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Home My WebLink About2007/03/26 Item 1 CITY COUNCIL AGENDA STATEMENT ~\!f:... C1lYOF :~CHULA VISTA March 26, 2007 Item~ ITEM TITLE: PRESENTATION AND SUB COMMITTEE REGARDING THE SOUTH BAY POWER DECOMMISSIONING AND DISMANTLING REPORT PLANT SUBMITTED BY: Michael T. Meacham, Director of Conservation & Environmental Servi/ CITY MANAGER 'rJI REVIEWED BY: 4/5THS VOTE: YES NO X BACKGROUND The purpose of the City Council meeting is to provide the City Council and public with additional information regarding the regulatory process associated with decommissioning and dismantling the existing South Bay Power Plant. The meeting will afford an opportunity to hear directly from stakeholders, that did not present at the January 18, 2007 workshop, regarding their recommendations and participation in the process for addressing resource adequacy and removing Reliability Must Run (RMR) from the existing South Bay Power Plant (SBPP). The meeting will also provide the Council Sub Committee with an opportunity to provide a progress report on their activities since the committee was established at the January 18,2007 workshop. ENVIRONMENTAL REVIEW Not applicable RECOMMENDATION Hear the presentations and provide direction to staff. BOARDS/COMMISSION RECOMMENDATION Not applicable. DECISION MAKER CONFLICT Staff has reviewed the property holdings of the City Council and has found no property holdings within 500 feet of the boundaries of the property which is the subject of this action. FISCAL IMP ACT There are no fiscal impacts, as staff is not recommending formal Council action at this time. .. .....1111.1111.... 111111"1-': rllT KPll<;:1n.o:> H...."'...........' If 'I IUL'\. (.1.I~_;~ (.~_~...L. City Council Meeting '4 pm Monday, March 26, 2007 Workshop Agenda Open the meeting: . Public Comment on Issues Not Before the Council . Open the Workshop and Introductions: o Port Commissioner Mike Najera, o Randa Coniglio, Real Estate Manager, Port of San Diego o Michael Meacham, Director of Conservation & Environmental Services Brief Historv and Background: Michael T, Meacham . Power Point and Brief Description of Current Infrastructure and History of Issues that Lead up to the Establishment of the Council Energy Sub Committee: . City Energy Strategy and Action Plan . Regional Energy Strategy and Infrastructure Study . 2001 Resolution . Bay front Master Plan Power Plant Subcommittee . Application for Certification by LS Power . Joint Port / City workshop 2/18/07 . Council Establishes Subcbmmittee to Address the Decommissioning Dismantling Issues . Council Recommendation to Port Regarding the Current and Proposed Future Power Plant on the Bay front, February 20, 2007 . Port Resolution March 6, 2007 (Randa Coniglio) Introductions and Comments bv Interveners and Interested Parties: . California Unions For Reliable Energy (CURE): Gloria Smith . Environmental Health Coalition: Paul Fenn, Robert Freehling, Laura Hunter, . SDG&E: Mike Niggli Council Sub Committee Report: Mavor Cox and Councilmember Castaneda Overview: . Sub Committee Meeting(s) Mayor and Councilmember Castaneda . Meeting with Port, LS Power, SDG&E and City: March 5, 2007 . Meetings with CPUC: (Mayor) March 7, and 16,2007 (Councilmember Castaneda) -~. Meeting with LS Power: March 19,2007 . Meeting with SDG&E, Potential Alternative Sites: March 19, 2007 (staff) ~.. Meeting with CAISO: March 20, 2007 Mavor Cox and Councilmember Castaneda Report on CPUC and CAISO Fact Finding Trips . Council Questions and Comments . Public Comment and Discussion . Council Direction for Sub Committee and Staff, and . Council Closing Comments SDG&E Maximum Hourly Load by Season 2005 5000 4000 -g 3000 CIS E <LI Q ~ 2000 - -- . ...... - -- - 1000 Jan-Mareh - Apri I-June July-September - Oct-Dee 0 ~ t ~ $ $ ~ (l o.~ t t o.~ o.~ "v:: B "v:: <:> B "v:: &' B <:> B B &' <::i P P <::i P ,j' ''Ii '1;>' "'" 'lJ' <S' ~' <Y' '1;>' "'" 'lJ' <S' " " Time of Day Source: Data from Cailfornia Energy Commission. Graph by Environmental Health Coalition 2007. SDG&E Maximum Hourly Load Spring and Summer 2005 5000 - -April-June 4000 July-September - .....~--, 'CI ; 3000 E CLI c I 2000 - --- ...... ~ ./ Intermediate Base Load .. .. ...... .. '" Base Load 1000 - 0 I .t ~ ~ ~ ~ .t G..~ G..~ G..~ G..~ G..~ G..~ &' <:> B B B &' &' B B B B &' " ,y '\I '!>-' 10' q,' ~' n;.' 'V' '!>-' 10' q,' ~' "- "- '" Time of Day Source: Data from Cailfornia Energy Commission, Graph by Environmental Health Coalition 2007, Different Technologies are Appropriate for Meeting Base Load, -_. -------- Intermediate Load, and Peak Energy Needs ----- ------ 5000 1000 - - - April-June - July-September 4000 " c 3000 Pumped (\:S E Storage Q,l Wind C ~ 2000 - ---- Natural Gas Baseload Power Plants I Fuel Cells 0 I ~ ? ? <:,? ? ~ i~ <l.~ # <l.~ <l.~ <l.~ &' B B B &' &' <:, B B <:, &' 5:> 5:> 5:> <V 'V '9-' IQ' <0' <:'.' ,ji 'V '9-' IQ' <0' <:'.' ... >.; " Time of Day Source: Data from Cailfornia Energy Commission. Graph by Environmental Health Coalition 2007. Energy Technology Diversification Provided by the Green Energy Options 700 600 500 >. ... 'u '" Co '" 400 CJ III ::: '" ~ '" Cl 300 CIl ~ 200 100 ------v Green Energy Portfolios o Proposed South Bay Natural Gas Replacement Plant "--- At 630 MW At 490 MW Source: Local Power Green Energy Options to Replace the South Bay Power Plant February 2007. Graph by Environmental Health Coalition Feb 2007 Peak Demand Reduction Solar PV Solar Thermal wI NG Backup . Hydroelectrical Pumped Storage ftltWind . Natural Gas -, I I i At 350 MW ~ E (+l., ~ ~&r)'vwvy<j(,v+L~l~r In' ,I :!l,'r)., (;'lJfY~ l ... j\" "I,' ~;i j v' " . ".,J' f',~ , r; x .. (, SuYV'\ IN' e:A v- ~ Th-fPV\-hu ~ ~ t~~ v-:. r;.~ l:N';e- :.;.:1. ~ f)?;~V\ C, \ $( If> f?l-edv \ ('l1 ~ ~OlNC'e.- plC{J\ f x~.-p1 , Stc~N cb'tL2. ~\)v ( t ,,\ .loo'1' OVIL VlLfSJiM ~,(.'UA..e.. US I'JA\,i\'l loUr'l s.o\o. r '\)YU\~u!S. o _~_~~~_.*_~_~",,,.._~_~..__.~.~~,,,._..___,,__._.~c,_,,."~..._",._._.~~___~.,_.~~,____~__,._~."._._n___.~~."~.~.~.,~,_"..,,,~~._"__."._..~._,~,,~"__,.",,,,_...~._.__~,,__,,. Information we needed regarding what is the minimum number of MW required to remove RMR and agreement mechanism. j-o What is the minimum # ofMW required to remove RMR o What the effect be of OMGS and other planned projects? o What is the required timeline in which this must occur o What agreement mechanisms can be used o Where do we really need the energy and what kind and size is best for reliability. o Do they support the in-basin and local control committed to in our local energy plans? o What is RMR costing rate-payers? o What can be done to make the G-1 and N -1 more realistic? Recommendations for Next Steps /1 II Seek determination from ISO and CPUC regarding what is the minimum number of megawatts required to remove RMR. ~~1J-uJV G. ~-() ~~ ~y ") II Disclosure of impact of planned projects on RMR . 1/ . Develop criteria, technologies, and potential sites for replacement power that could yield community support . Governmental agencies and other stakeholders identify and commit to local and state early actions to minimize the need for the SBPP and determine MW of replacement energy or reduction of future needs each action would provide. . Coalesce willing partners and develop timeline and list of responsibilities for implementation. ~_~._.~"" __,,_.<, ~'_'_' ....__..~.._____..__._%__ ~.____._ W"_' ."."_..._.-...,,___~~___~'~"'""______"_W.h"~_" -, - .," ~-_.,._".,.._~ : What will the effect be of the addition of. . . . 561 MW Otay Mesa Generating Station . 200 MW AMI meters by 2011 . 180 MW California Solar Initiative by 2017 II RFO responses -----~-,-~.._--._-~. _._.-,_.~~----~~~--_.~~.,._->.;,,-"._-~_.".,._- . I I , I I I I I I l . . i Q) i t I I ......, i " \ , ...., ! ,..q~ I I i'""O ; I i Q) Q) q Q) ~ I I 0 1'""0 i~ I ~ I Q) I q I Q) 4-l o '""0 q ~ .-.. ~ CO Q) c.. ~ o - --- l~ I~ l_,,_~_ Q) '+-' CO ~ "'C .- CO CO "'C Q) o Q) a.. - E Q) s..... ..c en Q) 0) CO '+-' .- alEI . . . - .-...~~....~..." ..... .'^..~..".__._~--_. ......_.~_._--_.~,.~~._~-,.~,-.._.,,~-'--.~._..~~ ,-_._~_.,.~..--,- _',_"",_,_-"-'_.~'-'-""-"---'~"'- Develop criteria, technologies, and potential sites for replacement power that could yield community support and participation. . Project must avoid air pollution impacts to sensitive populations, residences, schools . Project should include significant (e.g. 25-500/0) RE or EE component over project life. II Project should fund some appropriate transmission efficiency element if applicable. II If project has air emissions, proponents should agree to upgrade to newest emissions technology within a realistic timeframe (keeps project current) II A successful project will include multiple technologies and probably multiple sites. ~ ~~.-~---~-~~,.=----~>~-,--"._~~-"._-~~~-<,.~----~~"--~ ____.."....____~___....._~.."..~O'_.;....,'_.."."..__.+..._.~...~.," .~~~---_.~-,-~-----~---~->_..~--~~-~=~---~~,~..~..._,,.,------~-'~'~-~-.'-^'--"~~. Sample Projects (existing and proposed) using various technologies II Natural Gas o Los Esteros 320 MW Combined Cycle o Woodland Modesto 80 MW Combined Cycle II Solar o Solar Thermal- Victorville 2 proposed 500 mw o Solar Tracking Peakers (1.7 to 4.5 MW) o Alvarado Water District type Solar installation (1 MW) o Aggregate residential Solar PV in Chula Vista . Pumped Storage o Lakes Hodges Pumped Storage _'_--'~,_.~...~"'-._.' ----,.,--" ".~".~."-._-',-,~ .,.._..,,"..~._,_.....~.. ~.. . _.---~--~ ....".""-.-..--.,.-., -"-~--~--~--- ",""." --~,-'~...--'-"'~-' _..._.~~_.. .--".--'..-'". ,,-. .... ...-~-._---~-'_._,_...'.'- ..,--~". , Decentralized Options . Demand Response examples o ICE energy o TOU meters . Distributed Generation examples o Sheraton Hotel and Marine 1 MW Fuel Cell o Rooftop, parking lot PV II NASNI II Kearny Mesa ~~,.--~~---~-- ~.~-"-,-~---,,,,--",-_._---,-,,,--,'-'-"-_.'~~"'-"'''~'',-_._~--~.~'."---,-.-~ Navy Solar Projects: NASNI .. PV system electricity is fed direcdy into the power grid and provides 400 covered parking spaces. .. NASNI's PV system will reduce 884,736 pounds of carbon dioxide emissions, and 288 pounds nitrogen oxide emissions. 750kW system. .. Provides 3% ofNASNI peak demand and 1 % of power consumption. .. NAB as 30kW project ~=...,~._____~,_,~~~.,_~~.~...___..~~__~~.".______ ..'~"'"'~'__'_~" ,____"'_~^~....~ .__".._"...,'__.'-~ H'____'-.>~,~..-../.._"._.~~".__"=._____~.~.._....~_~. ."...,_.>_.~-"....." ^-'"-,~,,-+._-,,'-"- ~'''''--''-- .. -" ,~~~-".^<,"'-"----'---~'-' , Navy Newsstand: Major Milestone Reached Using Solar Power 10/3/200612:32:00 PM . CORONADO, Calif. (NNS) -- Naval Base Coronado's energy conservation efforts reached a major milestone Sept. 29 when the Solar Photovoltaic (PV) Carport registered more than 5 million kilowatt-hours (KWh) produced. When the PV Carport powered up in October 2002, it was projected to produce about 1,244,000 KWh annually. According to Naval Base Coronado Public Affairs, the system has performed better than projected, with annual savings exceeding $228,000, and more than $912,000 since inception. ,_"_,~_._",_,,,~,~,,~,_~_,,_"_~~~____~"_~'~__'"'~'''~_,_____,______~'w'''"'__~'__'_'_~ __ ----~..,..._~"~',....."..__." -~~~._--~~_==~'_~'__""~"="~__..._~~.___~~~T_~~.'_'____'~_...~~~..~~___.,~~ _.'o,~~,____,__"""~'."'e'<""_'.,_~__",__,__"__," Solar and landfill project in AZ II The third power generating plant in the Energy Park, a 500 kW solar energy system also located at the Pennsauken Sanitary Landfill, will provide power to run the 2,800 kW landfill gas-to-energy power generator at the landfill, which in turn provides energy back to the Aluminum Shapes facility. A total of 2,500 Kyocera KC200 modules were used to create the 500 kW solar energy system with an estimated annual energy production of 600,000 kWh. --_._~-.,----_.._-, If en ~ ~ ~ ~ ~ Q) ~ o ~ gf :.g u ~ ~ ~ ~ o C/) ~ q Q) ~ 3 . .~ , I j I ~ I I I rJ) I I , 0..) I I ~ I I I ~ I I I i 0..) I j q ~ , ~ 0..) "' '.." ~ ~2 ~ I I 0..) I > I 0 U 4-l 0 ~ ao ~ ~ ~ ~ .__.~._-~-- ""__,__,__"_",,,~,w,,,".,,,,____.__,~,,,_.-~,_,"",-''''~'''_"'~" _h__^_"" ."..__.~.__.,..~".,>,____.__.._,",,__~_~~_.~....4'" _;._..~_.,._____",._.___.~ -.- "".-.- ..._~.".."..- ~'._""-~" .".." Pursue Local and State Actions . Upgrade Renewable Energy and Energy Efficiency Standards for new and existing construction. . Explore Use of Chula Vista Solar Utility Districts: Determine the potential use of the SUD to offset need for SBPP. II Plan for implementing Chula Vista General Plan energy goals. . Develop a plan for fmancing and deployment for using existing rooftops and parking lots for solar power plants. II Develop specific or regional funding mechanisms for energy development if necessary. II Get AB32 Early Actions to address and facilitate these state regulatory improvements Who will decide South Bay's Energy Future? We urge the City to join with other stakeholders to convene a unified effort to remove the RMR from SBPP and chart a cleaner energy future for South Bay. .. Local Officials .. State Officials .. Federal Officials .. Public members .. Community Groups .. Business Interests .. Tribes .. Academia .. Water Districts Potential for Renewable Energy in the San Diego Region August 2005 Executive Summary For Full Report http://www.renewablesg.org/ Potential for Renewabie Energy in the San Diego Region August 2005 Chapter 1: Executive Summary The results of a collaborative, 18-month study by a group of local energy experts confirm that there is significant technical potential in the Region for development of several types of renewable energy sources. This conclusion is supported by a rigorous technical examination of data and can be the foundation of the Region's renewable energy policy and implementation strategies. The participants and methodology of this study are discussed in the Preface. Although the actual amount and pace of development of renewable energy resources will be determined by factors such as cost, incentives, regulatory policy, economics, and individual customer decisions, the message of this report is clear. Technical potential exists to serve a substantial amount of the Region's capacity and energy needs with renewable power. The approximate locations for major renewable resources in the Region are illustrated in Figure 1.1. Te,.hnical potential exists to serve a substantial amount of the Region's capacity and energy needs with renewable power. @ 2005 San Diego Regional Renewable Energy Study Group. All Rights Reserved. Page 1 of6 Potential for Renewable Energy in the San Diego Region August 2005 Figure 1.1: Approximate Locations for Major Renewable Resources in the Region Biomass Commercial and Residential PV Sma" Hydro Dispersed throughout SO County Dispersed throughout County Dispersed throughout SO Region Potential Renewable Energy . Wind Resources . WIND, GEOTHERMAL and CONCENTRATING SOLAR POWER POTENTIAL RENEWABLE ENERGY SOURCES ~ Geothermal Resources Solar Resources - CSP Concentrating Solar Power . Hydro Resources @ 2005 San Diego Regional Renewable Energy Study Group. All Rights Reserved. Page 20(6 Potential for Renewable Energy in the San Diego Region August 2005 Table 1.1 summarizes renewable resources that are deployed in the Region in 2005. Table 1.2 summarizes the technical potential for renewable resources in 2020. That table includes both existing and developable resources. As a point of reference, the system peak demand for 2004 was 4,065 MW, and total energy requirements in the Region were 20,578 GWh. These figures include customers served by SDG&E, as well as other energy providers. The Study Group used a multi-step process to determine a resource's technical potential, beginning with an estimate of the gross, or maximum, amount of a given resource available to the Region. For example, the amount of solar energy falling on the Region was determined using solar insolation data obtained from the California Department of Water Resource's California Irrigation Management Information System (CIMIS), and the amount of wind energy potentially available for harvest was based on data from the California Energy Commission. The next step involved applying a series of "screens" or filters to the available data to derive the technical potential for renewable energy in the Region. These refinements represent a significant advance in the state of analysis and knowledge for our Region and are described in detail in each chapter. As examples, a summary of the approaches for solar and wind resources is presented below. To determine the technical potential for residential solar electric, estimates of solar insolation were screened through data and forecasts of available single and multi-family dwelling units from the San Diego Association of Government's (SANDAG) database, estimates of available residential rooftop area per dwelling, average roof size, amount of roof available for a photovoltaic installation, roof orientation, shading, and pitch. Technical potential for commercial solar was determined through a GIS-based study that used satellite images to digitize all large buildings (roof area over 3,000 square feet), including industrial, commercial, educational, hospital, and hotel spaces in the City of San Diego. These rooftops were then analyzed to provide estimates of their likely available roof space for photovoltaic equipment. Estimates of average output per square foot were then applied to derive technical potential. Figures for the remainder of San Diego County were derived by calculating the ratio of total useable roof area in the City of San Diego to its total usable land (roughly 12 percent), and the applying that ratio (rounded down to 10 percent for simplicity) to the total usable land in the County outside of the City of San Diego. Solar technical potential for both residential and commercial sectors was further refined by deriving its on-peak capacity using hourly energy output shapes from existing solar installations in the Region. Along with the solar contribution to overall energy production, this on-peak component adds value to the Region's electric infrastructure at times of peak system demand. @ 2005 San Diego Regional Renewable Energy Study Group. All Rights Reserved. Page 3 016 Potential for Renewable Energy in the San Diego Region August 2005 -'_.,."_._---~.~~._-~~,.,.._-----_._-.-.~...- ._^-------_.._,._--_._.__....-._--~---~--._~-_.. ,.<._..,.._.~-_._^-_._- Table 1.1: Renewable Resources Deployed in the Region in 2005 SOLAR PV - Commercial and SOLAR - Concentrating Solar Power (CSP) WIND Residential CaDacitv tMW Eneray CaDacity tMW ACl tGWhl ACl Eneray IGWhl CaDacitv IMWl Eneray IGWhl SO County 12.6 27.3 SO County 0 0 SO County & Parts of Imperial County and Northern Baja California, Mexico Imperial 0 0 0 0 County BIOMASS (SO County) SMALL HYDRO GEOTHERMAL ~ CaDacitv IMWl IGWhl CaDacity IMWl Eneray IGWhl CaDacitv IMWl Eneray IGWhl Landfill 18 126 SO County 8.32 15 Imperial 537 4,700 Gas County Other Imperial Northem 0 0 86.5 152 Baja CA, 720 5,000 Biomass County Mexico @ 2005 San Diego Regional Renewable Energy StUdy Group. All Rights Reserved. Page 4 of6 Potential for Renewable Energy in the San Diego Region August 2005 Table 1.2: Region's Renewable Energy Technical Potential in 2020 SOLAR PV . Commercial and SOLAR - Concentrating Solar Power WIND Residential ICSPI Capacity IMW Eneray Capacity IMW ACI IGWhl ACI Eneray IGWhl Capacity IMWl Eneray IGWhl SO County 4,691 10,224 SO County 2,900 5,080 SO County & Parts of Imperial County and Northern Baja California, Mexico Imperial 29,000 50,808 1,650 - 1,830 4,530 - 5,020 County BIOMASS (SO County) SMALL HYDRO GEOTHERMAL Eneray Capacity IMWI IGWhl Capacity IMWI Eneray IGWhl Capacity IMWl Eneray IGWhl SO County 8.32 15 Landfill 72 505 86.5 152 Imperial 2,500 22,000 Gas Imperial County County Other Northern Northern Biomass 75 525 Baja CA, 75 131 Baja CA, 840 6,000 Mexico Mexico @ 2005 San Diego Regional Renewable Energy Study Group. All Rights Reserved. Page 5 of 6 Potential for Renewable Energy in the San Diego Region August 2005 Concentrating Solar Power (CSP) was estimated by the National Renewable Energy Laboratory (a major contributor to the Study Group) using data and information available from national sources as well as specific performance from the nearby CSP units I serving Southern California Edison. Filters were applied to derive technical potential from the overall available solar insolation in the Borrego Springs and Imperial County regions. These include estimates ofland availability, ownership, current use, and slope, as well as prevailing state and federal incentives. Technical potential for wind was determined through a two-step process. First, GIS information was used to identifY all sites with wind speeds of Class 4 or higher that are not located in national parks and monuments, state parks and recreation areas, on Bureau of Land Management Wilderness or Wilderness Study Areas, on bodies of water, on grades steeper than 14 percent, in urban areas or other hard to access areas such as mountaintops. Analysis of the technical potential for the remaining high-promise areas was conducted using a state-of-the art analytical methodology developed for this study. This model takes into account wind speed frequency distribution, direction, terrain roughness, availability factors, wind turbine hub diameter, rotor diameter, and power curves using a representative turbine selected to optimize annual energy output rather than peak power output or capacity factor. Other variables accounted for include aerodynamic turbulence, rotor diameters, and losses due to the Park Effect. 2 As with solar resources, data were developed showing the seasonable and hourly availability of wind resources to enable consideration of wind's fit with the Region's overall and on-peak capacity and energy requirement. This report provides a starting point for the next logical steps in renewable energy development for the San Diego region, inclUding policy formulation and implementation. The large-scale renewable technologies (in particular concentrating solar, wind, and geothermal) will require adequate transmission infrastructure to bring their benefits to all customers on the grid. While ability to deliver resources to load is a key driver of the technology's ultimate development, the Study Group did not use transmission availability as a constraint in its assessments of technical potential. Decisions regarding transmission and many other key drivers are part ofthe next step: bringing these technologies to market. The Study Group believes that this report provides a starting point for the next logical steps in renewable energy development for the San Diego region, including policy formulation and implementation. The Study Group looks forward to a thorough discussion of the current report, possible refinements, expansion of the report as new perspectives and information emerge, and completion of work for the remaining study/resource areas. ] These units are located at Kramer Junction, CA. 2 The Park Effect creates losses or decreases in electrical production due to aerodynamic turbulence created by the wake of the rotors in a wind fann with multiple wind turbines. @2005 San Diego Regional Renewable Energy StUdy Group. All Rights Reserved. Page 6 of 6 The Electricity Resource Plan Choosing San Francisco's Energy Future San Francisco Public Utilities Commission San Francisco Department of Environment August i002 Table of Contents Executive Summary.... ...... ..... ................................. ... .... ........ ...... ........ ........ 3 Introduction .... ... .... ........ ............ ......... .... ........ ... .......... ......... ............. .... ...... 10 Chapter 1: Setting Goals .............................................................................12 Chapter 2: Structure ofthe Electricity System .......................................... 20 Chapter 3: Electricity Supply and Demand in San Francisco.................... 29 Chapter 4: Challenges and Choices............................................................. 40 Chapter 5: Action Plan ................................................................................48 Chapter 6: Findings and Recommendations .............................................. 62 Appendices Appendix A: City Ordinance: Human Health and Environmental Protections for New Electric Generation, SF Board of Supervisors, 200 I Appendix B: Glossary Background Documents (available as separate documents on SFE website, sfenvironment.com) Energy Policy Element of San Francisco's General Plan, SF Planning Department, 1982 Sustainability Plan, 1997 San Francisco Peninsula Long-term Electric Transmission Planning Technical Study, 2000 Public Comments 2 Executive Summary California's experiment with electricity deregulation and the energy crisis it spawned exposed the vulnerabilities of San Francisco's electrical supply and highlighted environmental justice issues associated with the location of fossil fuel generation. The City's power is supplied by two old and polluting power plants at Hunters Point and at the base of Potrero Hill and through overhead and underground transmission lines along a single pathway in San Mateo County. For years communities in the Southeast, where there is a high level of respiratory disease, have been calling for the shutdown of the Hunters Point plant. In 1998 PG&E and the Mayor signed an agreement to close the plant as soon as replacement power was available to assure reliability. In 1999, as part of the deregulation process, PG&E sold its power plant at Potrero to an out-of-state merchant energy company. Mirant, the new owner, decided to expand the facility by adding a new power plant more than twice the size of the existing plant. That proposal has met with strong community resistance and raised further alarm about environmental justice in neighborhoods bordering fossil fuel plants. The City's Board of Supervisors responded to this situation by unanimously passing the "Human Health and Environmental Protections for New Electric Generation" ordinance in May 20011. The ordinance directs the San Francisco Public Utilities Commission (SFPUC) and the Department of the Environment (SFE) to prepare an energy resource plan that considers all practical transmission, conservation, efficiency and renewable alternatives to fossil fuel electricity generation in the City and County of San Francisco. This plan presents a framework for assuring reliable, affordable, and sustainable sources of electricity for current and future generations with the following notable milestones: a) By 2005 the City will enable the closure of the oldest of San Francisco's fossil fuel plants at Hunters Point and the reduced operation of the second oldest one at Potrero. This will be accomplished by developing sufficient replacement power through a combination of peak load reduction, energy efficiency, renewable energy, and new clean technology generation. b) Following 2005 the large Potrero power plant can be shutdown with the development of transmission projects already being planned or the construction of additional renewable or clean energy technology in the City. This plan assumes there will be no need for the construction of a large central generation plant in San Francisco. c) Beginning with the closure of the Hunters Point power plant and throughout the planning horizon of this plan greenhouse gases will be reduced. The operationally flexible natural gas-fired power facilities proposed in this plan will allow for continued displacement of the use of natural gas by increased energy efficiency and renewable 1 Text of the ordinance appears in Appendix A. 3 - energy technologies with a long term goal of having zero greenhouse gas emissions and minimal environmental impacts from the generation of electricity. If these milestones are met, San Francisco will have reduced its in-City fossil fuel capacity as well as its air pollution emissions. Figure ES I shows that the net decrease in fossil fuel use results in a 73% drop in in-City NOx levels by 2005. In City NOx Emissions (tons/year) 700 600 500 .. 400 '" '" .?:o .. c 300 ,g 200 100 0 Figure ESt 2002 2005 Goals During a series of public hearings, the following goals were identified to set priorities for this plan: Maximize Energy Efficiency Develop Renewable Power Assure Reliable Power Support Affordable Electric Bills Reduce Air Pollution and Prevent Other Environmental Impacts Support Environmental Justice Develop the Local Economy Increase Local Control Over Energy Resources Key Issues San Francisco is a constrained transmission area because of its location at the tip of a peninsula. During periods of peak demand, the City can import over existing transmission lines only about 60 percent of the power needed to meet its needs. Therefore, the California Independent Systems Operator (ISO) requires that power plants located in the city be operated to satisfY maintain grid reliability. The existing power plants are now past normal operating life, inefficient, prone to failure, and many times more polluting than new power plants. The Hunters Point and Potrero communities consist of a high proportion of lower- income, predominantly non-white residents. Residents of these communities share a common concern for public health, especially that of children and the elderly, who are hospitalized for asthma and other diseases at higher rates than reported statewide. Air pollution is a contributing factor to these health problems. The Hunters Point and Potrero power plants, along with vehicles and industrial facilities, are sources of air pollution. Potrero Unit 3 and Hunters Point Unit 4 are subject to significant NOx emission limitations beginning in 2005. The Potrero Unit is subject to a NOx emissions "bubble" that applies to multiple boilers owned by Mirant in the greater Bay Area. Air regulations require that power plant owners operate their fleet of boilers to meet an average NOx output. Mirant is currently evaluating alternative strategies for meeting these air regulations. One possible approach includes scheduling an extended outage of Potrero Unit 3 in 2004 to allow for pollution control retrofits. Given the current set of power resources available, such an outage would make the city more dependent on the Hunters Point Unit 4 and four diesel-fueled peaking power plants for reliability in 2004. The peaking plants are limited to 877 hours of operation because of their high level of pollution. PG&E has indicated a strong desire to avoid having to invest in emission reduction retrofits at its 44-year-old plant at Hunters Point. PG&E has assumed they couId operate Hunters Point into 2005 and beyond using emission reduction credits for NOx. If that is 5 the case, the number of hours the plant could operate would be limited. Given these circumstances it is extraordinarily important that the City develop a flexible short-term plan that permits the closure of the Hunters Point Unit 4 plant by 2005. Both the proposed Mirant power plant (Unit 7) and a proposed PG&E transmission line on the peninsula (Jefferson to Martin) could provide sufficient additional load serving capacity to allow for the closure of Hunters Point. However, there is significant uncertainty as to when either resource could be available, but it is defrnite that neither will be available by 2005. Therefore, the City needs to develop sufficient credible generation and load reduction alternatives that can be implemented by 2005. Complicating San Francisco's vulnerable power situation is the state of flux California fmds itself in as a result of its failed electricity restructuring scheme. Responsibility for planning for future electricity needs has been diffused through myriad state and federal agencies and the private sector. Consequently, the development of new electricity resources including generation, transmission and load reduction are not being considered in a comprehensive fashion. Sources of Power (MW) 2000 1800 1600 1400 1200 PG&E Peak Load Forecast 1000 [] Import Capacity . Distributed Generation . Solar . New Combustion Turbines t:I Energy Efficiency l::I New Cogeneration . Potrero . Hunters Point 800 600 400 200 o 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Figure ES.2 Years Figure ES2. The graph above shows the projected resource mix for San Francisco, following the recommended electricity resource portfolio described in this plan. 6 Recommendations to Support an Action Plan Based on months of research, independent analysis, and public input, the SFPUC and SFE are recommending a strategy to shut down the Hunters Point power plant and Potrero Unit 3 and to set the City on a sustainable course that shows a progressive decline in dependence on fossil fuels. In order to meet the City's electric reliability requirements, implementation of the plan should begin immediately. The main components of the plan include: I. A Clean, Reliable Electricity Portfolio Demand Reduction throul!h enerl!Y efficiencv and load manal!ement. This is generally a cost effective means of reducing electricity load. The objectives are: 16 MW by 2004; 55 MW by 2008; 107 MW by 2012. In San Francisco, demand reduction needs to be accomplished citywide. Since commercial users make a substantial contribution to peak demand they need to be targeted for peak reductions, with downtown buildings apriority. The California Independent System Operator (ISO) gives priority to meeting the downtown network load in the event of a multiple transmission failures while allowing other areas to be blacked out on a controlled basis; therefore, every megawatt reduction in the downtown network makes in-city generation available to other areas in San Francisco and lessens the likelihood of blackouts. City-owned facilities will likewise be targeted for load reduction and will be managed by SFPUC. The Department of Environment oversees several efficiency programs for the private sector. These programs will have to be augmented to include incentives, changes in codes and standards, outreach, and training to achieve the goals of the plan. Renewables. Programs to harness the sun, wind, water, and other natural sources will be a high priority. The objective for renewables are: 7 MW by 2004; 28 MW by 2008; 50 MW by 2012. Solar power is an excellent distributed resource because of its modularity. It can be sized all the way from multi-megawatt systems down to hundreds of watts on residential roofs. The SFPUC will soon begin the City's first large solar power development at the Moscone Center. This football-field sized showpiece will produce about 688 kilowatts. A second 600-kilowatt solar site is planned for the Southeast wastewater treatment plant. Other proposed municipal sites include the airport and the port. SFE will undertake an aggressive program to identify and develop sites in the private sector. There are wind technologies appropriate for urban applications, though the most significant amounts of wind power are outside the City in areas such as the Altamont Pass, where wind speeds and proximity to transmission can be met. Hetch Hetchy can build wind turbines at Altamont and at sites along its transmission right-of-ways. 7 Tidal current and wave generation are in a pre-commercial development stage. The theoretical potential for these resources in the Bay Area are in the hundreds of megawatts of power. The City should seek partnerships with the federal and state governments in exploring the potential of these resources and take the lead in providing the opportunity for demonstration sites. Medium-sized Generation and Cogeneration. Mid-size plants of about 50 megawatts can provide high levels of reliability and could be built in several locations in San Francisco. The amounts assumed to be needed to help shut down Hunters Point and Potrero Unit 3 are: 150 MW by 2004; 250 MW by 2008. These plants will be the most efficient gas fired generators available and will be used as replacement generation for the old, polluting plants in the City. The quantity of new natural gas-fired generation should be based on a publicly-reviewed reliability analysis. Whenever investment in demand-side management and sustainable resources can offset new fossil fuel development, this will be the City's preferred course. Cogeneration is the production and use of electricity and heat from a single installation. It is favored because the total efficiency goes up when the heat created from combustion is captured and used. One site currently under consideration is a 50 megawatt cogeneration plant at 5th and Jessie Streets in the City. This installation would produce steam to feed into the existing district heating system, with the electricity being produced as a by- product of the production of steam. Another potential site for a cogeneration system is the Mission Bay campus of the University of California, San Francisco where the potential for district heating is substantial. Small-scale Distributed Generation (OG). These include fuel cells, packaged co- generation, and micro-turbines. DG generators range from 10 kilowatt to 5 megawatts in size and usually support single facilities. The objectives are: 10 MW by 2004; 38 MW by 2008; 72 MW by 2012. The SFPUC will identify sites for municipal applications and the SFE will work with downtown building owners and other businesses to find appropriate sites and to facilitate installation. The effective deployment of distributed generation will require the cooperation of PG&E for interconnection to the grid, and the assistance of City departments in streamlining permitting. Transmission. An upgrade to an existing line and a new transmission line scheduled to be built on the Peninsula to service San Francisco will be necessary for long term reliability, and should be supported by the City. At the same time the City should commit to securing a continually increasing percentage ofrenewable sources to feed the transmission grid. 8 II. Environmental Justice SFE will take responsibility for seeing that communities in the Southeast will benefit from the programs developed through this plan. Air quality will be more effectively monitored as a measure of the success of the plan. The department will also monitor and periodically report on bills for low-income residents and the dispersion of energy program benefits, including training, employment, and business development. III. Implementation and Review Implementation of the Plan needs to begin immediately to accomplish the 2004-5 objectives. Relevant activities have already been initiated and can be expanded as funding is available. Implementation will require strong continued participation by the public and support from City officials. SFE and SFPUC will work with each sector of the San Francisco economy to promote efficiency, renewable energy and distributed technology into their facilities. Specific objectives and timelines for their achievement will be developed later. The Plan will be evaluated and updated to reflect new developments and SFE and SFPUC will submit an annual report to the Board of Supervisors on achievements and challenges of the energy program. 9 5 Action Plan San Francisco will need new electricity resources over the next decade to meet growth in demand for electric services, to shut down the outdated Hunters Point Power Plant and to replace the aging power plants located at Potrero. The strategy for developing the necessary resources to rapidly modernize San Francisco's electric infrastructnre needs to take into account the longer-term objective of environmentally sustainable electricity for future generations. While the short-term solutions need to be cost-effective, they must also be consistent with the goals set forth in Chapter I as well as with the Mayor's goal for reduced greenhouse gas emissions. Therefore, taking into consideration the challenges identified in the previous chapter, the preferred course of action outlined here proposes solutions that immediately address the City's urgent needs while complementing and advancing the achievement of mid- and long-term objectives. Specific recommendations in the areas discussed follow in Chapter 6. Short Term Action Plan - 2002 through 2005 The City must take aggressive steps immediately to shutdown the Hunters Point Power Plant while assuring reliable electric service. In addition, the City should facilitate the early retirement ofPotrero Unit 3, to avoid costly upgrades and the extended operation of this outdated plant. This could lead to forced outages in 2004, and then allow the plant to continue operation well into the future when cleaner, more reliable resources are available. Therefore, it is in the City's interest to develop a short-term action plan that would avoid the shutdown ofPotrero Unit 3 in 2004 and minimize San Francisco's dependence on its operation over the longer term. Our objectives are to maintain reliability through decreasing reliance on old, polluting technologies and increasing investments in energy efficiency and clean, efficient technologies. An action plan that could achieve these objectives would include: . Maximum investments in energy efficiency measures particularly peak reducing measures . Development of new highly efficient and operationally flexible generation at appropriate sites by the summer of 2004 to facilitate the closure of the Hunters Point Power Plant Unit 4 by the end of 2004. . Development of a plan between the City and Mirant to allow for the environmental dispatch of new generation owned by the City and Potrero Unit 3 to meet BAAQMD requirements under the SIP and ISO requirements for reliability. . Aggressive efforts to promote and facilitate installation of distributed generation using renewable technologies and clean natural gas-based technologies 48 Medium Term Action Plan - 2006 through 2012 The most important challenges facing the City in the medium term is to develop sufficient new resources to permanently close Potrero Umt 3 and to limit the operation of the diesel-fired peaking plants at Potrero to genuine emergencies. In addition, the City must take aggressive steps to meet its commitment to reduce greenhouse gases, which means commitments to fossil-fuel reduction both in the City and in the power sources feeding the transmission grid. The key components of a mid-term action plan include: . Completion of the Jefferson to Martin transmission line Accelerated development of solar electric generation in San Francisco with the objective of having 50 megawatts installed by 2012 Development of additional renewable energy, cost-effective co-generation, and clean distributed generation technologies in San Francisco Maximizing investments in energy efficiency and demand reduction with a goal of maintaimng peak demand at a level no higher than 909 megawatts (the average of 1996-2000) . Development of at least 150 megawatts of new wind or other renewable generation that can be imported into San Francisco . . . . The following graphs present the results of the short-term and medium-term action plan. Figure 5.1 shows the contribution that each resource makes towards meeting the projected peak demand for electricity in San Francisco from 2002 through 2012. The Chart shows 150 megawatts of new operationally flexible combustion turbines coming on line in 2004. In 2005 an additional 100 megawatts of import capability is assumed to be in place from the upgrade of the San Mateo to Martin power line number 4. The new combustion turbines and the upgraded power line allow for the retirement of the 163- megawatt Hunters Point Unit 4 and the down rating ofPotrero Unit 3 from 207 to 47 megawatts. This results in a net decrease of 109 megawatts of in-city fossil fuel generation in 2005 and a 73% reduction in annual NOx emissions. Two new 50-megawatt cogeneration power plants are developed in 2005 and 2006 that allow for the retirement of Potrero Umt 3 and the peaking ullit at Hunters Point in 2006. The peaking ullit may be retired earlier if the operational plan for Potrero Unit 3 permits it to run at a higher capacity than estimated. By 2012 energy efficiency, distributed generation and solar account for 210 megawatts of capacity. Figure 5.2 shows the amount of electricity produced or saved by each resource category. With the addition of the new combustion turbines and additional import capacity in 2005 the amount of generation from the Potrero and Hunters Point power plants is only 13 percent of their 2002 level of generation. The addition of efficient cogeneration plants in 2005 and 2006 eliminate all generation at Hunters Point and further reduce generation at Potrero. The expansion of energy efficiency measures, distributed generation and solar lessens the amount of power generated by the combustion turbines as well as the amount of imported power each year through 2012 49 Figure 5.1 1400 1200 1000 800 l:! ; . '" . '" 800 400 e 4000 , o :I: '" ; & 3000 c:;; Recommended San Francisco Electricity Resource Portfolio Sources of Power (MW) 200 Il:I Importecl Power . Distributed Generation . Solar . New Combustion Turbines 1:;1 Energy Efficiency a New Cogeneration .Potrero o 2002 200' 2007 2011 2012 2008 2009 2010 200' 2006 2003 Years Sources of Power (GWh) 7000 Figure 5.2 6000 5000 2000 D Imported Power . Distributed Generation 1000 . New Combustion Turbines Il Energy Efficiency II New Cogeneration Ii Potrero III Hunters Point o Imported Energy Figure 5.3 details the principal sources of imported power used to meet San Francisco's electricity needs. Wind generation is added in the following increments - 50 megawatts in 2004, 90 megawatts in 2006, 125 megawatts in 2008 and 150 megawatts in 2010. Assuming that renewable resources account for 12 percent of the purchased imports, renewable energy will account for almost 50 percent of imported power by 2012. Figure 5.3 5000 4500 4000 3500 ~ 3000 ~ 0 :%: = 2S00 ~ ~ 2000 C) 1S00 1000 SOO 0 2002 2003 2004 2005 Imported Power (GWh) 2D06 2007 Yoa, 2008 2009 2D10 2D11 2012 Emissions Figures 5.4 and 5.5 show the impact oflocal emissions of oxides of nitrogen (NOx) and particulate matter (pM I 0) of the recommended San Francisco Electricity Resource Portfoli06. A vast improvement in reduced emissions is achieved with the retirement of the Hunters Point and Potrero power plants in 2005 and 2006. Emissions begin to increase slightly after 2006 with the addition of cogeneration and distributed generation in the City, which displaces imported power. 6 Emission estimates for figures 5.4,5.5,5.6 und 5.7 by Rocky Mountain Institute, SFE und SFPUC staff based on data from BAAQMD, PG&E, Mirunt, CEC, EPA und California Air Resources Boord (CARB). 51 Total In-City NOx Emissions Figure 5.4 (tons/year) 700 600 "- 500 III CD ~ 400 0 Z II) l: 300 0 - 200 100 0 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Figure 5.S 70 60 50 ... .. ~ 40 Cl - ::E ll.. 30 '" c: 0 - 20 10 0 2002 2003 Total In-City PM10 Emissions (tons/year) 2004 2005 2006 2007 2008 2009 2010 2011 ~2 Figures 5.6 and 5.7 show the impact of the recommended SF Resource Portfolio on the emission of carbon dioxide(C02), the.most common of greenhouse gases. By 2012 carbon dioxide emissions are reduced by almost one-third below their 2003 level. A significant amount of the reduction comes the retirement of the Hunters Point and Potrero power plants. Additional reductions are achieved by the increased proportion of imported power coming from renewable sources of electricity, which has reached 20% by 2012. Reductions in C02 emissions are also gained through growth in energy efficiency. 53 Figure 5.6 Total In-City C02 Emissions (tons/year) 2,500,000 2,000,000 ~ 1,500,000 .. " .2:- N 0 <J WI c 1,000,000 0 - 500,000 o 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Figure 5.7 Sources of Carbon Dioxide (C02) Emissions 2,500,000 500,000 2,000,000 iu 1,500,000 ~ o <J WI c S 1,000,000 o 2002 2003 2004 2005 2006 2007 Years 2008 2009 2010 2011 2012 54 Long Term Action Plan. 2012 through 2030 The long-term challenge facing San Francisco in the energy sector is making electricity generation sustainable, by maximizing energy efficiency and the use of renewable energy. This means the City will need to increase annually the proportion of electricity being produced through renewable resources while managing both peak and overall consumption of electricity. Because many renewable energy resources are intermittent in nature, it will be important for San Francisco to develop cost-effective electricity storage technologies that will allow electricity to flow at times when the sun, wind, or tidal currents are not capturing energy. It will also be necessary to promote clean energy carriers such as hydrogen that can be used cost-effectively in energy conversion technologies like fuel cells, reciprocating engines and microturbines. Actions that need to be taken in this time frame include: . Phasing out fossil fuel sources of generation in the City Attracting private capital for the development of new renewable energy technologies Strengthening regulations and incentives to encourage the development of zero net energy buildings and investments in the upgrade of existing buildings Building the institutional and human capacity to support the longterm growth and development of sustainable energy in our economy. Supporting research in emerging renewable technologies such as wave energy, tidal/marine currents, ocean thermal energy conversion, salinity gradient/osmotic energy, and marine biomass fuels. Establishing regional partnerships for the development of renewable resources . . . . . Resources to Be Developed , In each program area, SFE and SFPUC will engage specific market sectors by meeting with stakeholders to develop more effective programs. Stakeholders will assist in defming the market barriers, selecting the best options to overcome the barriers, and doing outreach to potential program participants. Energy Efficiency Energy Efficiency is our most readily available, cost-effective, and underutilized resource. In a study7 recently commissioned by PG&E to determine the potential for energy savings in the commercial sector throughout its service area, it was shown that an estimated 13 percentS of the peak demand in the commercial sector could be reduced on a cost-effective basis. The study estimates that well-designed energy efficiency programs can cost effectively realize 80 percent of the electricity savings that is potentially available. The study estimates that PG&E achieved 46 percent of the maximum achievable savings for 7 Commercial Sector Energy Effic'iency Potential Study, Xenergy Inc" July 2002. s 13% reduction from peak is approximately 113 MW of the January 10,2001 peak. 55 lighting and air conditioning in 2000. Stronger and more focused programs have the potential to achieve larger savings in the future. In City facilities, SFPUC is continuing energy efficiency programs that include replacing old equipment with high efficiency equipment, educating City departmental staff; promoting the use of Energy Star-certified computers, lighting, and office equipment; and monitoring heating and air conditioning temperatures. It expects to reduce the peak by 4 megawatts by 2004. For new City facilities, SFE is recommending adoption of a new environmental standard that will require projects to exceed state standards. In the private sector, energy efficiency needs to be accomplished citywide and address both usage as well as peak load; however, the peak is of primary concern, particularly to address the 2004-5 period and to shut down the Hunters Point plant. Commercial and industrial users contribute more to the peak than is represented by the usage numbers because much of the residential use is during off-peak hours. In particular, downtown buildings are a priority. The ISO states that there must be sufficient in-city generation to meet the downtown network load in the event of a transmission failure; therefore, every megawatt reduction in the downtown network reduces the need for a megawatt of in-city generation. New construction is the largest source of expected growth in demand. Because energy efficiency in new construction is the cheapest available energy resource, this should be a very high priority program area. Peak load reductions will mean employing a range of specialized efficiency technologies, e.g. thermal energy storage. Both SFE and SFPUC have begun working with private sector developers by providing design and technical support to help them integrate sustainable and efficient features into the new complexes. Additionally, there are over 40,000 small businesses in San Francisco that also provide an opportunity for peak demand reductions even though they represent only 20% of the commercial energy use. Typically, they are tenants in older buildings, and cannot afford updating the building systems; therefore, the lighting, ventilation and refrigeration systems are older and less efficient than those in larger businesses. SFE is currently managing a $7.8 million retrofit program (funded by a grant from the CPUC) to install energy-efficient lighting in 4000 small businesses, with a goal of reducing peak demand by 6 megawatts.. Mid-Sized Natural Gas-Fueled Generation (Replaces Old Large and Mid-Sized Power Plants) Power plant efficiency has increased significantly with the application of aeroderivative combustion turbines. Jet engines that were developed for commercial aircraft have been used in power applications for over 20 years. These plants are more efficient9 than 9 Efficiency is measured as how much of the heat value contained within a fuel can be converted to electric energy. Convention boiler-steam turbine power plants have efficiencies around 30 percent. Combustion turbines have efficiencies around 35 percent and in a combined cycle mode have efficiencies around 50lpercent. In a cogeneration application 80 percent of the energy contained in the fuel can be converted to 56 conventional power plants and perform well with availability rateslO of around 98 percent. They are operationally flexible with short start up times and can be ramped up and down to meet power load on a daily basis. With water injection for control of oxides of nitrogen (NOx) and selective catalytic reduction (SCR) systems, they can achieve NOx emission rates that are at least five times less than is required by the SIP for the Clean Air Act. Combined cycle power plants that use the waste heat from a combustion turbine to produce steam have reached efficiencies exceeding SO percent and now operate producing less than two parts per million of NO x . The City is currently seeking to permit and construct a S7 megawatt combined cycle power plant at the San Francisco International Airport. This plant will improve grid reliability in the upper peninsula and provide a cost-effective source of electricity for the airport. It will also free up transmission capacity into San Francisco Highly efficient and operationally flexible combustion turbines powered by natural gas can be developed at various sites in San Francisco by 2004 if a consensus could be achieved as to appropriate sites. Mid-Sized Cogeneration (Replaces Old Large and Mid.Sized Power Plants) Cogeneration is the production and use of electricity and heat from a single installation. Starting in the late 1970's, cogeneration plants have been sited primarily at industrial sites and the power is used on site to reduce energy costs. One site currently under consideration is a SO-megawatt cogeneration plant at Sth and Jessie Streets in the City. This installation would produce steam to feed into a district heating system, with the electricity being produced as a by-product of the production of steam. The City currently has a steam franchise agreement with NRG Thermal Corporation that produces steam at the Sth and Jessie facilities. The new plant could produce 90 percent of the steam requirement and reduce air emissions by significant amounts compared to a new combined cycle power plant and the boilers necessary to provide the steam for the downtown heating system. A key issue in moving forward on the development of this facility is determining who would purchase the electrical output of this facility and how it would be distributed to retail consumers. useful energy usually in the form of steam and electricity. Efficiency is often measured as a heat rate. Heat rates are expressed in terms of the numbers ofBTUs of heat needed to produce a kilowatt hour of electricity. The heat rate for aeroderivative combustion turbines is around 10,000 BTUs. 10 Availability rate means the percentage ofthe time the plant runs when it is called upon to run. Capacity factor means amount of electricity a plant produces divided by its theoretical maximum production capability for a period of time. S7 Another potential site for a cogeneration system is the Mission Bay campus of the University of California, San Francisco. The University of California has experience with cogeneration plants at six of its campuses including a 43 megawatt facility at UCLA. That plant provides heat during the winter months and air conditioning through a central chilled water plant and a chilled water distribution loop. The potential for district heating at Mission Bay is substantial. However, the build-out of the site is a long-term process that creates problems in determining the appropriate size for a cogeneration plant. A larger plant would be more efficient and cost effective. However, sizing a plant larger than the electric requirements of the campus would require that there be a retail market for the surplus. Over the last 15 years, smaller cogeneration projects have been installed at hospitals, swimming pools, and other facilities that have needs for heating and cooling. The City is currently developing a five megawatt project at San Francisco General Hospital. The commercial market for this equipment continues to be viable; however, there is opportunity for the City to stimulate further investments through informational programs, direct technical assistance, permitting assistance, and low interest financing via Proposition H. Renewables Renewable energy options currently available to the City include solar, wind, biomass, and geothermal. Emerging renewable technologies like wave, tidal current and, ocean thermal energy may be available in the near future. Each of these resources has unique opportunities, advantages, and sometimes disadvantages. Solar Solar power is an excellent distributed resource because of its modularity. It can be sized all the way from multi-megawatt systems down to hundreds of watts on residential roofs. Typically, solar electric systems use photovoltaic material to generate electricity directly. Photovoltaic systems are well suited to commercial and institutional settings (schools, hospitals, libraries, government buildings). However, electricity production is limited to times when the solar resource is available. Clouds, fog and shading limit the amount of power that a system produces. Solar is, however, particularly valuable when used at the local level to reduce peak power usage, and to defer distribution infrastructure development. The City's first large solar power development will be at the Moscone Center. With approximately 90,000 square feet of perfectly flat unshaded roof, this football-field sized showpiece will significantly reduce Moscone's purchase of power and provide a solar showplace for visitors from all over the world. The SFPUC has installed radiometers at eleven sites on City buildings and schools to collect data about the availability of sunlight. The variability in solar incidence is based 58 on microclimate and geography, and when cross referenced with availability of appropriate space, limits the application of solar technologies in some areas of the City. To develop a well thought out strategy of implementation City needs to understand the resource and develop it where it is most cost effective. If sufficient participation by commercial and residential customers is obtained at least 50 megawatts of solar could be installed in San Francisco. Price of systems is a major consideration in achieving this magnitude of installation. A sustained program to develop solar in San Francisco can help, if done in an orderly manner, reduce the overall cost of solar technologies. Wind Wind has been used for centuries to create mechanical power for uses such as water pumping and the milling of grain. In recent years, wind turbines have been developed that produce electricity. The technology is now well developed, and can be used to generate significant amounts of relatively low-cost power. Modem wind turbines have increased in size and output to megawatt scale machines in recent years. San Francisco could obtain significant amounts of wind power in areas such as the Altamont Pass, where wind speeds are high enough, and where other conditions like proximity to transmission can be met. The SFPUC is currently looking at several sites including those adjacent to its own Bay Area reservoirs. They estimate potential for wind development in the greater Bay Area for San Francisco's use could exceed 150 megawatts. Electricity from these projects would require transport using PG&E's transmission lines. There may be additional opportunities for developing small-scale wind projects in the City itself. Biomass The combustion or gasification of wood, agricultural waste, and other forms of biomass offers options for San Francisco. The SFPUC is currently reviewing several potential biomass projects. Last year the SFPUC installed a small reciprocating engine to use biogas recovered from the Oceanside Water Treatment Control Plant. This year a 2 MW biogas plant will be operating at the Southeast Water Treatment Control Plant. Both of these plants use methane gas produced by the sewage that would otherwise be flared-off. Fuel Cells Fuel cells are a developing technology that is expensive and not yet readily available. Fuel cells do not bum fuel, they chemically convert it, much like a battery chemically stores electricity. Fuel cells need hydrogen and produce water and heat, though current models are use the hydrogen contained in natural gas or gasoline because those fuels are readily available. As this technology becomes mass produced, the cost will reduce, and it will be a popular option because there are essentially no air emissions. Marine Energy Surrounded on three sides by water, the technical potential of marine energy technologies is enormous. The energy of the ocean is stored partially as kinetic energy from the motion of waves and currents and partly as thermal energy from the sun. Although most 59 marine energy is very diffuse, in special situations it could be cost effectively captured for practical use. .Among the marine energy technologies that are currently being investigated are those that convert the energy in waves, tidal/marine currents, ocean thermal gradients, salinity gradients and marine biomass fuels. Tidal and marine current is one of the most serious of the marine energy resources to be studied. The technologies are in development with demonstration projects now being installed in Europe, Canada, and the U.S. The City will initiate partnerships with appropriate agencies to develop demonstration projects. Geothermal Geothermal energy has been used commercially for over 70 years both for electricity generation as well as direct use. A significant area of geothermal development has been the Geysers region in Northern California. More recently large scale geothermal development is taking plant around the Salton Sea in Southern California. Several geothermal developers have approached the city with competitive offers for power purchase agreements. A challenge for San Francisco in utilizing geothermal energy is arranging for cost-effective transmission into the city. Transmission Recently, the ISO made the finding that proposed Jefferson to Martin 230 Kv transmission lien is needed no later than 2005. The ISO also agreed to determine whether the shutdown of the Hunters Point Power Plant can be approved once the transmission line is complete. However, before the transmission line can be built, PG&E will need to obtain a certificate of convenience and necessity from the CPUc. As part of the certification the CPUC will have to evaluate the environmental impacts of the project under CEQA. The CPUC also has to determine whether the project is the most cost effective way of improving electric system reliability. If it makes that determination, then the cost of the project is placed into PG&E's ratebase and charged over time to all of PG&E's ratepayers, not just those in San Francisco. Relying on transmission means that the city may be importing power that creates pollution in other communities. In addition, if the City is to meet its Climate Change commitment it must reduce the proportion of imported power coming from fossil fuel sources. The city could own or contract for renewable resources from other regions such that the new transmission line would be "importing" green power. In fact, the energy will be coming from the mix on the grid; however, by owning or contracting for that power, the City will be supporting the development of renewable energy in the state. Finally, Peninsula loads reduce the amount of power that can be transmitted to San Francisco; therefore, an additional strategy to increase transmission into San Francisco is to encourage efficiency and new generation projects throughout the Peninsula. Given this linkage between the City's needs and the Peninsula cities, the City should initiate contact with those cities to explore how San Francisco might help stimulate a 60 larger effort towards efficiency and local generation projects on the Peninsula, e.g. via collective purchasing of distributed generation equipment to get better prices. Funding and Development Options The City is examining a variety of ways of becoming involved in the generation of renewable and distributed power. It is likely that a combination of these would be considered, including: . Full ownership, where the City would finance and own the facilities . Part ownership, where the City would take an equity position and partner with a developer . Build-own-operate-transfer arrangements, where a developer finances and operates the facility in return for a power purchase agreement and then transfers ownership of the facility to the City at the end of the power purchase agreement . Straight power purchase agreements, where the City signs an agreement to purchase power and the developer continues to own and operate the system. . Facilitating private activity through permitting, incentives and technical assistance. An important issue associated with the use of small-scale distributed generation involves the impact of multiple sources of generation on the operation of the power grid. The distribution system was designed to have a central plant with the power delivered through lines that decrease in voltage as they get further from the source. Distributing the generation onto this system may place generators such that they upset the balance of the system, cause power to backfeed through equipment not designed to operate in that manner. Since the grid was planned for large centralized plants, the control of the system tends to be top-down, whereas with many smaller sources interconnected throughout the system, the issue of control becomes more important. Understanding the impact of multiple sources on the flow of electricity, and implementing intelligent two-way controls are crucial to the success of distributed generation in the City. Therefore, distributed resources require that the City work with the utility to resolve the safety, interconnection, and environmental issues that have tended to dominate the distributed generation field in recent years. PG&E and the ISO have recently agreed to analyze several possible scenarios for planned and potential siting of distributed generation facilities. 61 6 Findings and Recommendations The San Francisco Public Utilities Commission (SFPUC) and the Department of the Environment (SFE) submit the following recommendations to support the implementation of an Electricity Resource Plan for San Francisco. In Ordinance 124-0 I, passed in May 200 I, the Board of Supervisors called for plans to implement all practical transmission, conservation, efficiency, and renewable alternatives to fossil fuel generation in San Francisco. The recommendations are based on findings determined after detailed research and evaluation of San Francisco's electric resources, nine public hearings, several energy forums, consultation with state energy policy makers about California's electricity market and regulatory structure, as well as information obtained from monitoring the progress of proposed projects affecting San Francisco's electricity supply, including the licensing of a new power plant at Potrero. I. A Clean, Reliable Electricity Portfolio A. FINDINGS San Francisco's electric reliability remains vulnerable. Regulatory requirements and limitations continue to pose significant challenges in maintaining adequate reliability while improving air quality and public health. The following have been found to contribute to this situation: 1. A.1 1.A.2 San Francisco relies heavily on two aging, inefficient, and polluting power plant at Hunters Point and Potrero. The State Implementation Plan for the federal Clean Air Act requires that the owners of these plants significantly reduce emissions of oxides of nitrogen (NOx), a precursor of ground level ozone (smog) by January 1,2005. Installing new pollution control technology on either of the plants would cost the owners and ratepayers tens of millions of dollars and could result in the extension of their operation for another ten to fifteen years. The installation of the pollution control equipment in 2004 would require the shutdown of the main generators at each plant for three to six months, creating a major reliability problem as well as increased pollution if diesel-fueled peaking power plants are called into operation. Analysis by the SFPUC and SFE demonstrate that retrofitting and continuing operation of both these old, large units would produce higher levels of pollution and health impacts than if they were replaced with new, 62 1.A.3 1.A.4 1.A.5 1. A. 6 1.A.7 cleaner technologies. Also, smaller-scale, distributed generation, including co-generation, can more easily be combined with renewables, energy efficiency, and peak load management to minimize the use of fossil fuel generation. The analysis further indicates that reliability would also be enhanced by distributed, mixed resources. The City and the residents of southeast San Francisco have made it clear that they want to shut down, rather than upgrade the Hunters Point plant. In order to close Hunters Point and to meet demand forecasts, there is a need for a projected 100-210 megawatts of in-City replacement generation and load reduction, or new transmission, by 2005. That need grows to 249-317 megawatts by 2012. Development of a proposed new 540 MW power plant at the Potrero Power Plant (Unit 7) has been delayed in the regulatory review process and is now looking doubtful due to investors' current lack of confidence in the electricity market. It is now certain that the plant will not be operational by 2005 in time to provide the replacement power needed for the shutdown of Hunters Point. San Francisco has transmission constraints that limit the amount of imported power. New transmission projects can increase the amount of power to be imported and limit the hours that in-City power plants need to operate. One project, the upgrade of the San Mateo to Martin line number 4 from 60 kV to 115 kV could be completed before the end of 2004. A new 230 kV transmission line from the Jefferson substation in San Mateo County to the Martin substation would provide another 350 MW of imported power to the City. The current schedule for completion of this transmission project is September 2005. However, it is possible that this project could be delayed. There is significant untapped potential for electricity load reduction through energy efficiency improvements and load management in existing buildings and new construction in both the public and private sectors. Energy efficiency investments reduce peak demand, thus avoiding the need to obtain the power from generating plants. Some projects have been identified and could be undertaken immediately. To be fully effective in addressing reliability in 2004-5, additional mechanisms for capturing this potential in a timely fashion would need to be developed. There is demonstrable public support and opportunities for the development of solar, wind, and other renewable resources in and near San Francisco. A portfolio of electricity resources that includes an increasing proportion of renewables together with higher levels of energy efficiency can significantly reduce emissions of carbon dioxide and air 63 1.A.8 pollutants, improve marine and wildlife habitats, lower noise levels, lessen visual impacts, and make a contribution to improved public health. Small-scale renewable projects stimulate local economic development to a greater degree than do large-scale generation and transmission approaches, which tend to send most dollars out of the City. Renewables, together with other small-scale distributed generation, such as packaged co-generation and fuel cells, are appropriate applications for many public or commercial facilities in the City. I. A Clean, Reliable Electricity Portfolio B. RECOMMENDATIONS The City should take on the responsibility of planning and developing new electricity demand reduction sources and the most environmentally friendly power generation for San Francisco. This would require that: 1. B. 1 1. B. 2 The City periodically review and set annual targets for increasing the efficiency of electricity use and the amount of electricity produced by renewable sources of energy so that ultimately all of San Francisco's electricity needs are met with zero greenhouse gas emissions and minimal impacts on the environment. The City identify and promote common criteria for investments in energy efficiency, renewable energy, and fossil fuel powered generation. SFE will develop an economic value for public health and environmental impacts to be incorporated into the investment criteria. Through coordination with the Independent System Operator, PG&E and others, the City needs to determine more precisely the quantity of new power resources necessary to shut down the Hunters Point Power Plant Unit 4 by 2005 and avoid the retrofit of Potrero Power Plant Unit 3. Based on this coordinated determination of need, the City should develop a mix of efficiency, renewables, small- and mid-scale sources of generation-- including co-generation facilities and gas-fired peaking power plants--and facilitate the construction of additional transmission capacity. Specifically, Energy Efficiency -16 MW by 2004; 55 MW by 2008; 107 MW by 2012 1. B. 3 The Department of the Environment should facilitate comprehensive energy efficiency implementation measures throughout the private sector, and the San Francisco Public Utilities Commission should aggressively implement energy efficiency projects in City facilities. 64 1. B. 4 1. B. 5 1. B. 6 1. B. 7 1. B. 8 1. B. 9 1. B.10 1. B. 11 SFE and SFPUC should perform an energy use study of San Francisco's conunercial and residential buildings. Results of this study will be used to design targeted electricity demand reduction programs based on San Francisco's unique energy use characteristics. The Board of Supervisors should direct City agencies to develop guidelines, programs, and new codes designed to reduce demand in conunercial and residential buildings in the public and private sectors. This should include: upgrading the Residential Energy Conservation Ordinance, re-instating the Conunercial Energy Conservation Ordinance, and requiring City vendors to participate in energy efficiency programs. The Board of Supervisors should adopt energy-efficient planning and building codes for new construction and major renovation projects in the public and private sectors (eg. requiring district heating and cooling systems in new developments) and join other cities in adopting green building standards such as LEED (Leadership in Energy and Enviromnental Design). . A priority target for reduction is the peak demand among conunercial and industrial facilities, particularly downtown buildings. SFE and SFPUC should work with downtown building owners and operators and the ISO to implement programs that incentivize load curtailment and load shifting during periods of peak demand. SFE and SFPUC should work with other City departments, PG&E, and state and federal agencies to provide enhanced incentives to San Francisco businesses and residents for energy efficiency and peak load reduction (eg., tax credits, rebates, rate incentives, and peak load management programs). SFE should create a coordinated outreach program directing residents and businesses to available local energy efficiency services, local appliance suppliers, programs offered through PG&E and other organizations receiving Public Goods Charge funding, state and federal programs, and tax credits. SFPUC should implement a design review program to make new municipal construction projects more energy efficient than required by state and local codes. The SFPUC should continue to implement municipal energy efficiency programs in City buildings including large scale retrofits, energy management, reconunissioning projects, maintenance, and staff training programs for existing facilities. 65 1. B.12 1. B.13 SFE and SFPUC should organize energy efficiency training for operations and maintenance staff, facility managers, and designers/specifiers in both the public and private sectors. SFE should develop energy educational programs for schools, coordinating with successful national and state curricula programs. These should be integrated into the curriculum in the SFUSD, City College, as well as private schools and professional training programs. Renewable Energy - (Solar) 7 MW by 2004; 28 MW by 2008; 50MW by 2012 (Wind) 50 MW by 2008; 150 MW by 2012 1. B.14 1. B.15 1. B. 16 1. B.17 1. B.18 1. B.19 1.B.20 SFE and SFPUC should identify locations for the installation ofrenewable energy systems in San Francisco on public and private buildings, and develop programs and funding mechanisms to put them in place through propositions B and H and other sources. SFE and SFPUC should work with City Planning and the Department of Building Inspection to facilitate permitting and inspections ofrenewablc energy projects. The SFPUC should develop renewable energy sources to be conveyed through transmission lines that serve San Francisco. SFE and SFPUC should work with other City departments to develop a local solar installation industry and bring renewable energy manufacturing and assembly to San Francisco. The City, through the Board of Supervisors, should set targets for the quantity of solar and other renewable energy development in San Francisco over the next decade. The Board of Supervisors should set a Renewable Portfolio Standard that would continually increase percentages of renew abies in San Francisco's imported electricity mix (to be supplied by renewable sources such as wind, solar, low-impact hydroelectric, geothermal and biomass). The Board should support Renewable Portfolio Standard legislation at the state and federal levels. SFE and SFPUC should develop resources and infrastructure for the production of hydrogen as a fuel to convert or displace fossil fueled technologies. 66 1. B. 21 SFE and SFPUC should seek partnerships with government agencies and private entities to explore the potential of advanced renewable technologies appropriate for San Francisco's urban envirorunent, including wind, tidal current, and wave generation. Medium-sized Generation/Co-generation -150 MW by 2004; 250 MW by 2008 (replaces old fossil fuel generation) 1. B. 22 1. B. 23 1. B. 24 1. B. 25 1. B. 26 The City should expeditiously develop sufficient highly efficient and operationally flexible new generating resources to enable the closure of Hunters Point Unit 4 by the end of 2004. The amount of new generation needs to satisfy ISO reliability requirements based on objective load flow analyses. The City should facilitate the early retirement ofPotrero Unit 3, to avoid costly upgrades and the extended operation of this outdated plant. New City power facilities used as replacement power must reduce air emissions. The City should develop cost-effective co-generation applications at locations such as Mission Bay as an effective way of reducing the emission of greenhouse gases and improving electric system reliability. The quantity of new natural gas-fired generation procured by the City should be based on an ISO-reviewed load flow study that determines the amount of power necessary to maintain system reliability while complying with all state and federal envirorunental regulations. All studies will be based on the latest ISO-accepted electricity demand forecast. Whenever investment in demand-side management programs and sustainable resources can offset new fossil fuel development to meet demand forecasts, this will be the City's preferred course. SFE and SFPUC should annually evaluate the need to operate any city- owned or controlled natural gas-fired generation. The evaluation will include an assessment of the latest electricity demand forecast and an assessment of the progress in energy efficiency, demand reduction, distributed generation, and renewable energy. Fossil fuel plants should only be used to serve city load and to meet reliability requirements as required by the ISO. 67 Small-scale Distributed Generation - 10 MW by 2004; 38 MW by 2008; 72 MW by 2012 1. B. 27 1. B. 28 1. B. 29 1. B. 30 SFE and SFPUC should develop or facilitate private and public sector projects for various distributed generation applications including fuel cells, packaged co-generation, and micro-turbines. Emergency diesel generators that do not have the best available pollution control technology should not be used except in genuine emergencies. The City should seek to remove economic disincentives within the control of the CPUC for the development of distributed generation projects installed in San Francisco. SFPUC should work with PG&E to research and identify the effects of distributed generation on the local distribution system. SFE and SFPUC should work with PG&E, City Planning and the Department of Building Inspection to streamline the permitting and interconnection of distributed generation to the grid. Transmission - 100 MW by 2005; 450 MW by 2006 1. B. 31 1. B. 32 The City should advocate for the completion of the 60 kV to 115 kV upgrade of the San Mateo-Martin transmission line number four before the end of 2004. The City should support the Jefferson-Martin 230kV transmission line project and strongly advocate for a continual increase in the level of renewables in the electricity resource mix transmitted over the grid. SFPUC should work with PG&E to expedite its early approval and construction. SFE should monitor the EIR process to ensure the City's expectations regarding environmental compliance/mitigation issues are met. II. Environmental Justice A. FINDINGS 2.A.1 The neighborhoods of Southeast San Francisco have historically borne a disproportionate burden of environmental and health impacts represented by the Hunters Point and Potrero power plants. At the same time, these communities have not shared in the benefits of jobs and economic development that the electricity generation supports. 68 2.A.2 2.A.3 The most pressing issue facing the neighborhoods of Southeast San Francisco is the closure of old polluting power plants and the net reduction of pollution from the generation of electricity in the Southeast. Significant potential exists for creating economic and employment opportunities for residents of Southeast San Francisco in the development of renewable energy sources and the expansion of energy efficiency programs. II. Environmental Justice B. RECOMMENDATIONS 2. B.1 2.B.2 2. B. 3 2.B.4 2.B.5 Prioritize low-income neighborhoods in San Francisco for the delivery of services and activities related to the development of the economic infrastructure for the efficiency and renewable energy industries. SFE should monitor and periodically report on the dispersion of specific energy program benefits to Southeast San Francisco including training, employment, contracting, and business development opportunities. SFE should work with other City departments to monitor and periodically report on carbon dioxide emissions, the reduction in air pollutants, and environmental impacts to Southeast San Francisco, the Bay, and sensitive habitats that are the result of electricity use and infrastructure. The results should be used to measure San Francisco's environmental performance. The Board of Supervisors should recommend that the Bay Area Air Quality Management District (BAAQMD) install a new air quality monitoring station in Southeast San Francisco. The siting of any new fossil fuel generation in San Francisco must demonstrate a significant improvement in air quality and other environmental benefits in addition to cost-effectiveness using cost benefit analysis criteria that includes health and environmental values. 69 III. Implementation and Review A. FINDINGS 3. A.1 3.A.2 In order to follow through on the recommendations made in this plan and to meet the identified goals, sufficient human and financial resources must be put in place. Some programs and projects are already underway, while others must be initiated and funded. Successful implementation will require strong continued participation by the public and leadership by the City. The Chamber of Commerce and the business community are cooperating in promoting energy efficiency and distributed generation among their constituents. SFPUC and SFE are actively engaged with state energy agencies, PG&E, and community groups to coordinate efforts and resources in support of our goals. III. Implementation and Review B. RECOMMENDATIONS 3. B. 1 SFE and SFPUC should identify specific objectives and develop timelines for the achievement of energy efficiency, renewable energy, and other distributed generation objectives in each district, each sector, and citywide. They should also identify the resources necessary to implement the recommendations of this Electricity Resource Plan 3.B.2 3.B.3 3.B.4 3.B.5 The Board of Supervisors should determine when City energy policies need to supercede other City policies (e.g. the Residential Guidelines currently disallow solar on historic buildings). The City should establish a funding source other than revenue bonds dedicated to private sector energy programs, such as a carbon tax and credit system. SFE and SFPUC should perform an economic impact and employment projection analysis of the effects of implementation of this plan SFE and SFPUC should target each sector of the San Francisco economy for the inclusion of energy efficiency, renewable energy and distributed technologies. Sectors include, but are not limited to commercial property developers, banks, large office buildings, small office buildings, hotels, warehouses, grocery stores, and apartment buildings. 70 3.B.6 3.B.7 All energy efficiency programs should incorporate measures to address natural gas use in addition to electricity use. SFE and SFPUe should coordinate in applying for funding from foundations as well as federal and state funding sources to achieve the goals of the Electricity Resource Plan. SFE and SFPUe should provide periodic updates on any developments in the regulatory or electricity industry that bear on this plan and should submit a joint annual report to the Board of Supervisors on achievements and challenges of the energy program. The Plan itself should be evaluated and updated annually. 71 Energizing Cities STATE OF THE WORLD 2007 is 2-5 percent, but studies find that the asso- ciated financial benefits over 20 years are more than 10 times the initial investment. And the costs of green buildings are falling with design and construction experience." I Although the marginal cost of improving \ efficiency is lowest when buildings are con- strutted, retrofits can be highly cost-effective as well. Simple strategies like daylighting, efficient lighting, and glazing can pay for themselves in as little as one year. More than 300 retrofit projects-from insulation to water system improvements-undertaken in China in recent years had an average pay- back period of 1.3 years.'" Such advances can also provide important benefits for the world's poor. In industrial nations, maximizing efficiency through design and cost-effective end-use technolo- gies can ensure that poor residents are.. not forced from their homes by rising energy costs. In the developing world, efficiency advances can bting dramatic quality-of-life improvements by making energy services more affordable to the poor. LEDs, for example, provide an estimated 200 times more useful light than kerosene lamps. At $55 each, solar-powered lamps with LEDs could brighten the nights of the poor. In Tembisa, a shantytown of Johannesburg, South Africa, a survey found that almost 10,000 households spend more than $60 each for candles and paraffin every year; with access to microcredit (see Chapter 8), such families could afford cleaner, better lighting freely powered by the sun." In ancient Greece, many cities were planned in grids so that every home had access to the sun for warmth and light in winter; the ancient Romans went so far as to pass "sun-right laws,>> forbidding builders from blocking access to the winter sun. Green roofs date back thousands of years, the most famous being the Hanging Gar- 96 dens of Babylon, constructed around 500 Be. The lessons of these ancient practices, combined with state-of-the-art technolo- gies and materials, provide today's cities with powerful tools to achieve dramatic efficiency improvements." Powering Cities Locally When Thomas Edison installed his first elec- tric systems in the late nineteenth century, he envisioned an industry with dozens of com- panies generating power close to the point of use. Such a system would be particularly suited to densely populated urban areas. Ini- tially, the industry evolved along these lines, with many companies producing power on site and capturing the waste heat. But by the mid-1930s most industrial countries had established monopoly industries, driven greatly by the economic benefits of ever- larger generating stations matched with trans- mission and distribution systems. It was not until the 1980s that efficiency limits were met-which, combined with a variety of eco- nomic and environmental challenges, led many experts to realize that bigger is not always better when it comes to energy pro- duction." Small-scale, locally installed power equip- ment, also called distributed generation (DG), could enable cities to meet much of their own energy needs once again. Today, DG remains more expensive per unit of energy output than conventional, centralized gen- eration, but costs continue to f.ill and asso- ciated benefits are significant. Distributed generation reduces the need for expensive transmission and distribution infrastructUre while loweting grid losses. By bypassing the . T&D system, DG also improves reliability and reduces vulnerability to accident or sab- otage. Because they are modular and can be installed rapidly, distributed small-scale gen- STATE OF THE WORLD 2007 Enlllr.lz.lng Cities eeators can expand to keep pace with demand as a city grows, deferring or preventing the need for new central power plants. This is par- ticularly important in developing countries, where migration is rapidly raising urban num- bers as well as energy demand. And distrib- uted systems provine local control and ownership of energy resources, encouraging community-level economic development. (See Chapter 8.) Most DG today comes from inefficient diesel generators or natural gas turbines. But several new options are emerging, with tech- nological progress on a variety of fronts. For example, advanced technologies such as high- performance microturbines and fuel cells promise reliable, efficient alternatives. Fuel cells require minimal maintenance and can be sited in crowded urban centers because they are clean, quiet, and highly flexible. Several fuel cell technologies are under develop- ment, with many already producing power for modern office buildings and hotels; advanced fuel cells could soon generate enough energy to supply a large proportion of the electricity and heat needed to power a city and warm its buildings.'. Today fuel cells or advanced microtur- bines must rely ptimarily on natural gas that has to be piped into cities. But alternatives already exist: methane from a local landfill will soon drive a fuel cell in the city of Vaasa, Finland, supplying heat and power for 50 homes. Eventually, fuel cells can use hydro- gen produced from a variety of renewable sources.31 Far beyond feeding turbines and fuel cells, renewable resources can provide energy for cooking, lighting, heating, cooling, and even transportation in the world's cities and beyond. Renewables already meet the energy needs of millions of people around the globe, and renewable energy markets are expeti- encing exponential growth. WlOd and solar power are the fastest-growing electricity sources, and biofuels are the world's fastest- growing fuels; all are experiencing double- digit armual growth rates. 32 Green roofs date back thousands of years, the most famous being the Hanging Gardens of Babylon, constructed around 500 Be. Wherever the sun shines, buildings- whether shacks or skyscrapers-can become mini-power or heating stations. Solar photo- voltaics (PVs) generate electricity directly from sunlight, often at precisely the time when power demand is greatest and electric- ity is most costly. PV technology has advanced to the point where it can literally be inte- grated into structures-in roofing tiles and shingles, outer walls, and glass windows- generating not only electricity but also shade and insulation. When used for building facades, PVs can be cheaper than granite or marble. Building-integrated PV (BIPV) is now widely used in Europe and is spreading to other regions as well. The lEA estimateS that BIPVs could meet nearly one fifth of armual electricity demand in Finland, more than 40 percent in Australia, and about half of the total in the United States." Solar thermal systems, which use the sUn's warmth to heat water and space, adorn rooftops from Frei burg in Germauy to Jerusalem in Israel and can pay for them- selves in just a few years through fuel savings. Shanghai and other Chinese cities are becom- ing hotbeds for solar energy, driven by the need to reduce coal and oil consumption. China now leads the world in the manufac- ture and use of solar thermal systems. Solar power and heating offer enormous potential in other developing-country cities as well, where they could provide electricity, heat, 97 Energizing Cities STATE OF THE WORLD 201 and hot water for families and communities in informal settlements that currently have no access to the electri.c grid or other modern energy services-and for fur less than it would cost to extend the grid." A new district with \,000 dwellings in Malmo,Sweden,meets 100 percent of Its electricity needs with solar and whll:! power. Cities can also tap the insulating proper- ties of the ground beneath them. Heat pumps use the near-constant temperatures of Earth or groundwater as a heat source in winter and a heat sink in summer to heat and cool water and space. The U.S. military replaced individual space heating, cooling, and water heating systems with ground- source (also called geothermal) heat pumps in more than 4,000 housing units in Fort Polk, Louisiana, e1iminating nearly one third of the community's electricity use and 100 percent of the natural gas previously required for heating and cooling. In the world's largest residential application of this tech- nology to date, the Beijing Linked Hybrid Project will use heat pumps to heat and cool almost 140,000 square meters (1.5 million square feet) of new apartments'S There is evidence that high-temperature geothermal water was used to heat buildings in ancient Pompeii. Today, such sources are tapped for district heating systems in cities in France, Iceland, the United States, Turkey, and elsewhere. Paris has the largest such sys- tem in the European Union.'" Although cities have little land available for energy crops, they have an enormous potential resource for biomass energy: urban waste. New York City, for example, pro- duces 12,000 tons of garbage per day. The waste must be shipped as far away as Ohio, 98 and disposal costs the city more than $ billion annually. In industrial- and develoI ing-country cities alike, per person gener: tion of municipal waste is increasing wit population and lifestyle changes. Due pI marily to a lack of resources and dispos; sites, as much as 90 percent of the waste i some developing-country cities is not co lected; instead, it is burned or left to rot i the streets, creating heavy smoke and fume water pollution, and disease.37 But one person's trash is another's blac gold, and urban waste can be used to PI( duce everything from cooking fuel for ind vidual households to grid-based electrici1 for office buildings and homes or'biofuels f( modern vehicles, Where waste does malce to landfill sites, methane can be extracted t generate electricity, reducing release int the atmosphere of a greenhouse gas (GH <: that is 21 times more potent than carbo dioxide, Landfill gas produces electricity i many U,S. cities, in Sao Paulo in Brazil, an in Riga in Latvia, and it meets nearly tw thirds of power demand for lighting in Mor terrey, Mexico. 38 Waste can also be treated in anaero bi digesters, which break down almost an organic material-from paper and yard wast to garbage and municipal sewage-into COIT postable solids, liquid fertilizer, and a gaseot fuel that can be carried or piped to stove: heaters, electric turbines, and any devie fueled by natural gas, Most poor people in th developing world spend at least 20 percent c their monthly incomes on fuel for cookin! But low-cost, household-sized digesters fe, with feedstock readily available in urban area can displace dung or firewood, reducing pre! sure on local forests while providing familie with a smoke-free and healthier environmenl And a Tanzanian study found that bioga could save five hours of household labor dail~ giving women and children more time fo STATE OF THE WORLD 2007 productive activities.39 On a larger scale, many industrial-country cities-including Frankfurt, Vienna, and Zurich-are converting waste to gas for energy. In early 2006, San Francisco launched a pilot project to produce power from dog waste aftci: finding that it accounted for nearly 4 percent of the residential garbage collected. Oslo, Norway, has perhaps the largest system in the world that uses raw sewage to produce $pace and water heating. Heat is drawn from the sewer and transferred to a network of 'Water pipes that feed thousands of radiators ,:and faucets throughout the city. And the Swedish coastal city of Helsingborg runs its )uses on biogas made' from local organic '.:Wastes. New technologies can convert even 'i'lnorganic materials-from hospital and indus- ]"wal wastes to car tires-into electricity and ,transport fuels'. Although the potential is limited in urban r~eas) even wind and water can provide some "~es with much needed energy. Wmd energy, ',:jp particular, faces visual and resource siting \~onstraints, but these challenges have not ;.1i/ways discouraged its use. Tokyo has installed .'~.5 megawatts of wind turbines along its 'waterfront, and in May 2005 an electricians' 'W:uon installed the first commercial wind tur- .iJ1h;.e in Boston, whicb will provide electricity ;ibr its regional training center. Cities along ,~stlines or large water bodies can tap local i.resources from new directions, helping to !i!iJeviate transmission constraints. The Mid- I'~grunden Wmdfurm off the coast of Copen- [!!agen meets 4 percent of the city's electricity llIileds and is the world's largest cooperatively !{!IWned wind power project." ~i'Both New York and San Francisco have 1"~'"'i..'.b,,,P, osed projects to use marine energy for :,.'wer. And some cities are literally tapping _."$1 water sources for cooling. Paris pumps ": ter from the Seine River to run air-con- ltioning systems, and Toronto uses the li", ~r ~] "....'. Energizing Cities deep, frigid waters of Lake Ontario for clis- trict cooling. Toronto's system has enough capacity to cool 3.2 million square meters of office space, or the equivalent of 100 office towers.42 Although few cities will meet all their energy needs with distributed renewable resources in the foreseeable future, some urban areas are already doing so. A new clis- trict with 1,000 dwellings in Malmo, Swe- den, meets 100 percent of its electricity needs with solar and wind power, gets its heat from sea and rock strata and from the sun, and fuels its vehicles with biogas from local refuse and sewage. The planned Chi- nese eco-city on Dongtan Island will tap similar resources for an expected popula ~ tion of 500,000 by 2040..' Energy efficiency improvements in build. ing:design, proper orientation and materials, and more-efficient end-use technologies facil- itate the use of renewable energy for two re~sons. First, because the scale becomes m(jre manageable, renewables can meet a city's energy needs more easily; second, as a city reduces its demand for energy, it is in a better position to bear the higher costs per unit of output that come with many renew- able technologies today.44 I While renewable energy technologies are ~I capital-intensive, they have low to zero fuel costs, reducing exposure to fluctuations in fos- sil fuel prices. They have far lower impacts on air, soil, and water and, as a result, on human health than conventional fuels and tech- nologies. And they can. provide a reliable and secure supply of power. An analysis of the 2003 blackout in the U.S. Northeast found that a few hundred megawatts ofPV gener- 1\ ation strategically placed in and around the major cities involved would have reduced the risk of the power outages dramatically..s Renewables also provide local control over energy supply and generate valuable tax rev- _7 99 -, Energlzlnc Cities STATE OF THE WORLD 2007 enue and local jobs-one of the most press- ing concerns of city mayors, according to a 1997 U.N. Development Programme sur- vey. Approximately 170,000 new jobs in Ger- many are attributed to the renewable energy industry. About 2S0,OQO Chinese are employed .in the solar heating induStry, and the biogas industry has created more than 200,000 jobs in India. Further, renewables can provide energy services where many con- ventional technologies do not or cannot go- into the homes and communities of the very poorest people." Pioneering Cities While cities face formidable challenges in reforming energy generation and use, many are taking bold steps in this direction-I;lllg- ing from daily municipal operations to spe- cial events and gatherings. (See Box 5-2.) Their actions demonstrate at practical levels which policies have proved most effective in a variety of conditions of economic wealth, natural resource endowment, and cultural and politieal heritage. They also indicate the vital role that cities can play in reducing greenhouse gas emissions and averting cli- mate change." In Barcelona, Spain, after the Green Party won in city council elections it introduced strong policies to support renewable energy and reduce reliance on nuclear power. The primary focus has been on developing the city's solar energy potential-which is 10 rimes as large as its total energy demand. From 1995 to 1999, demonstration projects and stakeholder consultations took place to develop policy and a realistic timeline for industry compliance." In 2000, the Barcelona city council man- dated that solar water heating provide 60 percent of hot water in new and substantially refurbished buildings. Less than four years 100 ::'~;:,~;~~;,~;<~'~';;,"~~;:~~:~%~;~~~~;::'):.,;%~,,:::::;,~.;;:,~:';'_:~,!;;.';~~:, Some 9.000 international gatherings take place around the world every year, giving cities a prime opportUnity to address cli- mate change In a very public way. For example. the Olympic Village constructed for the 2000 Games In Sydney. Australia, represented the biggest solafl-powered residential development in the world at the time. As part of Beijing's successful bid for the 2008 Olympics. city ieaders are work- ing to Improve local air quality. With assis- tance from the U.S. Department of Energy, the city is trying to reduce coal eonsump- don and to increase the use of solar energy for both electricity and pool heating. In Germany. a series of Green Goal targets for the 2006 World Cup Games included a 20.percent decrease in stadium energy use and energy generation from renewable sources. These efforts reflect municipal desires to attract prestigious and lucrative special events while avoiding strains on local infrastructure and resources as well as the global commons. SOURCE: See endnote 47. "",",.. ,'..<.".,,,.,,",~ after enactment of the Solar Ordinance, installed solar capacity in Barcelona had grown nearly rwelvefold; by April 2004, the city's solar water heating systems saved the equivalent of almost 16 megawatt-hours of energy a year, reducing CO, emissions by 2.8 tons annually. The city has since extended the requirements to even more buildings. By early 2006, more than 70 Spanish cities and municipalities had adopted solar water heating ordinances; fol- lowing their lead, the national government has enacted a siruilar policy." In other dties where governments encourage increased local reliance on green , iI/STATE OF THE WORLD 2007 Energizing Cltler &r , ~;: g:- " power, one popular mechanism is quota sys- meters (15 million square feet) could save the tems, which require that a growing amount city $6 million in energy costs annually. S2 " of municipal or community energy be Chicago's vision for change is not only " t obtained from renewable resources, with bearing economic fruit, it is also altering the market forces competing to identify the most very texture of the urban environment. .;! I economical projects. Often referred to as Green roofs have sprouted to life atop City renewable portfolio standards, these poli- Hall and on more than 232,000 square . cies can apply to public or private energy uti!- meters (2.5 riri1lion square feet) of residen- ~;,; jties. The publicly owned Sacramento tial and commercial structures. Some MuQicipal Utility District in California- 250,000 trees planted over the last decade building on its long-running comminnent to offer shade and beauty to local neighbor- (, , green energy-aims to derive 23 percent of hoods. In effect, a city long known for its ". its electricity supply from renewable industrial heritage is preparing to seize the _ resources by 2011. And to encourage 10C~1 next wave of global economic opportu- ~, PV installations by residential, commercial, nity-one linked explicitly to "green" and ", and industrial customers, the utility offers "clean" development. 53 ~, incentive payments for every watt installed. so ,-, Cities served by privately owned utilities;r.:~ Less than four, years after enactment ',. or o~er actors over which the municipality '~f the Solar Ordinance Installed ." has little control must often follow other /"'. .. ' .' strategies. In 1995 and 1999, Chicago swel- 'solar capacity In Barcelona had ., tered under serious heat waves that brought gl'Qwn nearly twelvefold. rolling blackouts and hundreds of local deaths. Following a $100-riri1lion settle- Another option for cities with private uti!- .: ment with the private utility ComEd due to ities is evident in the growing movement for "~' the outages, the city chose to apply the governments to help a colleetion ofcommu- funds it received toward greater sustain- nities meet their energy needs. In the United ability in local energy use in order to reduce States, for example, cities and towns in Cal- the likelihood and impact of futUre black- ifornia, Massachusetts, New Jersey, Ohio, outs. In 2001, Chicago negotiated a new and Rhode Island are now authorized to do power purchase agreement with CornEd, this for local government, area homes, and requiring the utility to provide 20 percent businesses, thanks to recent regulatory of the city government's electricity from changes. In turn, localities may shop among renewable sources by 2006 (although that a range of energy options. This community was later changed to 2010)." aggregation may allow cities to set more- Through these ,and other initiatives, stringent rules for energy efficiency and Chicago has started a campaign to become renewables than federal or state standards as "the most environmentally friendly city in a condition of utility contracts." America." & of 2004, new or substantially Beyond the issue of municipal control refurbished public buildings must meet Lead- and local utility ownership, some cities seek ership in Energy and Environmental Design clean local power as a way to keep pace with (LEED) certification as defined by the U.S. the demands of an industrializing society. Green Building Council. Retrofits of manic- Since 2000, Daegu in South Korea has pur- ipal buildings totaling 1.4 million square sued increasingly comprehensive urban plan- 101 Energizing Cities ning that links renewable energy with local economic development. During the 1997-98 Asian economic crises, the deval- uation of South Korea's currency con~ tributed to a doubling of energy prices due to the nation's large reliance on imported energy. Against the backdrop of high pop'- ulation density and rapid urbanization, this focused attention on Daegu's need to alter its energy model. 55 Daegu has established a goal of local renewables meering 5 percent of its total energy demand by 2010, with long-term tar- gets set through 2050. In addition, the Cen- ter for Solar City Daegu, a joint effort of the municipality and Kyungpook National Uni- versity, is working to disseminate green tech- nologies. These include PV and solar water heating installations at schools, on the uni- versity campus, and at sewage and water treat- 1 ment facilities. To help homeowners install solar roof systems, the city and national gov- ernment are funding up to 80 percent of installation costs. Strong citizen participa- tion has been reinforced by municipal lead - ership in Daegu.S6 The need to address environmental threats while widening social access to crit- ical energy services are driving efforts in Mexico City-home to 20 million people in the metro area-where a cloud of haze relentlessly shrouds views of surrounding mountains. In 1998, the World Resources Institute named Mexico City "the most dan- gerous city in the world for children" because of its poor air quality, and the city remains among the world's most polluted urban: areas." In 2002, officials finally addressed this situation when they enacted a range of poli- cies that are now organized under Mexico City's Proaire initiative for climate protec- tion. Energy efficiency improvements are being achieved through the installation of 102 STATE OF THE WOR.LD ,.., ~ advanced light bulbs in 30,000 new resi_ dential units and 45,000 exisring homes Solar hearing systems are due to be installed in some 50,000 residences. Financial sup_ porters of Proaire include local electric and water utilities, the World Bank, COrporate foundations, the Chicago Climate Exchange, and nonprofit organizations. 58 Since 2003, Cape Town in South Africa has sought to advance energy efficiency and renewable energy as a way to bting basic elec- tricity service to poor, underserved neigh- borhoods and to reduce the impact of a national power shortage that is expected to begin in 2007. The municipal government aims for 10 percent ofits energy to come from renewables by 2020 and has begun energy audits and efficiency retrofits at public facil- ities. In the Kuyasa region of the city, a pilot project under the Clean Development Mech- anism (CDM) of the Kyoto Protocol, which aims to reduce GHG emissions in developing countrieS, has insulated ccilings and provided residents with solar water heaters and compact fluorescent bulbs. The GHG reductions earned Kuyasa Gold Standard CDM recog- nition in 2005 fur exceptional standards in sustainable design. 59 Numerous other cities are adopting goals and programs that support sustainable energy systems. (See Table 5-1.) And many cities have united to form larger networks that can pursue green energy development for both cli- mate protection and urban quality of life. In many ways their collaboration-as well as the actions of regional and state govern- ments-reflects an effort to act in place of national governments and the international community, which to date have largely fuiled to resolve major problems associated with conventional energy llse.60 Examples of these networks include the U.S. Mayors' Climate Protection Agreement, which encourages cities to lobby the federal "~, STATE OF THE WORLD 2007 ,. EnerBb:lng Cities Table 5-1. Selected Municipal EnergyTargets Increase municipal use of renewable energy by 50 percent from 1996 levels and private use by n percent by 20 I 0 10 percent of homes must use solar hot water or PV by 20 10 100 percent green power for municipal government by 20 I 0; all new ctty~owned construction to meet LEED Gold certification Minimum 5~percent renewable energy use in large municipal facilities starting in 2004; renewables proposed to supply 20 percent of total energy by 2020 much greellhouse gas each person on Earth can emit annually without overwhelming the ability of the atmosphere and biosphere to absorb it. The target for 2050 is about 3.3 tons CO,-equivalent per person. This is about as much as the average person in China or Argentina emits today.62 Lighting the Way Cities have great potential to influence change. This power comes not only from the more manageable scale of local population and energy use but also from their role as national and regional seats of political power. Cities also frequently represent centers of political and technological innovation, where constituents are closer to these seats of power and thus retain more influence over policy- makers. And because powerful industries do not wield the same influence at the local level Target Reduce energy intensity of the city's economic output by 32 percent between 2004 and 2010 Reduce energy use in public buildings 30 percent by 20 I 0; incorporate solar water heating Into 75 percent of new buildings annuaily Energy audits required for buildings exceeding 1,500 square meters; all new buildings must rely on distrlct heating (electric heating banned) 10 percent of all public and private electricity must come from renewable sources by 2010 Reduce municipal building energy use 50 percent from 1990 level by 2025 Clcy Beijing. China Berlin, Germany Copenhagen. Denmark Frelburg, Germany Leicester, United Kingdom Melbourne, Australia Oxford, United Kingdom Portland, Oregon, United States Tokyo, Japan SOURCE: See endnote 60. government for a national climate change policy, and the Cities for Climate Protection Campaign ofICLE1-Local Goverrunents for Sustainability, which focuses on the design and use of climate-related policies among some 650 participating local governments. Through such partnerships, city officials are able to share best practices and encourage ongoing municipal leadership. And a few governments are now stepping forward to reinforce these efforts. For example, the Aus. tralian government has funded a national independent 1CLEI office, which involves 216 councils representing 87 percent of Aus- tralia's population.61 The International Solar Cities Initiative, created to address climate change through effective actions in cities, has devised an explicit target to guide "pathfinder" cities toward major GHG emissions reductions. The target was established by estimating how Energizing Cities STATE OF THE WORLD 2007 as at national or regional lev~ls, cities can provide a more even playing field for all. Under such conditions, supporters of clean power and related alternatives may find it easier to introduce groundbreaking changes in cities. .. \ Given that local renewable energy devel- opment can yield significant benefits, what is standing in !he way of change? One major . obstacle is the limited resources available to pursue local initiatives. AB noted, there are numerous options for minimizing energy use and increasing reliance on clean power, but cities need financial, technical, and administrative support to pursue these strate- gies. Although this is more commonly a problem in the developing world, it is also a constraint among municipalities in ipdus- trial countries. Many sustainability goals can be pursued through policies that do not increase taxpayers' costs. Investment priorities deserve particular attention in the world's poorest urban areas. To help achieve more balanced, sustainable economic development that simultaneously meets people's needs, nongovernmental orga- nizations (NGOs) and community groups can encourage governments to link clean energy access to poverty alleviation. Bilateral and multilateral program funding must also move more quickly from fossil fuels toward renewables. Initiatives under the CDM and related global programs could be used more frequently for energy projects that reduce GHG emissions..' The second fundamental challenge is posed by national and international poli- tics. For decades, conventional fuels and technologies have received the lion's share of global investment in energy infrastruc- 104 ture. In 2002, the World Council for Renewable Energy noted that the $300 bil- lion of energy subsidies spent every year on nuclear power and fossil fuels is four times as much as has been spent promoting renew. able energies in the last two decades. This trend is all too evident, for example, in the Bush administration's push for next-gen- eration nuclear and "clean" coal technolo- gies, in efforts to boost nuclear power in India and China, and in suhsidies used by some developing countries to support fuels like kerosene and diesel, which make renew- \ able energy less competi.tive. Countering these developments is going to require a political commitment to clear, mandatory , targets for renewable energy use and for technology research and development.' A third barrier is market pressures that ignore environmental and social costs and benefits in energy prices. AB a result, devel- opment of green energy remains at a disad- vantage beyond the most immediately profitable uiches, such as wind generation as a hedge against volatile natural gas prices. This is particularly clear in areas where the electricity sector has been privatized over the last decade, where governments have often found it necessary to impose firm renewable energy goals for retail electric providers in order to ensure green power's continued advance. Such actions highlight national gov- ernments' crucial role in correcting for prices and market structures that fail to signal the true costs of conventional fuels.' The effect of market pressure is also appar- ent in the priorities of most electric utilities, which focus on expanding supply rather than conservation to meet customers' needs. \ "Negawatts"-electricity that is never actu. ally produced or sold-would be a viabl, .energy service to consumers if more govern. ments introduced regulations that encour. aged utilities to pursue conservation.66 STATE OF THE WORLD 1007 The issue of pricing and costs also plagues the buildiog sector. Although developers in cities like Chicago now have trouble findiog the requisite "anchor" tenants if a new build- ing does not meet certain voluntary green standards, this is rarely the case in other municipalities. Energy costs often represent only a small share of overall business or house- hold expenses, and cost savings from effi- ciency measures are not always reflected in conventional accounting. As a result, price sig- nals fail to drive change." Another fundamental challenge involves altering the common skepticism that even a large number of small-scale, local renewable systems combined with conservation and effi- ciency will ever be able to produce enough energy to meet the demands of a large city. To some extent, such mindsets are starting to change, as evident in the growing movement toward more sustainable cities and in recent efforts by former President Bill Clinton to encourage climate protection in some of the world's largest urban centers." Yet a great deal remains to be done in cities. As one example, despite some policy efforts to encourage or require green con- strUction, the typical new U.S. home s~' remains highly energy-inefficient, requiring 30-70 percent more energy than new "advanced" green homes. This gap points to the need for larger awareness of the long- term gains, both ecological and economic, that can be achieved through more ambi- tious mandates for sustainable practices. In effect, a paradigm shift is needed-one that embraces radical improvements in energy efficiency, with the remaining demand met primarily by renewable energy.'9 Relevant actors and institutions-from all levels of government to the finance sec- tor-must consider new ways of evaluating the life-cycle costs and benefits of renewable energy and of buildiog design that consid- Energlz.ing Cities ers local conditions and uses local knowl- edge. This will mean involving the author- ities that have the most power to mandate new requirements and monitor enforcement. It can also ensure the institutional capacity- \ in the form of financing for "green" home improvements, for example-to assist peo- ple who participate in efficiency and renew- \ able energy programs.'o Contrary to some people's perceptions, many sustainability goals can be pursued through policies that do not increase tax- payers' costs, as in Chicago, where green buildiogs receive expedited permitting. City planners can incorporate the "new urban- ism"-which involves building for people rather than cars-and related planning approaches for mixed-use communities that combine residential and commercial space. This 'can minimize energy use and suburban sprawl while making city life more sustainable and enhancing the overall quality of life." In addition to education and public aware- ness campaigns, political pressure must be brought to bear against powerful forces that favor the status quo. Positive changes in the energy sector, particularly in the world's poor- est urban areas, will require action from not only municipal authorities but also regional, provincial, and national governments as well as NGOs and aid and lendiog institutions. (See Table 5-2.)72 1l The challenge lies in moving beyond local voluntary partnerships toward strong intergovernmental and societal commit- ments for change. Wider civil society involvement will be critical and has already figured prominently in many recent move- ments for more-sustainable energy use in cities. Citizens' groups can do more by call- ing for national and international changes in investment priorities and can work with pri- vate financial institutions favoring clean energy as a profitable strategy for minimiz- . 105 Energl:llng Cities STATE OF THE WORLD 2007 Table 5-2. Roadmaps for Powering Cities Locally Obstacle Strategic Response Lack of control over energy sector t' Lack of widespread access to energy service (particularly common in low-income cities) . Lack of funds or exper- tise to identify and undertake projects Lack of awareness or understanding of benefits of local green energy or how to use technologies Municipal government can set targets for its own green energy use, procure goods and services made wfth local green power, aggregate customer demand, and. form power purchase agreements with utilities. Municipal government ca.n target energy efficiency and conservation in public and private buildings by requiring energy audrts and mandating use of specific technologies and construction practices, through city planning and permitting. Citizens can form cooperatives for local energy development or purchase green power. Governments can support pricing reform and commit to replanting trees to ensure wider availability of fuelwood and other biomass resources. Legalized secondary power arrangements can give urban dwellers access to power sources "owned" by other individuals, thereby avoiding or reducing otherwise prohibitive upfront fees (the utility can set basic technical standards to enhance safety of energy delivery, while the de facto electricity distributor determines rates). Reduced lifeline electricity tariffs (available to lowaincome users for lower levels of use) can spread out upfront fees (such as grid connection charges) into future payments 'over time. Local actors (public or private) can partner with energy service companies or,ln low- to moderateaincome cities, bundle projects to leverage microfinance or multl- or bilateral assistance for the lease or purchase of solar water heaters, PV systems, and safer and more efficient stoves and smoke hoods. Municipal government can work with local trade organizations, private-sector champions, and citizens' groups on information campaigns, product labeling, professional training. and school curricula. (NGOs and community groups can sponsor demonstration projects. ~ Lack of utility involve- ment or of regional, national, or international emphasis on renewable energy development, energy efficiency, con- servation, and GHG reductions Municipal or grass roots efforts can coordinate lobbying across locales for changes in polftJcal priorities (toward regional or national targets and commit- ments) to include mandates for both public and private utilities, States and dties can develop and implement their own policies and band together in multi-state or multi-city agreements to set "de facto" policy. SOURCE: See endnote 72. ing business risks from climate change." Today cities have an unprecedented oppor- tunity to change the way they supply and use energy. New eco-cities such as Dongtan in China may show the way, even as existing 106 CIties turn to technologies rooted in the past-from adobe architecture to passive solar heating. When complemented by conserva- tion, more-efficient technologies, and neW decentralized, small-scale energy services, STATE OF THE WORLD 1007 Energizing Cities these efforts can help cities confidently nav- igate the forthcoming peak of cheap oil and narural gas production while reducing the impact of climate change. Energy tranSfor- mation in cities can be the doorway to secu- rity and vitality in urban life. 107 DISTRIBUTED GENERA TlON AND COMBINED HEA T AND POWER WORKSHOP N(lRESCO An EQ..UITABlE RESOURCES Company 30 kW System - Building 14, NAB Coronado · System Ratings: - 30.1 kW(ac) Output - 49,765 kWh Annual Production · System Details: - 275 - 109.3W PV Modules - Model PL-AP-130 DISTRIBUTED GENERA TION AND COMBINED HEA T AND POWER WORKSHOP N(~RESCO An EQ.UITABLE RESOURCES Compony 30 kW Sy'stem - Building 14,. NAB Coronado DISTRIBUTED GENERA TION AND COMBINED HEA T AND POWER WORKSHOP N(~RESCO An EQ..UITABLE RESOURCES Company 750 kW System -NAS North Island · System Ratings: - 750 kW(ac) Output - 1,244,000 kWh Annual Production · System Details: - Largest PV System in the Federal Government - 3,078 - 300W PV Modules - Model ASE-300-DG/50 - Covered Parking Structure for 400 Spaces DISTRIBUTED GENERA TION AND COMBINED HEA T AND POWER WORKSHOP N(lRESCO Iv> EQ.UITABLE RESOURCES Company 750 kW System - NAS North Island DISTRIBUTED GENERA TION AND COMBINED HEA T AND POWER WORKSHOP NljRESCO An EQ..UITABLE RESOURCES Company Project Benefits · Provides Both Bases 1,293,765 kWh per Year of Clean Power - 3% ofNASNI Peak Demand - 1 % ofNASNI Power Consumption · Reduces Air Emissions - 309 Tons of CO2 per year - 486 Ibs of NO x per year - 54 Ibs of SOx per year · Provides Sources of On-Base Power · Reduces Vulnerability to Disruptions to Off-Base Power Grid · Facility Demonstrates Strong Environmental Commitment Green Energy Options to Replace the South Bay Power Plant Alternative Energy Plan on the Feasibility and Cost-Effectiveness of Replacing the South Bay Power Plant by 2010 With Local, Competitively Priced Green Energy Sources Prepared By !Q,~,~,2l~~I Paul Fenn - Executive Director Robert Freehling - Research Director Prepared for ,. "N"""'." '. .".. ....'...".. . ""..........'. ..'. .' ',. ~...' , !' }(~','<f" ,':. . nm8." " . HOALI'ff " February 15,2007 Table of Contents I. Executive Summary .......................................................................................1 Background and Purpose ................................................................................................. 1 Summary of the Green Energy Option Portfolios ......................................................... 2 A Range of Options ........................................................................................................... 3 Findings.............................................................................................................................. 7 Recommendations ........................................................................................................... 10 2. I ntrod uction ..................................................................................................12 The Proposed South Bay Replacement Project............................................................ 14 Meeting the Appropriate Energy Needs ....................................................................... 15 3. ISO Reliability Must Run (RMR) Criteria Analysis & Scale of Replacement Energy Needs ........................................................................16 Current Scale and use of the South Bay Power Plant ................................................. 17 Current RMR Contract with the ISO........................................................................... 19 Variables that Influence RMR Calculations and Designations.................................. 19 Peak Demand and Types of Power Plants ..................................................................................19 Firming up the Capacity of Renewable Generation...................................................................20 San Diego Regional Electricity Supply and Demand................................................... 21 Addition of New Power Plants .....................................................................................................23 Future Power Plant proposals......................................................................................................23 Local Targeted Upgrades in Transmission .................................................................................24 Energy Efficiency and Loading Order Requirements ...............................................................24 Demand Response .........................................................................................................................24 Distributed Generation .................................................................................................................25 Existing and Future Energy Supply and Demand .....................................................................25 Summary of ISO RMR status and Scale of Energy Replacement Needs .................. 29 4. Green Energy Options: Three Portfolios for Cleaner More Sustainable Energy for the Region .................................................................................30 90% Replacement Capacity Green Energy Option..................................................... 30 70% Replacement Capacity Green Energy Option..................................................... 30 50% Replacement Capacity Green Energy Option..................................................... 30 5. Description of Green Energy Technology Options ...................................31 Hybrid Wind Farm & Pumped-Water Storage Facility ............................................. 31 Hybrid Solar Concentrator Turbine with Natural Gas Backup and Cogeneration. 34 Photovoltaics with Energy Storage or Demand Response .......................................... 36 Cogeneration for peak capacity ..................................................................................... 37 Energy Efficiency, Demand Response and Conservation ........................................... 37 6. Key Investment !VIeehanisms and Finandng ............................................39 Community Choice Aggregation (CCA)....................................................................... 39 Municipal Revenue Bonds (H Bonds) ........................................................................... 40 H Bonds and CCA........................................................................................................... 41 Applicatiou of H Bonds to CCA. .................................................................................. 42 Sources of Repayment .................................................................................................... 43 Alternative Structures for using H-bonds and Implications for Tax Exemption..... 44 Engagement of CPUC and other funding..................................................................... 47 California Solar I nitiative.............................................................................................................4 7 PGC Energy Efficiency Fnnds .....................................................................................................47 Federal Energy Tax Credits .........................................................................................................48 Snpplemental Energy Payments (SEPS) .....................................................................................49 7. Bent'tlts Comparison of CEO Options to Gas-tired Replaeemenl .........:;0 Economic Benefits ........................................................................................................... 50 Financial Return on Investment ..................................................................................................50 More Local Jobs ............................................................................................................................51 More Money in the Local Economy.............................................................................................52 Decreased Reliance on Natural Gas ............................................................................................52 Environmental Benefits .................................................................................................. 53 Air Quality Benefits ......................................................................................................................54 Environmental J ustice ..................................................................................................................55 Reduced Global Climate Change Impacts ..................................................................................55 GEO Report Findings..................................................................................................... 57 The Greener Energy Options Portfolios are economically viable.............................................57 The GEO Portfolios otTer significant benefits ............................................................................58 The initiative must be led by Chula Vista. ..................................................................................58 Community Choice Aggregation (CCA) and Public Investment is the best Approach ..........59 The GEO Portfolios are consistent with existing local, state and federal policy, regulations and law ...........................................................................................................................................61 Recommendations ........................................................................................................... 63 Appendiees Figures and Tables Figure 1. San Diego County Wind Resource Regions.................................................................. 32 Figure 2. New York Mercantile Exchange Futures Prices for Natural Gas.................................. 52 Table I. Operating Profile of the existing South Bay Power Plant. ............................................ 17 Table 2. Approximate cost of generating electricity (in nominal cents/kilowatt-hour) with the South Bay Power Plant and with a new gas-fired replacement peaker plant................. 18 Table 3. SDG&E 2005 RMR Resource Ca1culation..................................................................... 22 Table 4. Actual and Potential New Peak Resources for SDG&E between 2003 and 2009......... 25 Table 5. Comparison of Demand Projections made by SDG&E in 2003 and 2005..................... 26 Table 6. San Diego Region Generation ........................................................................................ 27 Local l'o\ver Alternative Energy Plan for Replacing the South Bay Povver Plant January, 2007 I. Executive Summary Background and Purpose The existing South Bay Power Plant, over 40 years old, is outdated, inefficient to run, devastates thc South San Dicgo Bay ecosystem and pollutes the air. The power company LS Power, all of whose merchant power plants (including the South Bay Power Plant) were recently acquired by Houston-based Dynegy', is in the permitting process for a South Bay Replacement Project (SBRP) which includes the demolition of the current South Bay Power Plant and the construction of a new gas-fired power plant near the current site. There is little disagreement that the existing plant needs to be shut down. There is debate, however, about how the energy capacity provided by the existing plant should be replaced. This decision will shape the region's energy future, the health of Chula Vista residents, and the character of the Chula Vista Bayfront for decades to come. The SBRP decision will have global impacts. Climate Crisis is upon us. Power plants are the largest cause of greenhouse gas pollution in the United States, which as a nation is the world's largest greenhouse gas polluter - and California's greenhouse gas emissions have continued to increase for the past fifteen years. A major opportunity to answer the Climate challenge is in our front yard, and will shortly present itself for local decision-making. In the Chula Vista region, by far the largest single cause of climate pollution is the South Bay Power Plant. While Dynegy's acquisition of the plant has increased pressure to approve a larger power plant replacement, green power alternatives - and the means to develop them cost-effectively - now exist, which if developed by Chula Vista and potential local partners will render power generation at the South Bay Power Plant site unnecessary for the regional transmission grid. Recognition of urgency and opportunity is essential to solving the Climate Crisis. The SBRP decision may be the community's only major chance to do something about this mounting catastrophe. While the existing plant runs at a relatively low capacity most of the time, it does provide 700 Megawatts (MW) (reduced to 515 MW for 2007) of "Reliability Must Run" (RMR) capacity to thc grid, a special designation instituted to ensure grid stability. A number of options exist to provide the energy and capacity that the San Diego region will need into the future, including demand response, renewable energy, natural gas plants in other parts of the County, and other options. For a number of reasons - to protect public health and promote environmental justice, to protect our economy from over dependence on natural gas with its price volatility, to reduce greenhouse gas emissions, and to meet state-mandated requirements for renewable energy - the replacement of the existing South Bay Power Plant should include a major commitment to green energy options. This report identifies and analyzes local opportunities for more sustainable, secure energy development in San Diego County in order to reduce the need for, or the scale of, a natural gas generation facility to replace the South Bay Power Plant (SBPP). On September 15,2006, Independent Power Producer Dynegy announced it has agreed to pay more than $28 in stock and cash for the merchant plant portfolio of private equity fund LS power Group, including SBPP and eight other power plants acquired from Duke Energy for $ I .6B in May. LS Power Group will retain a 40 percent stake in the combined company. Dynegy's management team, including CEO Bruce Williamson, will run the company. 1 L.\l\.lll'(lwer i\lh'rn,ltil\' CllL'I).!,) I'Lm rur Rq'l.l(in,~ lhle' South LLw I\'WI;-'1 Illcltl! lebJu,lfv 2007 The "Green Energy Options" (GEO) outlined in this report, demonstrate how Chula Vista and neighboring communities can now move to develop solar, wind and other green power technologies at market prices, stabilize local electricity rates, win energy independence, and eliminate a major contributor of pollution and greenhouse gases. The City of Chula Vista has already taken a leadership role in promoting energy sustainability and taking responsibility for reducing the hazards associated with the global climate crisis. By investing in energy development described in this Green Energy Options report, the City of Chula Vista can take a major step toward ensuring energy and economic security for Chula Vista and the region, and can set an example for the region, state, and beyond. Summary of the Green Energy Option Portfolios The Green Energy Options (GEOs) described in the report are viable, and the technologies are readily available. The GEOs are three electric energy portfolios designed to meet three different levels of capacity replacement for the South Bay Power Plant. They address a range of possible regional needs and provide a range of investment options. The current power plant supplies electricity in the period of high demand during the day and early evenings, and the GEO portfolios are designed to meet that same requirement. Each GEO portfolio includes diverse technologies in order to avoid "putting all eggs in one basket". The hazards of going to a 100 percent natural gas portfolio are numerous. Natural gas has a high level of price volatility, and when the fuel price shoots up, electricity prices are sure to follow soon. Residents of San Diego County have seen what happens when they put too much trust in natural gas. Natural gas also has other problems. It is a limited resource that is bound to become more difficult to obtain over time. It is also a fossil fuel that emits or creates many tons of pollutants annually, including lung-clogging particulates, nitrous oxides, corrosive ozone, as well as carbon dioxide and methane that are destabilizing the global climate. The GEO portfolios are designed to meet all of these challenges, to cut pollutants dramatically, reduce reliance on fossil fuel, and serve as a hedge strategy against future price swings in natural gas. The GEOs provide three levels of capacity replacement relative to the current 700 megawatt power plants. The nominal capacity of the GEO options range between 500 megawatts and 970 megawatts, but this translates into a smaller equivalent capacity for the purposes of replacing the existing plant. This is because some renewable technologies, mainly wind power, only produce electricity part of the time. But the wind resource is given a boost relative to its otherwise intermittent nature, since one portion of the wind power is delivered to pump water uphill into a reservoir during the evening so it is available the next day to power generators when demand for electricity is high. Nearly all the rest of the portfolio's generation capacity is considered to be able to carry its weight in electrical system support, without any greater degree of help than other types of electrical generation routinely receive. This rating, called the Effective Load Carrying Capacity, is a product of the full capacity of the power generation equipment and the availability of the energy resource. In the case of wind, studies have shown that the lowest "carrying capacity" for actual major California wind farms is about 25 percent. We have been even more conservative, and assumed that only 20 percent would "count". 2 Local Power Alternative Energy Plan for Replacing the South Bay Power Plant February, 2007 To confuse matters somewhat, yet another measure of reliable capacity is used by the state grid operator, the California ISO. This measure is exceedingly restrictive and actually has never established satisfactory rules for renewables like wind and solar power. With the increased legal mandate for renewable energy in the state, such rules will become increasingly necessary, and the ISO will not be able to ignore the contribution of renewables to the state's electric grid reliability, as they have in the past. This issue is not academic. During the 2000 to 2001 California "Energy Crisis", many commercial vendors of electricity took their conventional generators off-line. This caused serious problems that threatened grid stability, and resulted in greatly increased prices for their product. While these and other rather overt manipulations were going on, California's renewable generators continued to operate and they helped significantly to maintain the state's electric grid, and even to avoid blackouts. Thus, there is historical evidence, as well as ongoing demonstrated performance, to show how wind and solar power contribute greatly to the reliability of California's energy supply. We established the size of the three green energy portfolios to meet 50%, 70% and 90% of the current South Bay Power Plant's capacity for supplying power during the hours of peak demand. Thus the portfolios are designed to meet the same needs and have similar functionality to the existing plant, though with a number of extended capabilities that the current plant does not have. For instance, the pumped storage plant can respond nearly instantly to changes in demand for electricity, a factor that can be critical during a power emergency. Other features will be described in this report. This report also shows how any capacity shortfalls can be replaced in other ways without resorting to adding new transmission lines leading out of the region. A Range of Options The GEO options contain a variety of portfolio elements, design sizes, and potential for siting of energy facilities, that allows for flexibility to meet different system needs and market conditions. There is really very little that is constrained about this portfolio, and in fact the GEO options show general strategies, as well as how to apply these strategies in very specific and practical ways. It is certainly possible to change these elements to respond to changes in the cost of renewablcs and of conventional power sources. Thus there is an adaptability that is completely lacking in the current plan to build another power plant on the same site as the existing power plant. 3 t (\(',11 1"\\\[-'1 i\1tVlI1cill\t' ~,')ll'rt!y l'ldn 1m Rl'pLlllng tJw ')(llllh 13.1\' l\ll\t'I' l'l,ml hhru,1rv,2()()7 4 Locall'ower Alternative Energy Plan for Replacing the South Bay Power Plant Febnwry, 2007 5 1.(\( <l11'o\".L'1 ,~\lh'lI1C1lil, t' '=',Iwrg\ ['1,111 fl'l l~l'fll,lUI1,,~ tilt' S\Jllth LL1V f\l\\t-r P!ill1t ft'hi"lIMV_ 2007 6 Local Power Alternative Energy Plan for Replacing the South Bay Pmver Plant February, 2007 Findings The Green Energy Options (GEO) portfolios presented in this alternative energy plan are economically sound. The low-interest municipal bonds available to cities like Chula Vista can achieve significantly lower financing costs for renewable generation. Also, the largely fixed cost of the renewable GEO portfolios provides a hedge against substantial risk of increasing natural gas prices over the next 20 to 30 years. The GEO Portfolios offer a number of benefits over a future commitment to a 100% natural gas- fired plant on the bay front. One benefit is cleaner air - the GEO portfolios would result in 60- 80% lower emissions of particulate pollution and carbon dioxide every year when compared to a new "all natural gas" plant. Pursuing the GEO options would also get us firmly down the road of a more secure and sustainable energy future: they would produce more local jobs, decrease the region's over-reliance on natural gas, and keep more money in the local economy. Community Choice Aggregation (CCA) is the best approach to eliminating the need for power generation on the South Bay. CCA would enable a full range of options, including transmission of power. If Chula Vista forms a CCA or builds a power generation facility, it may elect to obtain transmission services within or outside Chula Vista, by acquiring access to existing transmission capacity, arranging with SDG&E to provide transmission access, pursuant to Federal Energy Regulatory Commission (FERC) Order 888, or arranging to purchase transmission services from another party such as a tribal government. No option would require adding transmission lines leading outside the county, and all would make use of existing transmission pathways. This Plan finds that the initiative would be best led by Chula Vista. Over the past four years, the City of Chula Vista has prepared extensively for the implementation of Community Choice Aggregation ("CCA") and/or development of a power generation facility. CCA would allow Chula Vista to find an alternative electricity supplier to SDG&E, and to decide what kinds of electricity to purchase. In addition, Chula Vista and a number of potential public partners may issue municipal revenue bonds ("H Bonds") to finance renewable energy and conservation facilities. These mechanisms are analyzed in this Plan. The GEO Plan shows how CCA in conjunction with H Bonds can be used to develop a cost- effective, cleaner and more sustainable replacement of the South Bay Power Plant ("SBPP"). This report identifies several specific opportunities available to Chula Vista, allowing a variety of locally feasible technologies and partnerships. However, even if CCA is not pursued by Chula Vista, other governance structures and initiative options are available for the City to pursue some or all of the green energy options outlined in this report. Financial analysis of the energy options has been performed with this in mind, to demonstrate the cost of electricity by considering the portfolios as independent investroents. A critical facet of the GEO options is to include local power resources that require little or no transmission facilities to deliver the power to customers. Chula Vista and the San Diego County region offer opportunities to develop a variety of green energy resources. These opportunities 7 1 (l(,lIl\l\\Ti" Alterl1ilti\t' cnl'J"/-'.Y 1'1,111 rpr l\tv1di.il1t', llll' '-lUllth HeW {'(\\\l'I' PLlIlt h+)]"U,HV, 2()()7 2. Introduction The Green Energy Options (GEO) alternative energy plan has been developed by Local Power for Environmental Health Coalition (EHC) to be considered by the City of Chula Vista and other governmental entities in the San Diego County region. The Plan identifies and analyzes local opportunities for more sustainable, secure energy development in San Diego County in order to reduce the need for, or the scale of, a natural gas generation facility to replace the South Bay Power Plant (SBPP). The GEO will include appropriately scaled renewable generation, energy storage, and energy efficiency measures. More broadly, the GEO will develop opportunities for Chula Vista to act singly, as well as inter-governmental or regional opportunities to eliminate the need for any power plant at the SBPP site, and to reduce the region's need for another large gas-fired power plant. These options will support reliability of San Diego County's regional electric transmission grid, which is run by the California Independent System Operator. This report presents a series of scenarios, location- and time-specific opportumt1es that are supported under current California and federal law, for Chula Vista to negotiate with energy suppliers, undertake public works projects, and administer energy efficiency programs to reduce or eliminate the need for a power plant at the South Bay Power Plant site. Every scenario and proposal outlined in this report can provide opportunities for the City of Chula Vista to operate a profitable energy facility and/or provide residents, businesses and agencies with competitively priced energy services. The profit structure will depend upon how the projects are financed, and implemented. For example, the lower cost of capital for bond-financed wind farm or natural gas peaking plant essentially locks in a long term price advantage over any private or utility competitor. The fact that renewables are now being required by law for all utilities and Community Choice Aggregators means that there is a built in market for the foreseeable future. The target requirement for purchasing renewable energy grows each year. Twenty percent of all utility company electric supply must by "green" by 2010. After that year a new target is likely to be set at 33 percent, a level that is fully supported by the governor and all the regulatory bodies. Legislation has been introduced that would write this higher goal into state law, and mandate that it be achieved by 2020. Utility companies have complained that it has been difficult to access sufficient renewable supplies; thus a growing market is wide open to those who can successfully develop green energy projects. Municipalities are in a unique position to benefit from this arrangement. Renewables face certain hurdles that municipalities hold the power to overcome. The first hurdle is financing. Private developers are faced with the challenge of raising capital for projects with certain risks. For example, wind projects may be eligible for special tax credits, but only if they are built by certain dates. If those dates pass, because of delay for any reason, then the project loses its financial viability. Municipal governments do not receive tax credits, and thus are not bound by such considerations. Their low cost, tax free bonds provide superior benefit to the tax credit, and is available to them at all times without being subjected to the risk of federal tax policies over which they have no control. 12 l.oc"ll'rlwvr Alkrndtivt" ErlL'q.~y I']all fm Replacing tJw Snllth t{,lY J\l\\'t'r PLlnt Ft'hrl.l"rv 2U[J7 A second financing risk is associated with finding a long term buyer for the electricity. While renewable standards do provide some assurance, lenders want to see contracts running out into the future as far as 10 to 20 years. This can be quite difficult to achieve. Municipalities that form Community Choice Aggregations (CCAs) have a built in market integration that no private developer could ever have, in that a CCA is both a seller and buyer of electricity. The market risk is thus greatly reduced, since the CCA can agree to purchase some or all of the electricity provided from its own renewable plant for up to 20 years into the future. This lowers borrowing cost, a critical component for making renewables cost effective or profitable. The fact that renewables greatly reduce reliance upon fuel means that once the capital expense is paid off, the cost of generating electricity is reduced to relatively small operating expenses. Electricity sold at full price from these facilities, after the financing cycle, will likely realize higher prices on the market at the same time that ongoing costs are greatly reduced. In this sense, renewables are an investment in the future. Renewables can also provide more near term benefit, as valuable insurance against spikes in fuel prices, protection against liability for- and damage from-pollution, and the possibility to benefit from carbon markets under California's new greenhouse gas reduction law. This GEO plan presents three South Bay Power Plant replacement scenarios with portfolios that contain mixes of wind with pumped storage, solar concentrators with gas backup, as well as photovoltaics and natural gas cogeneration. The GEO can be combined with conventional electrical capacity from available wholesale markets. Facilities are modeled according to two basic criteria: they would generate power at prices competitive with wholesale market power prices, and could provide this power within the portfolio of electric service under a Community Choice Aggregation. Thus, the GEO presents these investments in an apples-to-apples comparison with both wholesale peak and base load power prices, and reflects potential changes in natural gas and electric generation prices in SDG&E's rates, which are subject to change every six months.' The purpose ofthis modeling is to provide real, buildable, financable, and feasible investments that can eliminate the need of the Independent System Operator for the South Bay Power Plant, and can also be sound public investments in green power generation and conservation facilities. The investments are also described in a suitable manner for a CCA to incorporate these assets in a larger portfolio to supply its full electric power needs and compare this to SDG&E retail rates. This GEO may be adopted by the City of Chula Vista, and may be followed by drafting and adoption of a CCA Implementation Plan and Request for Proposals to solicit bids from suppliers, who will conduct a full CCA portfolio analysis and enter into a contract to build facilities and provide power service to participating communities. What this report does establish is that investments in a diverse set of peak power assets could benefit Chula Vista and surrounding communities over a 30 year expected equipment lifecycle, especially in the context of a CCA, and secondarily in the context of a municipally financed, locally developed green power facility. , This document contains forward looking projections about the prices of commodities and infrastructure; Local Power in no way warrants or guarantees, or will in any way be held liable for, such investments. All investments carry risks, and it is the responsibility of those who make such investments to verify all claims, and assume all associated risks, express or implied. 13 Local Power Alternative Energy Plan for Replacing the South Bay Power Plant February, 2007 If implemented, anyone of the proposed scenarios would form a landmark achievement following a decade of growing leadership in energy independence and entrepreneurial sustainability in Chula Vista. It would also be a positive, substantial contribution toward international efforts to reverse the Climate Crisis. The Proposed South Bay Replacement Project The existing South Bay Power Plant, over 40 years old, is outdated, inefficient to run, and has significant adverse water and air quality impacts. There is little disagreement that the existing plant needs to be shut down. The plant has materially damaged the South San Diego Bay ecosystem and creates significant air pollution. The power company LS Power, all of whose merchant power plants (including the South Bay Power Plant) were recently acquired by Houston-based Dynegy" is in the permitting process for a South Bay Replacement Project (SBRP) which includes the demolition of the current South Bay Power Plant and the construction of a new gas-fired power plant near the current site. The SBRP is proposed as a 620 MW net combined cycle generating facility using two natural-gas-fired combustion turbine generators and one steam turbine to be cooled with air cooling. The proposed South Bay Replacement Project would not use Bay water for cooling, which represents a significant environmental improvement. The SBRP would, however, still create a substantial air pollution hazard for neighboring residents. Like the existing plant, the proposed replacement plant would be directly upwind of residents and schools, and would perpetuate degraded air quality for west Chula Vista residents. The west Chula Vista zip code registers childhood hospitalization rates for asthma that are 20% higher than the overall county rate in 2003.' The SBRP is being promoted as a plant that will reduce air pollution impacts. Although more energy is expected to be generated for the pollution produced, total pollution impacts to the densely populated low-income neighborhood that is immediately downwind of its smokestacks are not expected to be appreciably reduced, and in fact may even increase. Though a new plant would be more efficient, it is planned to run far more often and bum more fuel, and so could produce comparable if not greater total pollution. The California Energy Commission and the SBRP project proponents have not yet come to an agreement on the estimated pollution impacts from the proposed project. We estimate that total particulate matter pollution could increase from about 73 tons per year to about 94 tons per year when comparing the existing South Bay Power Plant to the proposed replacement plant (Appendix H). The LS/Dynegy project offers no mitigation or additional offsets for impacts to air quality, and claims that particulates will remain the same as the current plant without giving adequate information to back up this claim. The existing South Bay Power Plant is a significant contributor to greenhouse gases, large enough on its own to have a significant climate impact (approximately l/IO,OOOth of global greenhouse gas emissions). The proposed new gas-fired replacement plant would continue to contribute significantly to the global climate crisis, when excellent local solar and wind On September 15, 2006, Independent Power Producer Dynegy announced it has agreed to pay more than $2B in stock and cash for the merchant plant portfolio of private equity fund LS power Group, including SBPP and eight other power plants acquired from Duke Energy for $1.6B in May. LS Power Group will retain a 40 percent stake in the combined company. Dynegy's management team, including CEO Bruce Williamson, will run the company. 4 California Office of State Planning and Development, 2003 Public Patient Discharge Data; 2000 Census. 14 L.oc,lll't'\Yt'r AlkIT1;:ltive Fm'Tg)' l'Lm tor Replacing lht' Suuth I:)"y 1'0Wt'f [)I,lnt h'nruan', 2()[)7 conditions are available for renewable generation of electricity, as this Plan has surveyed, analyzed, and modeled. The important question at hand is how the energy capacity provided by the existing plant will be provided. This decision will shape the region's energy future and the health of Chula Vista residents for decades to come. The current replacement proposal does not adequately assess viable alternatives for the power plant design, as required by US and California state law, nor has there been adequate assessment of the ability for other already permitted and proposed plants in the region to meet the goals of the project. Meeting the Appropriate Energy Needs Any replacement of the plant with renewable resources must address regional power needs. The scenarios for Chula Vista in this report will present model solutions on a graduated scale to ensure that regional transmission grid requirements of the California Independent System Operator (ISO), the non profit agency charged with maintaining transmission grid stability, would be met in each proposed scenario. The Green Energy Options portfolios presented here are designed to meet the energy service provided by the existing South Bay Power Plant. The California Independent System Operator's (ISO) designation of the South Bay Power Plant as "Reliability Must Run" ("RMR") requires that it provide peak energy production to ensure regional electric system reliability. SDG&E has built - and is still building - new power plants and transmission lines connected to the regional grid. As a result, the ISO's designation of need for power generation from the South Bay Power Plant is changing. This report presents three portfolios that would replace 50%, 70% and 90% of the existing 700 megawatt capacity of the 2006 RMR contracts on the plant. (the 2007 RMR contract is lower, at 515 MW). The portfolios are designed to meet a range of possible RMR demands so that changing ISO requirements can be met with little or no adjustment to the portfolios. The Reliability-Must-Run (RMR) role that the South Bay Power Plant serves is related to the plant's capacity, or the most that the plant can produce at a given instant, measured in megawatts (MW s). The plant's electricity service can also be thought of in terms of how much electricity capacity it provides to the grid over a period of time. This is measured in Megawatt Hours (MWh). The South Bay Power Plant currently runs essentially as a load-following plant that ramps up output at times of highest demand in the afternoon and evening, and a large portion of the plants capacity is rarely used. This is further explained in the next section of this report. On a capacity basis, 700 megawatts of the South Bay Power Plant are under contract with the ISO for 2006 (515 megawatts for 2007). On a megawatt-hour electric generation basis, the current plant produces about 1.9 million Megawatt-hours per year.5 Notably, the proposed South Bay Replacement Plant would only provide 120 megawatts of added peak energy, far less than the current plant or the GEO options do. LS Power. Application for Certification to the California Energy Commission for the South Bay Replacement Project. Pg 6-2 15 Local Power Alternative Energy Plan for Replacing the South Bay Power Plant february, 2007 3. ISO Reliability Must Run (RMR) Criteria Analysis & Scale of Replacement Energy Needs Other than a much cleaner and more sustainable power source and competitive pricing, the other main criteria for the scenarios in this report are that each must conform to the ISO's Reliability- Must-Run ("RMR") designation of the current South Bay Power Plant (SBPP), and that any replacement portfolio must fulfill the current function of the plant, which is to provide power during the peak hours of the day. There are a number of variables that will impact the final ISO designation for the site, including adjustments in predicted regional demand and other regional generation assets. These can change significantly from year to year, and it is not uncommon for projected requirements to be revised downward to lower levels. For 2007, the ISO will seek contracts on only three of the four units at the South Bay Power Plant. 6 This will result in a reduction to 515 MW under RMR contract. 7 In the recent past, opinions on the need for replacement power on the Bayfront have run the gamut from nothing more than a substation to maintain grid stability, to massive power plants upwards of 1200 MW. As utility forecasts often change, or may be manipulated, Chula Vista should evaluate a range of options to fulfill the energy needs required to replace the existing SBPP. Chula Vista would be free to pursue any of the scenarios described in this report with projects that range from 10 Megawatts of local photovoltaics to a 400 MW wind farm. First we will examine factors related to the current scale and use of the South Bay Power Plant, and then discuss several variables in play that should be addressed prior to establishing the real size of the RMR deficiency, if any, that is needed to be filled by a replacement plant. Capacity factor is the normal way in which degree of plant utilization is measured. This is expressed with a percentage, which is calculated by taking the number of megawatt-hours generated over a year divided by the total number of megawatt-hours the plant could generate if it operated full time at full capacity. Because "capacity factor" is a compound of total capacity and hours of operation, the concept creates some ambiguity. For example, a power plant operating at a fifty percent (50%) capacity factor could mean that it is running at half its rated capacity all of the time, or it could mean that the plant operates at full capacity half of the time. Or, it could mean any varying level of operation between these two extremes that created the same mathematical result. The operation of RMR facilities is complex, as they may run at various levels at different times of the day and year. Then they may be suddenly asked in the summer, when other resources are strained, to ramp up to full capacity for just a few hours. 6 Motion: 2006-09-G 1 Decision on Local Area Reliability Services Requirements for 2007 California Independent System Operator. Local Area Reliability Service 2007, Report of Gary DeShazo, August 31, 2006. 16 L.UC(l1 ['o\\'t'r i\llt'rndtiYl:' t:n\'rgy ['];111 fur Rl'pl'Hillg tlw SUlllh 8;w !'U\\L'r I'Lml hc+nu,H\', 2()\l7 Current Scale and use of the South Bay Power Plant Any replacement facility or facilities will have to fill the specific role served by the existing South Bay Power Plant. This plant is composed of four main generator units that together are considered to have 690 megawatts of dependable capacity. The following table shows some basic facts about the generating units at the South Bay Plant: Table 1. Operating ProfIle of the existing South Bay Power Plant. Dependable U. . B '1 C' . Output per Year Capaci" FucllJse Heat Rate mt 1II t .apae." . (MW)' (\'" h) Factor (MI\1Btu) (Btu/k\\h) 1 1960 147 459,135 0.357 4,654,5 31 10,138 2 1962 150 466,098 0.355 4,400,057 9,440 3 1964 171 319,847 0.214 3,312,646 10,357 4 1971 222 84,940 0.044 1,023,633 12,051 Total 690 1,330,020 0.2208 13,390,867 10,068 Source: Resource, Reliability and Environmental Concerns of Aging Power Plant Operations and Retirements. California Energy Commission, Aug. 13, 2004, 100-04-005D. In addition, there is a 16 megawatt combustion turbine, bringing the total capacity to 706 megawatts. The 2005 RMR evaluation by SDG&E rates the units a little differently and comes to a total of 689 megawatts for the four larger units, which would lower the plant total to 705 megawatts. In general, power plants as they age lose a small amount of rated capacity. For the sake of this report we assume a rounded total of 700 megawatts for the rated size of the power plant in 2009. The actual capacity requiring replacement is likely to be significantly less, and by a much larger factor than this marginal adjustment, for reasons described in this report. Since the South Bay Power Plant is old and inefficient, it is not desirable to have it running most of the time. This is mainly because it consumes more fuel than competing plants, and thus cannot recoup its fuel and other costs unless the price for electricity is high. High prices occur during the peak hours of the day, when other expensive power sources are also brought on line. The actual cost of running the plant is a function of the cost of natural gas fuel, the efficiency of the generators, and the fraction of the time the plant is running. The less the plant runs, the more expensive the electricity is. The fuel cost for natural gas is given in dollars per million British Thermal Units (MMBtu), which is a standard measure of energy content. It is the energy in very close to 1000 cubic feet of natural gas. Prices for natural gas on the New York Mercantile Exchanges (NYMEX) are around $7.00 per MMBTU for near term futures contracts. This is The SBRP AFC before the California Energy Commission lists the current capacity rating as 30%. 17 Local Power Alternative Energy Plan for Replacing the South Bay Pcn'\'er Plant February, 2007 triple the prevailing cost of natural gas during the 1990s, but considerably lower than the historical highs following hurricane Katrina in 2005. Higher natural gas prices have a dramatic effect on the cost of generating electricity, particularly for aging facilities like the South Bay Power Plant. The following table estimates how much it costs to generate electricity from the four South Bay Power Plant units at different prices for natural gas. The lowest price, of$6 per million BTU (about 1000 cubic feet) is on the low to mid range for recent prices of natural gas for electric generators, while $8/ million Btu is near to the average projected price for natural gas by the US Dept. of Energy for the period until 2030. Most analysts expect a long term trend of increasing natural gas prices, and the DOE projects a nominal price of $11.74/million 8tu in the year 2030, which is reflected by the upper range in the table below. Because the financial life of an electric generator built over the next few years will continue in operation well beyond 2030, it is very likely that even higher prices will be seen during that period. Note that a new power plant could have even higher costs, because the increased efficiency would be more than offset by the increased capital cost: Table 2. Approximate cost of generating electricity (in nominal cents/kilowatt-hour) with the South Bay Power Plant and with a new gas-fired replacement peaker plant. Unit lIeat Rate Capacit) (Btu/k"h) Factor -- ,Varllro! (ius prill;:) OhT Inmbtll) $6.00 $8.00 $10.00 $12.00 I 10,138 0.357 7.8 9.8 11.8 13.8 2 9,440 0.355 7.4 9.2 11.1 13.0 3 10,357 0.214 9.0 11.1 13.2 15.2 4 12,051 0.044 20.9 23.3 25.7 28.1 Total SBPP 10,068 0.220 8.8 10.8 12.8 14.8 Modern equivalent 9,400' .220 11.9 13.8 15.7 17.6 Source: California Energy Commission The capacity factor for the current four generators ranges between 4.4% and 35.7%. In general, we have chosen to assume a 32% operating capacity for the GEO options for a variety of reasons. It falls within a feasible range of performance of renewable facilities; it allows a common baseline of comparison for economic purposes; and it allows financial targets to be met. It may turn out, however, that the optimal capacity factor for any future plant may differ from what we have assumed. The plant owner and operator should evaluate market conditions, such as the value of peak power and the price of natural gas. It may also be advantageous in some cases to sell power outside of the peak period for supplemental income. The wind plant is specifically designed in this manner in that it is oversized compared to the needs of the pumped storage. This will allow for additional electricity sales that offset higher cost peaking resources. Similarly, the natural gas plant might be operated at a higher capacity factor to serve reliability needs of the wind plant during hours when its peaking service is not required. This would supply additional 18 IDe;ll ]'()Wl'r Altl'!"ll,ltin-' \:m'fgy I'bn rur Replacing the Suuth lLw l\nvt'T 1'1,1111 rPDruarv,2nU7 revenue that could offset the natural gas plant costs or improve the value of the wind plant by providing firm electric generation. Current RMR Contract with the ISO Until 2006, the full South Bay Power Plant was bound by a contract with the California ISO, the agency responsible for the operation of the state's electric grid. This contract, called a Reliability Must Run (RMR) agreement, requires the plant to remain available up to its full capacity in order to assure the reliability of the electric system in the San Diego County Region. However, in January 2007, it was reduced by 174 MW to 515 MW, with the releasing of unit #3 from this obligation. RMR contracts are effective for one year, and the contract on unit #3 could potentially be reinstated in 2008 if the ISO and plant operator agree. The RMR contact is particularly designed to assure that power plants are available during times of high demand, when other grid facilities, including generators and transmission lines, are being fully utilized and need extra support. The full power of all four generator units is rarely needed for actual operation, but they all must be on call if needed. This is particularly true of generator number four, the largest and least efficient of the units, which only operates a small fraction of the time. Variables that Influence RMR Calculations and Designations There are a number of variables that influence RMR designations. These must be accurately evaluated to establish the real size of the RMR requirement. Peak Demand and Types of Power Plants During the course of a day, electric power consumption reaches a low level around 3 to 4 o'clock in the morning. Then demand rises like a great wave during the day until a peak demand occurs, any time between noon and early evening. After the peak, the daily power demand wave ebbs and then returns to its lowest level again early the next morning. This is a "typical" daily pattern, though there is significant variation in different locations, on different days of the week and in different seasons of the year. It is the responsibility of the electric generators, state regulators, and the business enterprise that purchases power for customers, to ensure that the available electricity on the grid always meets or exceeds the demand. This is critical, since even a small shortfall in generation can cause disruptions of service ranging from poor quality power, to rolling blackouts, or complete collapse of the grid. In response to this daily wave of demand for electricity, power plants are differentiated into three main functional types. A generator is used most efficiently, and is cheapest to operate, if it is run 24 hours a day at a steady rate. Those that run 24/7 are called base-load plants. A second type of power plant increases and decreases its level generation of electricity to follow up and down the daily demand wave. These are referred to as load-following plants. Because they are less efficient, the electricity from these plants is often more expensive than the electricity from a base-load plant. 19 Loca J Power Alternative Energy Plan for Replacing the South Bay Power Plant February, 2007 The third type of plant is only turned on for short periods when the power needs spike upward, and cannot be met by the base-load or load-following plants. These are called 'peaker plants'. Since this is the least efficient way to use a power plant, this is the most expensive source of electricity. Due to its extreme age and inefficiency, the South Bay Power Plant has been essentially changed over time from a base-load to a peaking facility. However there is considerable difference in the degree to which the four generator units are used. Firming lip the Capacity of Renewable Generation Some renewable energy sources, sllch as wind and solar power, generate varying amounts of electricity on their own schedule rather than in accordance with the needs of the electric grid. For example, wind turbines in California tend to be most productive in the summer evenings when the coastal winds pick up. This is usually after the time when solar energy facilities have dropped out, but demand from residential customers is high. Yet, the wind often continues into the night, long after the demand has fallen and thus does not fully match the peak needs for electricity . On the other hand, solar energy facilities typically are producing during peak hours in the middle of the day. Flat plate, stationary photovoltaic modules pointing south and angled toward the mid-summer sun will begin producing small amounts of electricity early in the morning, peak in production around noon, and gradually decrease in output over the afternoon. Thus there will be no solar power available to meet the high evening demand that often lasts to 10 or 11 pm. On top of the above problems, individual solar energy systems can be interrupted when, for example, the sun is behind a tree or a cloud passes overhead. Low winds can cause a wind plant to produce little or no power, while short gusts can cause sudden spikes in output that cannot be absorbed by the grid. The three significant technical shortcomings to renewable electricity sources such as wind and solar energy are: . The production of electricity cannot easily be increased or decreased in response to electricity demand. The resources are subject to short term, unpredictable fluctuations that may be difficult to integrate into the grid. Natural cycles do not necessarily match the exact time, or full duration, when added power is needed. . . There are means to address all of these problems and "firm up" the supply of power. Renewable generation facilities and other support systems can be joined together in a variety of ways to cancel each other's idiosyncratic production patterns, and to supply power when it is needed: . Geographic separation. Spreading out generation units, such as wind turbines, over a wide geographic area helps greatly to regulate the combined output, since it is very 20 L.()((lll\l\\'l'l f\lkrndtiVl' Energy ('J.,n Illr Rt:pl,'(ll\g tIll' SOllth lL)V l)o\\er l'l(lnl February, 20(17 unlikely that the wind will suddenly dip or spike in all locations at the same instant. In the same way, if solar energy systems are widely dispersed, there is little likelihood that a small cloud will cover them all at the same time. · Integration of intermittent generators. This involves using different types of renewable generation, such as solar and wind, together in a way that provides a more robust service. The sun allows for production during the day, while wind picks up in the evening. · Integration with conventional generation. A common practice is to back up the solar or wind power with existing sources of power from the grid. This usually comes from a peaking or load-following gas fired power plant that is coordinated to the measured output of a wind or solar facility. In other cases, the gas generator may be built together with the renewable facility, and share the same transmission wires. This maximizes utilization of the power line, and can avoid the surcharges that are often levied against wind plants that need to reserve more line capacity than they can reliably use. An even better source for back up of renewables that produce intermittently is hydroelectricity, which has the extraordinary capacity of being able to respond almost immediately to changes in the electric system. It can use this ability to enhance the efficiency of wind farms. · Integration with power storage systems. Power storage, such as batteries or flywheels, can absorb extra power from a wind or solar facility, and release it at times when the power is most needed. This allows the solar and wind generators to be fully "dispatchable", meaning that they can be tapped when they are needed most. Batteries and flywheels are useful for relatively modest power needs, for a single building or for very short periods of time on a larger scale. Much larger amounts of power can be stored by using the renewable generation to pump large quantities of water from a lower to an upper reservoir. When the power is most needed the water is allowed to flow downhill through a turbine powering an electric generator. This sort of technology has been used for many decades. Almost all conventional energy storage systems are efficient, but they can add significant cost. · Integration with demand response and energy efficiency. Photovoltaic facilities are always better investments when combined with energy efficiency and conservation measures. A more advanced application is to use these tools in a coordinated way to provide reliability for the grid. San Diego Regional Electricity Supply and Demand San Diego County's electric system is essentially an island connected to the outside transmission system at two points. One of the transmission connections is in northwest San Diego County leading toward Orange County (WECC Path 44). Path 44 is the only connection into the rest of the California ISO system. The other transmission connection, the Southwest Power Link (SWPL), begins at the Miguel substation east of San Diego and heads through the east county, just north of the Mexican border, and then leads into the Imperial Valley. This 500 kilovolt line allows for power to be brought in from generator plants in Arizona. The total import capacity of the two transmission corridors is 2850 megawatts. The 2005 projected peak electricity 21 Local Power Alternative Energy Plan for Replacing the South Bay Power Plant February, 2007 generation requirement for SDG&E was 4370 megawatts, meaning that 65% of the summer peak demand could be met by electricity imported through the transmission wires alone. The electric resource potential is defined by the generation resources inside the country and the import capacity at the two transmission entry points. ISO rules require that the regional grid be rcsilient to some degree against failure of system components; specifically the grid must have resources to withstand the removal of the largest generator and one transmission line. This is referred to as the "G-l/N-l" criteria. These criteria require that all reliable resources be added up, and then the largest generator and one transmission line are subtracted. For this purpose the 350 megawatt capacity of the Southwest Power Link line is subtracted from 2850 megawatts of total transmission capacity to result in 2500 megawatts of capacity that is considered to meet the reliability criteria. The main generator resources are 945 megawatts of steam generators (of a total 971 MW) at the Encina Plant, 689 megawatts of steam generators (of 706 MW) at South Bay. In 2005, there were another 395 megawatts of capacity under RMR contracts, including the remaining capacity at Encina and South Bay that are gas turbines. This brings the total RMR generator capacity to 2030 megawatts. In San Diego County the largest generator for 2005 was the 329 megawatt unit at Encina, called Encina 5. The largest generator in the region contributes nothing to the reliability requirements except to serve as the discounted resource. Similarly, one transmission line is worth 350 megawatts of carrying capacity, and also gets subtracted from the total. The available resources are then compared with assumed projections about future peak demand, which is based upon a probabilistic model. The generators and transmission capacity are supposed to meet a spike in demand that has a 1 in 10 year probability of occurring. The following table shows in summary the region's 2005 resources as calculated by SDG&E. Table 3. SDG&E 2005 RMR Resource Calculation Capaeit) Cumulative (MW) Total C\lW) Peak Demand plus line losses 4370 4370 Transmission Import capability -2850 1520 N-lloss of one transmission line 350 1870 QF generation resources -180 1690 Removal of largest generator (Encina 5) 329 2019 Designated RMR units -2030 -11 While the above was valid for 2005, significant changes occurred in 2006. Specifically, the Palomar facility was brought online, making it the largest generator in the region; Encina 5 lost its designation as the subtracted generator. Since about 8.6% of the electricity produced by generators is lost in the transmission and distribution system, this loss must be added to the peak demand in order to figure out how much the generators need to produce. Thus, included in the 4370 megawatts is about 375 megawatts of power lost in the electric grid, mostly in the form of 22 L.lhdll'uv,'l'r '\Ikrntlti\ Ie' Enngy l'ldn for Rl::'plal'ing t]ll' Suuth I:Ll}' Pll\\l'J' Pldll! FL'bru,Hv,2()()7 dissipated heat caused by the electrical resistance of power lines and transformers. This is important, because the 8.6% loss is avoided whenever an energy resource is placed where the demand is located. Partly for this reason, utility companies like to consider on-site generation, like photovoltaic systems on a customer's roof, as removed load rather than as generation; it makes the calculation of the power resource simpler for them. When you take the total requirement to meet demand and subtract all available resources, then the result for 2005 was a negative II megawatts. This means that there was II megawatts more estimated electric system resource than was required to meet RMR criteria in that year. Retirement of the South Bay Power Plants' 700 megawatts in 2009 would have to be replaced with other resources in the form of new generation within the county, new transmission to bring power into the county, or peak demand reduction. These resources not only must replace South Bay, but they also must meet future growth in demand in the SDG&E territory. This requirement can be met in a number of ways without any need to build new transmission capacity that goes out of the county. In addition, at a meeting of the Energy Working Group representatives of ISO and of the Resources Subcommittee stated that there were several options to close any reliability gaps, and that building several smaller power plants would be a better option than a large base-load plant9 Addition of New Power Plants Two new power plants have been brought on-line since the resource calculations were made by SDG&E in 2005. A 44 megawatt peaking plant in Escondido (MMC) and the 546 megawatt plant at PalomarlEscondido built by Sempra. This adds a total of 590 megawatts to the region's power generation; nearly the anticipated replacement capacity for the South Bay plant. Since the Palomar plant is now the largest generator, the Encina 5 plant adds back its 329 MW. Future Power Plant proposals An additional 561 megawatts of capacity has been permitted and contracted at Otay Mesa, with an anticipated on-line date of January, 2008. This project has been postponed a number of times, leading to questions about when and if the power plant will be completed. Yet, if this power is brought on-line, as is expected since a long-term contract was signed with SDG&E, then there will be major implications regarding the South Bay Power Plant. So large is this addition that it will certainly reduce, and may even eliminate, the need for an SBPP replacement. A 22 megawatt biofuel plant has also been announced, bringing the total possible additions to 612 megawatts in the SDG&E system by the 2009 retirement date of the South Bay plant. A proposal by ENPEX for the Community Power Project could result in electric generation capacity located at the Sycamore Substation of750-1500 MW, proposed to be operable by 2011. 9 "Ms. Hunter asked whether options to close the gap were evaluated in the CAISO study. Mr. Shirmohammadi explained that there is a multitude of ways to address this issue but that large power plants were not the solution to the problem. Mr. Shinnohammadi stated that if building more power plants were the decided route, building several smaller one would be a better option." Minutes ofSANDAG's Energy Working Group, July 27, 2006,p.13 23 Local Power Alternative Energy Plan for Replacing the South Bay Power Plant February, 2007 Local 'I argctcd Upgradcs in Transmission The San Onofre Nuclear Generator Station (SONGS) has 2200 megawatts of capacity. The SONGS facility is jointly owned by San Diego Gas and Electric (SDG&E), Southern California Edison (SCE), and two municipal utilities. SDG&E's share is 20% of the power output, or 440 megawatts. Even though the nuclear plant is in San Diego County, it is not included in the resource base. This is because it relies on the northern transmission line (WECC Path 44) for moving its electricity into the rest of the county. Therefore it takes up transmission capacity and effectively removes 440 megawatts of power from being brought into the region from out of the county. One option would be to add to the transmission system within the county, using existing rights of way, to bring the SONGS electricity far enough south into the regional grid so it does not block the northern imports. An additional factor to consider is the planned decrease in capacity of the nuclear plant. The past 440 megawatt share is expected by SDG&E to be reduced to 377 megawatts by the year 2009, and to 311 megawatts thereafter. This means that the actual capacity advantage of the new transmission line may be 311 megawatts in future years. ~:ncrgy Hfieicney and Loading Order Rcquin'nH'nts New electric resource plans are required to follow the state's new concept of the "loading order." The loading order requires utility companies to make energy efficiency resources their top priority, above conventional generation. New resource planning since 2004 must include energy efficiency resources that were not included in the earlier RMR calculations. Energy efficiency may reduce resource needs, if the removed load occurs during times of peak demand. Lowering the amount of street lighting, for example, would reduce energy consumption, but does so mainly at night. It thus would be of little value in meeting RMR requirements. A much better approach would be to implement higher efficiency air conditioning, forced ventilation to cool buildings at night, or improve insulation and ductwork. This form of efficiency usually corresponds well to patterns of peak summer demand, when electric system resources are most strained. I)cmand R('sponsc Demand response is an agreement with the utility company, usually by large commercial or industrial customers, who agree to reduce their electricity consumption during hours of peak demand. This reduction may result in absolute savings in their consumption, or they may simply defer electricity usage until hours when the demand reduction is not needed. Whether or not Demand Response reduces electricity consumption, it does reduce the total load during peak hours. This reduces the need for new power plant capacity. It also means that there is less need for operation of power plants that would meet the peak demand. In fact, typically the dirtiest and least efficient plants would be removed from operation first. So, Demand Response reduces fuel consumption for power generation and reduces pollution. A Demand Response contract can be considered equivalent to power plant capacity as far as reliability is concerned, and is actually worth more than a power plant due to avoided electrical line losses. 24 L.u("II'(HVl'1 Altnn,ltin' Em'l~Y ['I"n fur Rt:'p1.H~il1g tlH' SOllth Hd)' Ilm\l'r 1>lo1nl February 20()7 Distributed Generation Distributed Generation ("DG") includes any generation capacity that is installed near or at the location where the electricity is consumed. Particularly relevant is any form of solar energy, such as photovoltaics, that meets peak demand, or Combined Heat and Power (CHP) plants, which generate electricity whenever it is required. The amount of CHP is unpredictable at this point, but there is a major expansion in the works for photovoltaics in the state due to the California Solar Initiative, which should result in the installation of 100 megawatts per year, or more, over the next decade in the investor-owned utility regions. As San Diego has excellent solar resources, and the highest utility rates in the state, it would be reasonable to assume that up to 10 megawatts of photovoltaics will be installed each year in SDG&E service territory. By 2009, this could add 30 megawatts to the region, of which 60% might be considered to be reliable for the RMR criteria. This will add 18 megawatts of reliable demand side resource, to which about 9% must be added to make it equivalent to generation side resources. Thus, 18 megawatts of reliable photovoltaic capacity would be worth nearly 20 megawatts ofRMR capacity. Existing and Future Energy Supply and Demand The following table summarizes the existing and future potential resources by 2009 that have been discussed above, none of which were included in the SDG&E forecasts in 2003 as reliability resources. It shows the possibility for an additional capacity of 1848 megawatts, without any more new power plants than those already announced, and without any additional transmission projects for bringing in power from out of the region: Table 4. Actual and Potential New Peak Resources for SDG&E between 2003 and 2009. Stratcg) Capacit) New Power Plants (2003 to 2006) Planned Power Plants (online 2007 to 2009) Upgrading SOS transmission (within county) Uncommitted Efficiency in 2009 Dispatchable Demand Response in 2009 Distributed Generation in 2009 590 Megawatts 612 Megawatts 311 Megawatts 55 Megawatts 260 Megawatts 20 Megawatts Total New Resources by 2009 (actual plus potential) 1848 Megawatts Of course, all these resources may not necessarily be up and running by 2009, but at least half of this capacity, including power plants already built, demand response, energy efficiency and distributed generation is a reasonable "base case" assumption. This would mean about 900 megawatts added to 2003 projected resources. In order to determine what level of resource is sufficient, the added capacity must be compared to projected demand. This is complicated by the fact that past demand projections have been overestimated. For example, in 2003 SDG&E submitted projections to the California Public 25 Local Power Alternative EnergyPlan for Replacing the South Bay Power Plant February, 2007 Utilities Commission that in 2005 they would need to meet a demand of 4504 megawatts, and that their resources could not meet this target. The projected shortfall was 69 megawatts. Two years later (in 2005), they changed the 2005 demand figure to 4370 megawatts, a downward revision of 134 megawatts. In addition, the 2003 SDG&E projection relied on the assumption that no power generation in the San Diego basin would come on-line between 2004 and 2023. Both of these assumptions turned out to be false. New resource requirements were all shown to be met by major new transmission lines that have so far proven to be unnecessary, 700 megawatts in 2008 and another 1000 megawatts in 2013. In fact, generation had come online before the end of 2005: revisions plus the 46 megawatt Miramar plant pushed the new resource requirements downward by 180 megawatts in just 2 years. The result was a robust 2005 surplus of III megawatts rather than the projected 69 megawatt shortfall. A comparison between projections is instructive. The revised November 2005 projection removes 605 megawatts from the generation resource requirement in 2016, compared to the 2003 projection, roughly equivalent to a full replacement of the South Bay Power Plant. This shows how changing from one projection to another can add or subtract the need for large power plants with relative ease. Table 5. Comparison of Demand Projections made by SDG&E in 2003 and 2005 ~- 2009 2010 2011 2012 2013 2014 2015 2016 Peak Customer Demand (2005 "base case") 3921 3984 4046 4109 4171 4232 4290 4348 Reserve Margin (15% Demand) 588 598 607 616 626 635 644 652 2005 est. Finn Peak Requirement 4509 4582 4653 4725 4797 4867 4934 5000 2003 Projection (90/1 0) 4937 5031 5125 5219 5313 5408 5506 5605 2003 Demand Overstatement vs. 2005 Base Case Projection +428 +449 +472 +494 +516 +541 +572 +605 Using the updated 2005 "base case" projection is thus equivalent to building a new South Bay Power Plant replacement. Note that this does not say that a replacement plant is or is not needed. Such a decision would depend on matching demand projection with actual resources brought online, and must subtract the capacity of any power plants that are retired. Yet, the comparison of projections just two years apart shows how important it is to keep an eye on revisions in projected demand. During the same period, between 2009 and 2016, additional demand response, energy efficiency and local distributed generation resources are projected, beyond the figures cited above. The following table shows expected deployment: 26 L.ol~cd 1\\\'\'l'l AlternutiVl' E,nergy I'Lm hlr RepLll"ing tilt' SOllth B.w I'u\\,(::'r l'l,lnt Fer-rUM\', 20m Table 6. San Diego Region Generation from 2009 to 2016 2003 Projected Generation (G-I) 1935 1935 1935 1935 1935 1935 1935 1935 New Generation 590 590 590 590 590 590 590 590 Retirement of SBPP -700 -700 -700 -700 -700 -700 -700 -700 Total Generation 1825 1825 1825 1825 1825 1825 1825 1825 Projected Transmission (N-I) 2500 2500 2500 2500 2500 2500 2500 2500 Transmission Plus Generation 4325 4325 4325 4325 4325 4325 4325 4325 (G-l/N-l) Efficiency 55 118 175 225 278 345 417 486 Demand Response (DR) 260 264 267 271 276 279 282 286 Distributed Generation (DG)! and - - - - - - - - CHP (to be developed with CEC) Total On-site Resources 315 382 442 496 554 624 699 772 (Efficiency plus DR and DG) Total Resources 4640 4707 4767 4821 4879 4949 5024 5097 2005 Peak Requirement 4509 4582 4653 4725 4797 4867 4934 5000 (including 15% reserve) Surplus!(Shortfall) 131 125 114 96 82 82 90 97 The above chart makes several assumptions. First, it includes only power plants and transmission line that have been brought online to date. Second, it relies on current projections for on-site resources, which excludes distributed generation and Combined Heat and Power (CHP) that may be added in the future. Requirements for including distributed generation in utility resources are supposed to be established this year by the California Energy Commission and the California Public Utilities Commission. Both agencies place high priority on distributed generation, so this should add significantly to the numbers on the resource side, or make up for potential shortfalls in efficiency and demand response projections. The scenario above also assumes that planned new in-basin generation, and the additional in- county transmission line in the South of SONGS (SOS) corridor, is not built. These combined equal another 923 megawatts of potential capacity, which if they were included could bring regular surpluses in excess of 1000 megawatts even with full retirement of the South Bay Power Plant. Yet, surpluses of 82 to 131 megawatts are projected even without the additional power plants or the SOS added transmission. This also assumes full retirement of the South Bay Power Plant, with no capacity replacement. 27 Local Power Alternative Energy Plan for Replacing the South Bay Power Plant February, 2007 In summary, the region has numerous options in addition to the Green Energy Options Portfolios presented in this report to replace the energy capacity provided by the South Bay Power Plant; a full capacity replacement should only be necessary if all the other options fail. The resources listed below can be used to meet projected demand requirements, replace a shortfall in meeting on-site resource targets, replace further generation capacity retirements, or meet an unanticipated increase in future demand. These options in total can add more than 2300 megawatts of electric system capacity, which should be able to meet the contingency needs of the county for years out into the future. The options include: . SDG&E fulfills its responsibilities to deploy demand response, energy efficiency, distributed renewables and Combined Heat and Power Facilities, adding 772 or more megawatts.1O . Future additional electric generation capacity, such as the Otay-Mesa Generating Station, and/or other smaller plants, results in 612 megawatts or more of new capacity. I I . Construction of the South of Songs Transmission line adds 311 megawatts of capacity.12 10 11 12 SDG&E, Annual Aggregate Energy Resource Accounting Tables, Appendix llA, Table B 17, November 15, 2005. California Energy Commission Energy Facility Status, updated February 18,2004. SDG&E, Annual Aggregate Energy Resource Accounting Tables, Appendix !lA, Table B17, November 15, 2005. 28 [nt.lll\l\\'t'l AltC1TI(lli\'\' FIWI)~~' [1),H1 f()f Rvpl'King tlw South g'l'y j'(l\Vt'f ]'Llnt 1\.I:HlldrV, 2007 Summary of ISO RMR status and Scale of Energy Replacement Needs The RMR rating for the South Bay Power Plant is a moving target partly because of new generation and transmission projects that are coming on line or that will be built in the future. Weare presenting three scenarios that provide capacity for different RMR replacement levels, as what capacity will actually be needed to replace the existing South Bay Power Plant's capacity is highly uncertain. Two different strategies are possible for addressing a high case RMR requirement. The first is to apply the highest, 90 percent replacement scenario. The second would be to supplement a smaller Bay front power plant with the smaller portfolio. The ISO board has removed the RMR status from Unit #3 of the South Bay Power Plant for 2007. Unit #3 is considered to 174 MW of dependable capacity. This reduced the total RMR burden on the SBPP down to 515. As the language of the Cooperation Agreement states the replacement plant only has to be as large as needed to remove RMR from South Bay, the solutions presented in this report will become significantly more affordable. Finally, there are a number ofresources that are not counted in the current RMR projections for the San Diego region. Some of these resources, such as demand response, distributed generation, and energy efficiency, are required by state regulation to come on line over the next three to ten years amount to literally hundreds of megawatts of capacity. Others, such as insuring the proper, full accounting for the Palomar Plant, and adding an extra transmission line on the existing corridor to the San Onofre Nuclear Plant, are least cost solutions for adding capacity. Addressing these issues is essential before any decision is made to commit hundreds of millions of dollars of ratepayer funds into a new bay front power plant, particularly when other solutions to the region's energy needs exist which are environmentally superior, carry lower risk, and represent a far better investment than betting the entire bank on natural gas. 29 Local Power Alternative Energy Plan for Replacing the South Bay Power Plant February, 2007 4. Green Energy Options: Three Portfolios for Cleaner More Sustainahle Energy for the Region This section outlines the Green Energy Options (GEO) portfolio alternatives to a new 620 MW replacement power plant, for a range of possible RMR capacities for the South Bay Power Plant. 90%. Replacement Capacity Green Energy Option Portfolio that replaces 90% of 700 MW Capacity . 400 MW Wind Farm with 150 MW Pumped Storage and Transmission project . 220 MW Natural Gas Plant . Solar Concentrator Plant powering a 160 MW Peaker with natural gas backup, . 20 MW Photovoltaics . 20 MW Peak Demand Reduction 70'Yc. Replacement Capacity Green Energy Option Portfolio that replaces 70% of 700 MW Capacity . 325 MW Wind Farm with 90 MW Pumped Storage and Transmission project . 190 MW Natural Gas Plant . Solar Concentrator Plant powering a 160 MW Peaker with natural gas backup, . 20 MW Photovoltaics . 20 MW Peak Demand Reduction 50% Replacement Capacity Green Energy Option Portfolio that replaces 50% of 700 MW Capacity . 150 MW Wind Farm with 60 MW Pumped Storage and Transmission project . 90 MW Natural Gas Plant . Solar Concentrator Plant powering a 160 MW Peaker with natural gas backup, . 20 MW Photovoltaics . 20 MW Peak Demand Reduction 30 l,(l(i11 !'O\\'l'l i\llt'rn,lti\'t' Energy ['lilll fur ReptlCing lhe South L3,1\ ['Ul\'t'l" PLmt Fl:'bruar\" 2()()7 5. Description of Green Energy Technology Options The three portfolio alternatives to installing 650-700 MW firm capacity generation replacement on the Chula Vista Bayfront utilize technology and investment options that are viable and ready for implementation, involving multi-year commitments of local jurisdictions that may be used to finance alternative energy portfolios and accelerate renewable investment in Chula Vista and throughout San Diego County. This section describes in detail these technology options and how they could be developed here. Hybrid Wind Farm & Pumped-Water Storage Facility Size Range: 150 to 400 Megawatt Capacity Wind Farm, 60 to 150 Megawatts Pumped Storage Cost Range: $170 to $540 Million for the Wind Farm; and $80 to $210 Million Pumped Water Storage Est. Power Cost from Wind Farm: Est. Power Cost from Wind plus Pumped Storage: (See Appendix A) 4.8 cents/kwh 9.6 cents/kwh A wind farm and pumped storage serve as insurance against increasing natural gas prices, as the cost is essentially fixed and is the part of the portfolio that is completely independent of fuel prices. Wind power also partly serves to round out load requirements that are not fully met by solar energy alone. While wind is intermittent, the pumped storage facility makes the electricity generated by the wind highly reliable and usable at any time it is required. Thus the pumped storage, while adding significant expense, also adds great utility and value. Wind power is easily the lowest cost renewable generation option, in the last several years globally averaging $1000 to $1200 per kilowatt of capacity for a large wind farm. High demand has recently pushed the cost of wind farms higher, with a range between $1300 to $1750 per kilowatt; the lower range should be achievable with good planning and also once manufacturing capacity catches up to demand. In fact, 2006 DOE projections are that wind farms should return to the previous low levels by the end of the decade, though our cost projections do not assume this. Should this happen, then economics of the wind farm will become very favorable. Wind turbines have become very reliable, and warranties on product defects cover investors from the most serious capital risks during the early years of operation. With proper operation and maintenance, wind turbines have a life expectancy of 20 to 30 years. The most important factor in the cost of electricity from a wind farm is the available wind resource. Wind power resource goes up geometrically in proportion to the cube of the wind speed. Thus, even small increments of average wind speed can make a significant difference in 31 Local Power Alte111ative Energy Plan for Replacing the South Bay Power Plant February, 2007 wind generation. It is critical first to find areas with the best wind and then to follow this up with careful measurements of at least one year at the locations under consideration. Wind resources are conventionally measured according to "Classes" ranging from I to 7. A class 3 wind is the usually the minimum for commercial development. A class 3 site would ordinarily only be used when other factors make it desirable, such as a location close to where the power will be delivered. For sites that require transmission of electricity over a distance, a minimum of class 5 is highly recommended. Parts of Eastern San Diego County have some of the finest wind resources in California (Class 5 and Class 6). A considerable amount of this area is in national park, forest or other protected areas, and thus is effectively off limits to development. However, there are high wind areas in the Southeast County that may be more suitable for a large wind farm (Figure 1). Figure 1. San Diego County Wind Resource Regions. --"" IoeCorps8ese ; " ! \ ~ \ ' 4~~~mIdo t~ fncInil..~, ~~ IN SolMa 8e8t:~:\~ I! i ' Del Mor)\'r' , "{-_Y/',',-,_" .~,.,~'m'.. ' ~~:::tc 1m class 6 Paelfk ~ \ Gl Cwlkm Grmde Ul \ Ocean "_ :t\., .1/" __'> _C:f'i.~~ . ',\ ''i,',<<,>'' ,', ,,"r-,. ~;.r-~,.<.~==o"""'" "",I'*r ) i,y i,i~ "":'...,,"'...."";_._', \'" . -Q.~~l '1':!:~,CIt~.Oro . aevel'nd"_lOnatfore't:,__,:_~1 ..,,;,.::;~.' :i~.~"r.DI::i~I':'~"'-= ~ \_.c';:~~:. ~~s 5 !1:Y '-, ..'.. \~.~. ,.0; . _ _' _ :_'~}i;: fI.___ ' Tecete, ._____ ______... RAJACAUfO _ _________':":.~s_ _ .. ._.",_,.:_::.~':"":"':-~M:~~ ____ __ __LIIJ}yl1:tQl'.Q~~~ lo. Coyote. .... l.aJoU, IA 'Wa''''' ........ ..,..,. ...."" ..... .i'.....~. '" _ :ti2' '\ . M"~a S~lI..1 GUnde V",abOIlR. I." :q,., C A l I F ,0 R .8:::t'.f:T. lien~'~)./' .. :"\(, ~~~~ 0"", -{~ '" '1~ : ;, . .~ ~~eIJ<lOellert St<t1I:'Pllrk ........... S t..14 DIE 0 rJ The second major factor affecting the cost of wind is financing. Private developers require significant rates of return that can add to the cost of wind. This is usually offset by the federal wind tax credit, currently 1.8 cents per kilowatt.hour paid for the first 10 years of the wind farm's operation. Since Chula Vista is not a tax paying entity it is not eligible for the tax credit, however its low cost financing resources using municipal bonds can essentially equal the benefit 32 I (lC.ll ['O\\'l'l Allt'rtl(lti\'t, Energy ['Ian tor Rcpl.lci!)g fhe SOllth Hi)'',' l\lH'l'1" l'l<-1nl h'brUM\', 10117 of the tax credit. This means development plans can be independent of federal tax policy, a frequent stumbling block for wind projects. In addition, the benefit of low cost financing extends for the full life of the asset, while the tax credit is limited to 10 years. Utilizing municipal financing for a large wind farm with class 6 winds would likely result in wholesale electricity costs of 5 cents per kilowatt-hour or less. This makes wind power competitive with the long-range expected cost of electricity generation from base load plants. Wind powered electricity can be sent directly over the transmission grid, but its variability means that it is not reliably producing power at the times it is most needed. To make the wind generation reliable, it must be backed up with other generation resources. Vendors of contract wind power usually make use of natural gas generation to provide a 24-hour base load service. Since this off-peak character of wind power is not part of the service provided by the existing South Bay Power Plant, selling the power to wholesale buyers or a CCA requires a way to transfer the energy output to those hours when it is needed, and the design of this component must be included (and is included in this Plan) in its financial modeling. In order to project the competitiveness of the large scale solar concentrator turbine facility and wind turbine facility, this Plan includes the fully integrated "Hybrid" packages rather than just isolated RMR-related component, investment scale, and paybacks. An energy storage system, which takes the power produced at night and makes it available during the day, is the way to achieve this functionality. Pumped Storage is the only affordable, practical way to store this amount of energy, in which water is pumped to the top of a reservoir at night when the wind blows, and the water is released the following day to run hydroelectric turbines. Modem systems allow for a single unit to serve both as pump and turbine, which reduces the capital expense. The GEO's proposed Pumped Storage facility places an additional cost for peak power that can add about 3 to 4 cents/kwh to the cost of energy that is used to pump the water into the storage. At current and forecast future natural gas prices, pumped storage can be competitive to projected peak power from competing natural gas power plants. Hybridizing the facility also enables the lower-cost wind power to offset the higher cost Pumped Storage power. This is because only a part of the power generated by the Wind Farm is used for running pumps on the Pumped Storage Facility, with the remainder of the wind power being sold as part of a competitively priced, stable energy supply. While pumped storage facilities can be expensive, their cost can be reduced by using existing reservoirs. There are reservoirs in San Diego County, most notably in the East County, which might be suitable from the standpoint of location, size and sufficient elevation drop below the reservoir. Also, the Lake Hodges Pumped Storage project may provide a feasible market for selling excess wind generation, and should be evaluated by Chula Vista and any partners. Finally, while Pumped Storage adds substantially to the cost of the Wind Farm's power, power delivered during peak hours has a large premium value in the wholesale power market. This facility will serve as a hedge should natural gas prices increase in the future, which is widely predicted. In addition, the pumped storage facility will outlast the wind equipment by decades. Once financing costs have been covered during the financing period, the pumped storage cost will be reduced to operation and maintenance, which means that the cost to generate electricity will be very cheap and the profit margins quite large. In this way, the pumped storage facility is a long term investment. 33 Local Power Alternative Energy Plan for Replacing the South Bay Power Plant Febmary, 2007 Hybrid So13l- Conc~ntrator Turbin~ with Natu.-al Gas Backup and Cogeneration Size Range: Cost Range: Power Cost without Cogeneration: Power Cost with Cogeneration: (see appendix B) 160 MW $350 to $450 million 10.2 to 12.2 cents/kwh 9.1 to 9.28 cents/kwh Solar thermal generators have been reliably delivering hundreds of megawatts of power into the California grid since the 1980s. This technology uses parabolic mirrors to collect light and concentrate the heat of sun onto a long tube filled with a fluid. These mirrors track the sun, and thus produce power all day long at a fairly consistent level in sunny locations. In one variation, the fluid transfers the heat to a second fluid, such as water, that turns to steam and runs a conventional turbine. The conventional turbine can also be run off of natural gas on days when the sun is not available. This provides a very high level of reliability while greatly limiting use of natural gas. Such a system can completely replace the functionality of the current South Bay Plant. One major problem with solar thermal generation has, in the past, been lack of availability. This limitation is rapidly disappearing, as new solar thermal manufacturers and installers are beginning to emerge all over the world, including in the US. Recently a one megawatt solar thermal power plant in Arizona was completed, and a 64 megawatt plant in Nevada is under construction. The I megawatt plant was quite expensive: at about $6000 per kilowatt it is 5 times more costly than equivalent sized wind farms. The larger plant in Nevada reduced the unit cost by about 40%, due to improved design, experience, and some economy of scale. This technology is expected to continue to decrease in cost, which will be necessary to make it directly cost competitive with peak power from natural gas generators. However, it is easier to acquire and permit real estate for Solar Concentrators, making it feasible in many areas of California where there is sufficient relatively level land. For a local resource, power prices from solar concentrators are expected in the next 5 to 10 years to become a competitive, locally available power source, especially when transmission already exists or no new significant transmission is required. The Nevada solar-trough thermal generating plant costs about $3500 per kilowatt, but the installer says that a larger plant of 160 megawatts, such as Local Power is recommending for Chula Vista, will be significantly cheaper. A combination of further development of the industry, and a larger scale project, should begin to make solar thermal technology directly competitive with long-term expected cost of comparable natural gas plants. The projection of $2500 per kilowatt is in line with industry expectations and DOE price projections. 34 L.uu1Il'o\.\'l'r .A.ltt-'ITldtiVl:.' energy l'Lln for R<-'pl.King thl' South I:Ll\' 1\J\\'t'r PLlIlt FehrlhlrV,2()()7 We also strongly recommend that a solar thermal project be co-located with a facility that can use and purchase the "waste" heat; an application referred to as co-generation or combined heat and power (CHP). This can make solar thermal generation significantly more cost effective, and also provide a secondary commercial development opportunity. Solar concentrators have been around for over a hundred years. We estimate that a 160 megawatt project would require approximately 900 acres; however, if the cost for solar concentrators continues to drop, a smaller facility may become economical. The sites mentioned in this report, such as those near Sycuan, and Ream Field, have been initially evaluated and may prove adequate in size and solar conditions to provide affordable local power. The resource for solar energy is optimal in the East County, but a development nearer to Chula Vista would corne close to matching the effective cost to produce electricity if transmission charges can be avoided. Further site acquisition and permitting analysis is warranted and land-owners would need to be solicited about their interest in such a project in a timely manner. A natural gas plant that provides assured power is an essential part of the portfolio. It provides a benefit if natural gas prices are lower than the threshold required to make the fixed cost renewables profitable. It is thus a kind of insurance should natural gas prices remain below current levels of $6 to $7 per MMBtu. But even if prices are sustained at $5 per MMBtu, the total portfolio cost of energy is only a fraction of a cent per kilowatt-hour above prevailing costs to run a natural gas turbine generating at an equivalent capacity, an increment that is less than half the premium that the renewables would have by themselves. This illustrates why the natural gas component is a critical part of the GEO investment portfolio. This hedge is more valuable than it would be for a private third-party investor, because the low return on municipal bonds decreases the expense of owning a power plant. This margin of savings is larger for a peaking plant than for a base load plant, since the cost of the plant becomes more significant as less fuel is consumed. The relative savings due to municipal financing, however, are not nearly as large as they are for highly capital intensive renewables like wind, pumped storage and solar thermal, where the fuel cost is very low to non-existent. 35 Local Power Alternative Energy Plan for Replacing the South Bay Power Plant February,2007 Photovol!aics with Energy Storage or Hemand Response Size Range: Cost Range: Power Cost: 20MW $120 to 160 million 25 to 30 cents/kilowatt-hour after rebates; 8 to 12 ceuts/kilowatt-hour for commercial owners who can also get tax credits. (See appendix D) Photovoltaic power is the direct conversion of sunlight into electricity using semiconductors. The most common semiconductor is a thin wafer of silicon with minute amounts of boron and phosphorous that gives the silicon an electric charge. The silicon wafers are mounted in panels that generate electricity any time they are placed in sunlight. The materials are highly durable, with some testing suggesting lifecycles as high as 80 years or more. Since the technology is modular and flat, the panels can be placed almost anywhere. Frequently rooftops are chosen, but shading structures over parking areas or placement in open areas are also frequently seen. Present full installed costs for small residential systems average about $9500 per kilowatt, while larger commercial or industrial sized systems average about $8000 per kilowatt, though some facilities have been installed for as little as $5000 per kilowatt.13 Over the next five to ten years, the cost of photovoltaics is expected to continue to decrease, and numerous technology options and economies of manufacturing scale will facilitate this. Photovoltaics are still one of the most expensive electric generation technologies, resulting in a full cost of electricity (before rebates) ranging between 20 and 40 cents per kilowatt hour. Yet, despite this fact, there are opportunities to make an investment in this technology cost effective. Deploying photovoltaic systems at the location where electricity is consumed gives it a premium value over the wholesale power which cost the utility company 5 to 8 cents per kilowatt hour. SDG&E sells this power at 13 to 18 cents per kilowatt hour to customers, and this is much closer to the cost of photovoltaic electricity. Photovoltaics, however, does not compete with the present cost of electricity, but rather with the expected cost of electricity over the next decades against which it represents insurance. This fact enhances its value substantially. (This point is also an important factor for evaluating the other renewables in the portfolio.) NOTE: Since photovoltaics, as envisioned in the GEO, are developed as generators at customer sites, and may even be owned directly by customers, they are not included in the wholesale electricity price calculations for the GEO portfolios. If customers take advantage of state rebates and tax credits, then the balance can be shifted decisively in favor of these solar energy systems. The fact that thousands of customers have taken advantage of subsidies shows that the potential market is quite large. The recently enacted California Solar Initiative provides rebates out to 2015, currently $2500 per kilowatt, and set to decrease when specified benchmarks of solar installation are met. Solar energy systems over 100 kilowatts in size will receive a performance incentive, paid out over a few years based on the electric generation of the system. Smaller photovoltaic installations will usually get their rebate at the time of purchase. In addition, businesses can take a tax credit for 30% of the installed cost 13 Data: California Public Utilities Commission. 36 L(H.',lll'nWt'r i\lterndtiVL' Energy ['],111 tur RL'pl'lling the Suuth H,)y ['ower J'l,lnt FebruoHV, 20()7 of the photovoltaic system until 2008. This will either revert to a 10% credit unless the 30% credit is extended, which several bills in Congress propose to do. Building to larger scale is another way to save on cost, as small home-sized installations can be about 10% to 20% more expensive on a unit basis. The economy of scale is not at present great enough to make building large photovoltaic generating stations cost effective, though this may change over the next decades as solar energy costs drop and electric rates continue to rise. Last year 1.5 billion watts of photovoltaics were installed around the world, about a ten-fold increase since 1995. During that time the average cost dropped by at least 35 percent. Installing two megawatts per year would require development of multiple sites, since the cap for rebates is likely to be I megawatt. Two megawatts was selected as an annual target as this is believed to be the minimum demand required to attract a solar panel manufacturer to the region to support part of regional goals for promotion and development of a green energy economy. Also, the electricity must be usable on-site and few customers use this much electricity. The cost would be about 12 to 15 million dollars per year, assuming large scale deployment and economies of scale. This range is likely to be valid until the end of this decade, though technology improvements will continue gradually to lower the cost over time. Cogeneration for peak capacity Cogeneration, also called Combined Heat and Power, uses thermal sources such as natural gas for more than one purpose simultaneously. The heat is first used to generate electricity, which typically only uses about 35 percent of the energy, though the most efficient modern combined cycle base load plants can reach up to 60 percent efficiency. The rest of the heat normally is wasted in the atmosphere, but cogeneration uses the heat to do further work. Normally this is for an industrial process that would use the fuel in any case, but now the fuel does double duty. This can raise the net efficiency to as high as 90 percent, which a substantial savings in both cost and fuel. There are also environmental benefits, while C02 reductions can approach even the most aggressive climate protection goals. The most efficient way to use combined heat and power is to match it with the on-site needs for heat. But using it intermittently for peak power also realizes significant savings and environmental benefits. This is an important way to help bring down the cost of solar thermal and natural gas peak power generation, though the expected efficiency levels are not as high as for base load plants. Energy Efficiency, Demand Response and Conservation Energy efficiency can also be turned into a peaking resource, if the load that is made more efficient matches the peak periods. Determining this may require some research into local demand patterns. Examining the load curves will show what sector the demand is coming from, but it is equally important to find out what appliances are creating the load at the particular time in question. Daytime loads might be offset by more efficient office lighting and other office equipment. Evening summer peak load in California frequently comes from air conditioning. Building insulation, sealing ductwork and building envelopes, measuring internal thermal flow and pressure patterns, and installing more efficient air conditioning are keys to addressing this late afternoon to early evening demand. Adequate training of personnel and inspection of air conditioning refrigerants also help. Any efficiency program requires the most stringent monitoring, which just as important as prescreening. The program should set clear goals that 37 Local Power Alternative Energy Plan for Replacing the South Bay Power Plant February, 2007 match the load requirements that the power plant currently fills, and they should be monitored for actual savings in kilowatt hours and peak building demand patterns. This is much more efficiently done in large commercial structures, but addressing the residential sector may be critical for offsetting the electric system's evening power demand. Demand response is far more easily accepted by the ISO as a legitimate power resource, particularly if customers in a demand response program are bound by usage contracts that specify when and how much demand curtailment will be applied. This is done by central dispatch, using automated controls, though up to this point such dispatch can be rather brutal. A CCA could create its own demand response program that allows for flexibility and customer choice. Importantly, such a program can be implemented with little capital investment, and forming an agreement with a customer is an ideal entry point for bringing in a wide range of attractive energy services, including photovoltaics, efficiency measures, backup emergency power, power conditioning equipment to assure high quality, and energy audits. Demand response is much more cost-effective with large commercial or industrial customers. Programs are more successful when the customer receives a financial reward, such as lower rates. Since many of these customers are on time-of-use rates, there is built in support in their electric rate structure. The key is to enhance this value while minimizing sacrifice from the customer. 38 I ,Ked ['(lwer /\ltt'rtldtiH' r;ntTgy [11,111 fur Rvpl(1cing tlw South l),lV ['ower ['I<Uli rt'lllll<HV, 20U7 6. Key Investment Mechanisms and Financing This section identifies the process and programs by which the City of Chula Vista could recoup their green investments and raise revenue. It contains an analysis of implementation structures that would be needed, financing, and public programs that support or affect clean energy projects. Community Choice Aggregation (CCA) Community Choice is a key strategy in Chula Vista's ability to develop the renewable energy facilities on a scale that will reduce or eliminate the need for generation on the SBPP site. CCA is technically easier to implement and less risky than a municipalization, but facilitates local control over energy resource planning. Under a CCA, Chula Vista would procure power on behalf of residents and businesses; SDG&E will continue to provide distribution, meter-reading and billing services, and would remain the Provider of Last Resort. CCA is an established, successful method of procuring competitively priced energy services. Nationally, CCA uses economies of scale to leverage lower prices, cleaner power and better service. Since 1997, CCA Laws have been passed by New Jersey, Ohio, Massachusetts, California, and Rhode Island. All of Cape Cod formed the nation's first CCA in 1997, and has provided electricity service and energy efficiency services at below-market prices since then. The Cape Light Compact is a regional services organization made up of all 21 towns of Cape Cod and Martha's Vineyard, and Barnstable and Dukes counties. The purpose of the Compact is to represent and protect consumer interests in a restructured utility industry. As authorized by each town, the Compact operates the regional energy efficiency program and works with the combined buying power of the region's 197,000 electric consumers to negotiate for lower cost electricity and other public benefits. The Compact provides I) Aggregated power supply 2) Consumer advocacy 3) Energy efficiency programs such as low income, residential, commercial and industrial, and education programs Cape Light Compact, emphasizes a comprehensive approach, undertaken with legal and technical support - as the electric industry continues in its transition to a competitive market. In Ohio, CCA represents nearly all of the state's competitive electricity market, with the Northeast Public Energy Council serving approximately 500,000 customers since 2000, with a 70% cleaner portfolio than utility service at prices consistently lower, even after changing suppliers. Forty California municipalities and counties are now evaluating Community Choice, 27 of them are seeking to double or more the state Renewable Portfolio Standard (RPS) targets. Apart from providing revenue for the repayment of renewable energy investments, CCA offers Chula Vis tans transparent, structured rates. "Political rate-setting" may be avoided by requiring prospective suppliers to "meet or beat" SDG&E' s current rates, be selected through a 39 LOCi! J Pm-ver Alternative Energy Plan for Replacing the South Bay Power Plant February, 2007 competitive bidding process, and commit to a locally-set rate schedule. Chula Vista, or a regional CCA, may set a Renewables Portfolio Standard (RPS) for the community and require suppliers to design, build, operate and maintain renewable energy and conservation facilities as portfolio components of the service. CCA enables a maximum level of performance risk to be placed on the energy rather than the City's General Fund. With significant revenues secured under a CCA contract, City program costs can be self-funded from a small increment of revenues. A single supplier approach allows for greater performance accountability, protecting both the City's General Fund and new customers against energy market risk. Double-Bonding may be used to insure risks associated with both commodity services and facilities construction. Finally, participation is voluntary. After the City signs a contract under specific terms, every customer will receive four notifications comparing the CCA's deal to SDG&E's terms, and be free to opt- out without penalty over a l20-day period. The repayment of Chula Vista energy investment may be made directly through CCA, or indirectly by selling power to another party. Directly, Chula Vista could provide for the power needs of its own residents, businesses and public agencies, guaranteeing power sales from a renewable energy facility integrated into the Specific Plan - delivering fixed prices and energy independence to the local economy. Indirectly, Chula Vista could build a facility to sell power to the Southern California Public Power Agency (SCPP A), or to the wholesale power market. With other municipalities in the region considering CCA, power may also be shared among CCAs. Either approach would enhance the uniqueness and sustainability of the renewable energy facility development and deliver profits to the city and significant local economic development - all at very low risk. Community Choice is an authority granted by California law (AB 117, Migden) that allows cities and counties to take charge of their own energy future. Under Community Choice, local governments can serve as a virtual "electricity buyer's cooperative" for local residents, businesses and government agencies. Unlike ordinary cooperatives, however, the day-to-day management for securing electricity supplies is managed by a qualified and experienced third party, while the local government is placed in the role of strategic planner. The government entity, called a Community Choice Aggregator (CCA), contracts with existing licensed suppliers called "Electric Service Providers" (ESPs). Other public entities, such as SCPP A or other inter-municipal association, may also purchase and sell power. ESPs are often the optimal vehicle because they are risk-bearing retail entities, in the business of providing reliable and cost-competitive electricity for large businesses and government agencies. About 12 percent of California's electricity is currently purchased from Electric Service Providers. If it were to desire to form a CCA Joint Powers Agency, Chula Vista should investigate partnering with other municipalities, principally, National City and Imperial Beach. Imperial Beach in particular has articulated interest in such partnering concepts. Municipal Revenue Bonds (H Bonds) The Chula Vista City Council has the authority to issue revenue bonds unilaterally, or to form a partnership with other local government entities in a joint venture to share the risks and benefits of a renewable energy network with other governments on a regional basis. 40 L()(,lll'(l\\'l'l AltCrIliltiH' Energ\ 1'1,,11 fm Rt']-l!,lcing tIlt-' Suuth tL1V 1\\\\"1;-'1' l'ldllt hhnJM\, 1()1l'7 Joint Powers Agencies, Native American Tribes, other cities and ports also have the authority to issue revenue bonds, either based on a new revenue stream or existing assets or contracts. There are several key entities in or near Chula Vista which should be considered for a potential financing partnership. We have identified specific opportunities for Chula Vista to issue H Bonds in conjunction with other local public entities, any of which could participate in a CCA, co-finance and co-own green power facilities, and host facilities on their list of lands and properties: · Native American Tribal Governments in or near San Diego County have land suitable for Solar Concentrator and Wind Power Facility, and are pursuing commercial green power development; · Southern California Public Power Agency members already co-develop power plants and could partner to develop and take power from a Solar Concentrator or Wind Farm Hybrid as municipal utilities; · San Diego County owns reservoirs and land suitable for the proposed Wind and Pumped Storage Facility; · Port of San Diego could co-finance a green power facility and purchase power as a member of a CCA; · U.S. Navy is an active developer of solar photovoltaics, has land suitable for green power facilities, and is a major energy user. The specific scenarios involve an integrated use of H Bonds in conjunction with a CCA. H Bonds are generic municipal revenue bonds used to finance renewable energy and energy conservation facilities. Chula Vista, and any other city, has the opportunity to issue H Bonds based on a new revenue source. There are three categories of H Bonds: · First, a municipality, JP A or public agency partnership may own its electric utility, and secure H Bond repayment through the guaranteed monthly bill payments of captive utility customers. This option has been foreclosed by Chula Vista's Franchise Agreement with SDG&E in 2004, which appears to prevent Chula Vista from providing wires services alone or with another party, including transmission; · Second, a municipality may issue H Bonds to finance facilities that will operate without a guaranteed retail customer, selling power with a degree of risk mitigated by long-term contracts with public agencies such as the Southern California Public Power Authority in a long-term agreement, and/or selling power in long-term contracts on the wholesale power market. · Third, a municipality may form a Community Choice Aggregator (CCA) formed pursuant to ABl17 (2002 - Migden) and secure repayment ofH Bonds based on monthly electric bill payments of participating residents, businesses and public agencies. H Bonds and CCA H Bonds provide CCAs with considerable flexibility. They can be used to finance renewable energy generating units and other revenue producing elements of CCA, such as storage facilities and conservation facilities. H Bonds can be supported by existing public agency assets and 41 Local Power Alternative Energy Plan for Replacing the South Bay Power Plant February, 2007 enterprises, or by new assets or enterprises such as renewable energy generating units. Finally, revenues from a contract with an Electric Services Provider ("ESP") may support H Bond repayment, with or without assets or enterprises. H Bonds and CCA are extremely synergistic. Together, they (a) provide both the means to develop renewable energy and energy efficiency resources, and the market to utilize and pay for those resources; and (b) provide CCA with a secure base of resources with which to serve its customers and, thus, avoid excessive dependence on a volatile energy market. Whether the H Bonds will qualify for tax-exempt status and other factors affecting their marketability are dependent on the structure of the transaction being financed. Specific structures are discussed below. As a rule, in order to qualify for tax exemption, the facilities that are financed must be owned by a governmental entity or operated by Chula Vista or other governmental entity - or by a nongovernmental entity on behalf of Chula Vista pursuant to a contract that meets certain requirements prescribed by the Internal Revenue Service. Even if not tax-exempt, H Bonds could still be issued to finance facilities which make solar and other technologies more affordable to local residents and businesses, albeit at a slightly higher interest cost than government-owned facilities would pay - but could also take advantage of significant federal tax benefits. Application of II Bonds to CCA 14 H Bonds can be used in a variety of ways. From a strategic business perspective, H Bonds and CCA were developed to work together. Without CCA, renewable energy and energy efficiency projects financed by H Bonds would have to search for a market for the power output. With CCA, major recurring revenues from community-wide retail electric sales will repay the investment in clean energy projects. Alternately, without resources of the sort authorized by H Bonds, a CCA program could not finance new green power facilities; moreover, without a secure base of resources, a CCA would be extremely dependent of the energy market to serve its customers. The energy crisis of 2000- 2001 dramatically demonstrated the danger of over-dependence on a volatile energy market - a lesson reinforced by fossil fuel price fluctuations this past year, and SDG&E's increasingly volatile electricity rates, reflecting its predominantly natural-gas fired power plant fleet. The specifics of how H Bonds are used in connection with CCA depend on what types of projects are to be financed. Because a driving factor behind most local government's interest in CCA is to utilize renewable energy and energy conservation, a number of projects that meet the parameters for H Bonds would probably be part of a Chula Vista CCA energy plan. Those projects can be financed with H Bonds. The specific use of H Bonds to most effectively further CCA depends on the particular projects. Three of the threshold questions that must be addressed are (i) what assets or programs would best assist with the implementation of CCA, (ii) what revenue source will secure repayment of the H Bonds, and (iii) whether the H Bonds are tax-exempt or taxable. These items are discussed 14 "How H Bonds can be used 10 implement an adopted CCA Implementation Plan," Nixon Peabody LLP, "Analysis for San Francisco Local Agency Formation Commission," November 10,2005, Accepted by San Francisco Local Agency Formation and San Francisco CCA Task Force, 2006. 42 L()(dl ['rnVL'r Altt'r11dtivL' Energy PieHl for Rl'p]cl(ing tilt' S(llJth 1:1<1)' I'()Wl'r l'l.mt f-cbnlMV, 20m briefly below. The first two are somewhat related in that if the items financed do not have an independent or sufficient revenue stream to support the bonds to be issued, a separate revenue stream for the H Bonds must be identified. The question of tax exemption will turn generally on the specific facts relating to ownership and use of the financed items. Chula Vista General Plan, Policy E 7.5 states that the City sets a goal of 40% clean renewable energy by 2017.15 San Franciscol6, Marin County, and other cities implementing Community Choice Aggregation have set goals of 50% or higher by 2017. To achieve this objective, Chula Vista's Implementation Plan would contemplate a number of elements that should fall within H Bond financing in order to provide for the development of renewable energy facilities, and could also establish replacement capacity and power for the RMR-contracted elements of the South Bay Power Plant. The bond financing can cover renewable energy generation from wind farms, distributed generation utilizing photovoltaic technology, an electrolysis hydrogen facility, and energy efficiency programs. This can include the developmental costs such as preparation of requests for proposals, environmental studies, and permitting, accounting and legal expenses, in addition to "hard-costs" of construction. Sources of Repayment H Bonds are "revenue bonds" issued by a municipality, county or Joint Powers Agency, which are to be secured by the revenues derived from fees and charges associated with the operation of an enterprise. Revenue bonds are commonly issued by state or local governmental entities and secured by the revenues of electricity or water enterprises or other revenue producing enterprises such as ports. The major point is that H Bonds may not be secured by or payable from Chula Vista's general funds. Rather, revenues from an operating enterprise must be the source of security or repayment. H Bonds allow, but do not mandate, the potential use of revenues produced by a facility to be built with proceeds of H Bonds to secure and repay those bonds. But revenues from other revenue producing enterprises may be used as security in lieu of or in connection with revenues from an H Bond financed facility. Under California law, revenue bonds such as H Bonds are excluded from the voter approval requirement of Article XVI, Section 18 of the California Constitution if they meet the requirements of the so-called "special fund doctrine." Under this exception, a debt otherwise requiring voter approval is not required if such debt is solely payable from and secured by revenues produced by an appropriate enterprise. No general fund or other tax revenues may be pledged to the repayment of such bonds. In order to constitute permitted "revenue bonds," Chula Vista will need to identifY a dedicated revenue source by which H Bonds are to be secured and repaid, whether revenues of a new source or an existing source. As noted, Chula Vista can structure H Bonds to be secured by the revenues from an existing revenue producing entity. Other financing scenarios also exist and are discussed below. 15 16 Chula Vista General Plan, Policy E7.5. San Francisco Community Choice Aggregation Draft Implementation Plan, San Francisco Local Agency Formation Commission, May 13, 2005. 43 Local Power Alternative Energy Plan for Replacing the South Bay Power Plant February, 2007 H Bonds can be secured by revenues from a new enterprise such as the CCA or a facility such as a renewable energy source that has not yet commenced producing revenues. This has the advantage of a logical nexus between the bonds' purpose and source of repayment. A disadvantage is the need to borrow additional moneys to pay interest on H Bonds during the construction period until such time as the facilities can produce revenues to pay the bonds, though obtaining a construction loan is a normal way of doing business for energy projects. Such a structure also has "construction" or "completion" risk that may result in a slightly higher interest rate on the bonds. In addition, the revenue production of a new facility to be built is uncertain which may also affect the interest costs that are attainable. Securing the H Bonds with the revenues of an existing revenue producing entity avoids the disadvantages discussed above. However, such a structure does "tie up" a revenue producing enterprise of the City. A potential "hybrid" structure is to use a combination of the foregoing structures. Under this alternative structure the H Bonds could be secured by both a pledge of revenues from an existing enterprise and from any new enterprise. The pledge on the existing enterprise could be limited to the construction period during which the new facilities are not producing revenues or could be for the life of the H Bonds. Another possibility would be to secure H Bonds with revenues available from a contract with a California-registered Electric Service Provider ("ESP") providing CCA services. Such revenues could be structured to constitute revenues of the enterprise(s), which would be the security for the H Bonds. For example, lease payments received from an ESP would constitute revenues that could be pledged as security. Ultimately, the projects Chula Vista desires to finance with H Bonds will have a strong bearing on the security structure chosen. For example, if a significant portion of the proceeds of H Bonds will be used to acquire or implement non-revenue producing programs, the use of an existing revenue-producing enterprise will be required. On the other hand, if a significant portion of the proceeds is used to acquire revenue-producing facilities, such facilities or related activities could serve as the security and source of repayment for the H Bonds. In any event, a bond rating will be required for H Bonds secured by new or existing enterprises that do not already have a rating. The credit quality analysis conducted by the rating agency will, among other things, focus on the "coverage" provided by the pledged revenues. Generally, the rating agencies prefer pledged revenues that are 125% or more of the scheduled debt service on the bonds. Alternative Structures for using H-bonds and Implications for Tax ~:xemption. Chula Vista has a wide degree of discretion regarding the use of H Bond proceeds for renewable energy and conservation projects. However, the particular programs and users of facilities financed with the proceeds of H Bonds will impact whether the interest on such bonds will be tax-exempt under the provisions of the Internal Revenue Code of 1986, as amended (the "Code"). 44 Lt)(dll\l1.n"1 Alll'rn.ltlYl' Em'rgy l'I,]f) fm Rt'pliKing tIll' South B,w P(\\\l'r l'ldllt h:'f~ru(1f\', 20W In other words, Chula Vista could use H Bond financing to provide its residents and businesses with the opportunity to purchase and own solar power with no money down. In general, the "use" of facilities or items financed with the proceeds of H Bonds by an entity other than a state or local government could result in such bonds constituting "private activity bonds." In that case, under Section 141 of the Code, the interest is not tax-exempt. Such use is often referred to as "private use". Private use is present where there are any types of privately held "legal entitlements" with respect to the financed facility. Nongovernmental ownership constitutes private use as do long-term contracts regarding the output to be produced by the facility. For example, a long-term contract with a nongovernmental entity in which that entity agrees to purchase the energy output of a facility will generally constitute private use. In addition, contractual arrangements with nongovernmental entities regarding the operations and maintenance of a financed facility will constitute private use, unless such contractual arrangement is consistent with certain contract parameters approved by the Internal Revenue Service and described below." Last, it should be noted that loans of the proceeds of H Bonds to a nongovernmental person or entity will generally cause the H Bonds to fail to qualifY for tax exemption. However, a tribal government could issue tax-exempt H Bonds in conjunction with Chula Vista or a group of public agencies in order to develop or co-develop a renewable energy facility and enter into power purchase agreements for the capacity and power of the facility between the tribal government and the municipality or group of municipalities such as a Joint Powers Agency. Therefore, the facts regarding the ownership and operational structure of the financed facility will determine whether the bonds may be issued as taxable or tax-exempt. If Chula Vista owns and operates the facility, and if the power is delivered to customers of Chula Vista, then the facility will probably qualifY for tax-exempt financing. It will also be possible to qualifY for tax- exemption if Chula Vista contracts the management of that facility to a private party, provided the management contract requirements of Internal Revenue Service Revenue Procedure 97-13 (discussed below) are satisfied. On the other hand, if an ESP or other nongovernmental entity owns the financed facility or operates it pursuant to an arrangement that does not meet the requirements of Revenue Procedure 97-13, it will probably not qualifY for tax-exempt financing. " Generally, bonds constitute private activity bonds if they meet either of the following tests: A. Both the private business use test ("Private Use Test") AND the private security or payment test ("Private Payment Test" and together with the Private Use Test, the "Private Business Tests")); or B. the private loan financing test "("Private Loan Test"). A bond issue meets the Private Use Test iftnore than 10 percent of the proceeds of the issue are to be used for any private business use. A bond issue meets the Private payment Test ifthe payment of the Implementation Plan of, or the interest on, more than 10 percent of the proceeds of such issue is (under the terms of such issue or any underlying arrangement) directly or indirectly -- A. secured by any interest in property used or to be used for a private business use, or payments in respect of such property; or B. to be derived from payments (whether or not to the issuer) in respect of property, or borrowed money, used or to be used for a private business use. For purposes of these tests, the term "private business use" means use (directly or indirectly) in a trade or business carried on by any person other than a governmental unit. Use as a member of the general public shall not be taken into account. A bond issue meets the Private Loan Test if the amount of the proceeds of the issue which are to be used (directly or indirectly) to make or finance loans to persons other than governmental units exceeds the lesser of X) 5 percent of such proceeds, or Y) $5,000,000. 45 Local Power Alternative Energy Plan for Replacing the South Bay Power Plant February, 2007 H Bond proceeds can be used to fund energy conservation programs. However, to the extent such purpose is accomplished through a loan program wherein residential and business customers can make use of low-interest loans in a CCA program to make energy conservation and efficiency improvements, the loans of bond proceeds will cause the program to not qualifY for tax exempt financing. Grants of bond proceeds could be made to individuals and businesses for conservation and other expenditures so long as an adequate project revenue stream is identified to secure and pay the bonds. The fact that such H Bonds are not tax-exempt does not in and of itself make such a program nonviable. Taxable rates on such H Bonds could potentially still be substantially less that the rate of interest otherwise available on loans to residential and business customers; and with longer lifecyc1e periods to facilitate a lower monthly payment. There are a number of ways H Bonds could be used to finance renewable energy facilities. This can be accomplished either in a structure wherein Chula Vista (or other local government) undertakes acquisition, construction, ownership and management of the facilities or through structures wherein an ESP undertakes some or all of the activities. As noted, the tax-exempt status of H Bonds will vary depending on the structure. Structures wherein an ESP takes on one or more of the roles present issues under the Private Business Tests discussed above. Any lease or other similar arrangement with an ESP would likely result in the H Bonds being categorized as taxable "private activity bonds." Again, such a result would not prohibit the structure but rather would result in a higher cost for these components of the program. An alternative involving an ESP would be to utilize the management contract provisions under IRS Revenue Procedure 97-13 ("Rev Proc 97-13"). Rev Proc 97-13 describes safe harbor contractual arrangements that may be made with nongovernmental entities to provide management, operations or other services with respect to a tax-exempt bond financed facility. Pursuant and subject to the requirements of Rev Proc 97-13, Chula Vista could engage an ESP to manage and operate renewable energy facilities financed with H Bonds without the ESP's involvement being in violation of the Private Business Tests discussed above. As discussed below, Rev Proc 97-13 would permit a contract between Chula Vista and an ESP for managing and operating a renewable energy facility financed and owned by Chula Vista for as long as 20 years. Rev Proc 97-13 defines "management contract" as "a management, service or incentive payment contract between a governmental person and a service provider under which the service provider provides services involving all, a portion of, or any function of, a facility." In this report, we assume a twenty-year maximum bond repayment within the context of a CCA contract period. However, a 30 year period is used for economic evaluation of a project, since this reflects the normal economic lifecyc1e. (see Appendix F, Financing). Rev Proc 97-13 focuses generally on the term of the contract and the manner and amount of compensation paid to the service provider. Generally, the more fixed in periodic amount the compensation paid to the service provider, the longer the permitted term of contract. Contracts pursuant to which the service provider's compensation is 80% fixed may be as long as 20 years in the case of service contracts relating to "public utility property". On the other hand, contracts pursuant to which the 46 l(lcdIJ\l\n-'] Alterntltin' Energy ['L'1l fm Replacing thL' South HdV 1\l\\t'l [ll.\llt FL'hnldJ\, 20ll? service provider's compensation is 50% fixed may not have a term in excess of five years. "Public utility property" is defined as property used predominantly in the trade or business of the furnishing or sale of (i) water, sewage disposal services, electrical energy, (ii) gas or steam through a local distribution system, and (iii) certain telephone services and communication services. Thus, for example, if the ESP is paid an annual fee equal to 8x and is also paid additional compensation in each year based on a variable component not in excess of 2x, then the contract can be for as long as twenty years. In addition, the ESP may be paid a one-time incentive award during the term of the contract, equal to a single, stated dollar amount, under which compensation automatically increases when a gross revenue or expense target, but not both, is reached. Further, a contract that satisfies the requirements of Rev Proc 97-13 may be renewed at the expiration of its term. A variety of the foregoing structures involving H Bonds could be used in tandem. For example, Chula Vista could enter into an energy supply contract with an ESP, which would not directly require the use ofH Bonds. Chula Vista could then issue H Bonds to construct renewable energy facilities to be owned by the City. Chula Vista could then enter into a management contract permitted under Rev Proc 97-13 to manage and operate the facilities. Such a structure could allow for the H Bonds to be tax-exempt. Engagement of CPUC and other funding Several funding sources have emerged in the recent months. These or other programs should be accessed by the City to provide renewable energy for its residents. California Solar Initiative Enacted by the California Public Utilities Commission, this program provides rebates for photovoltaic systems less than I megawatt, currently set at $2.50 per watt and decreasing 25 cents per watt as target MW levels of installed solar are met statewide. For systems over 100 kilowatts the rebate will be paid in the form of a performance-based incentive based upon the kilowatt-hours generated in the first years of operation. This will have an effect on financing, since the payment is not made up-front. The CPUC is examining a similar program for smaller photovoltaic systems as well. The recently enacted SB I, the former "Million Solar Roofs" bill, will place restrictions on the California Solar Initiative, e.g., it rolls back the PUC photovoltaic system size limit of 5 megawatts back to I megawatt, and has strict requirements for locating photovoltaic systems at customer sites. This may limit opportunities for a PV landfill project. PGC Energy Efficiency Funds These are currently administered by the utility companies in most areas of the state, except San Diego. AB 117 requires opening up funds to community administration for programs of their own design, and SDREO was able to take control of the funds away from SDG&E. This could be quite advantageous for Chula Vista, as a regional planning agency is more likely to be open to a systematic and creative efficiency program of the type necessary to meet grid reliability needs. 47 Local Power Alternative Energy Plan for Replacing the South Bay Power Plant February, 2007 This will require coordination between the energy efficiency component and the renewable energy systems, such as local photovoltaic systems and demand response capacity. A well designed program will look at the load curves met by each of these and work to optimize customer as well as system value. Federal Energy Tax Credits Private developers of energy projects may be eligible for certain tax benefits that are not available to public agencies. For this reason, it is wise to consider different ownership and financing models to determine which alternative can best meet the desired goals. In some circumstances the low cost of public capital may result in lowest energy costs for publicly owned and financed facilities. On the other hand, very generous tax credits may favor private, third party ownership. For many years there has been a 10% tax credit for solar installations purchased by commercial enterprises. The 2005 National Energy Policy Act (NEP A) increased this credit to 30% of installed cost of photovoltaic systems for commercial entities; but this will revert back to 10% in 2008 unless it is extended by Congress. Under the same law, homeowners can take up to a $2000 credit on solar energy systems. Public and non-profit entities are not eligible for this credit, since they have no tax liability. In fact, if government agencies provide rebates, or extend credit, to commercial enterprises for photovoltaic or other solar energy systems, they risk voiding eligibility for part or all of the credit based upon the portion financed. Hybrid ownership or financing models can be designed that optimize the balance between the benefit of public funding (such as rebates) and the ability to take advantage of tax credits. Commercial power project developers may take a 1.9 cent/kilowatt-hour production credit for certain renewable energy generators, paid out over the first ten years of operation according to the amount of electricity generated by the project. The rate of tax credit is indexed to inflation, and thus has increased over time. Congress, in 2005, extended this production tax credit to other renewables such as geothermal and solar projects; this is also due to expire at the end of 2007. A payment system has been set up by the federal government to make equivalent payments to public agencies as well, but this has mostly gone unfunded or underfunded in the past. There is wide interest in extending the solar and renewable production tax credits in the energy industry, in Congress and in the White House. The production tax credit has existed for a number of years, but Congress only approves this for a year or two at a time. This has created considerable instability in the US wind power industry, with customers clamoring to get their project on line before eligibility ends. Then Congress lets the tax expire for a year or so, and the demand for wind turbines completely dries up. Some renewable projects cannot occur within this time frame, particularly since regulatory approval, environmental review, planning and construction all have to be completed before the tax credit expires. Wind farms are most suited to taking advantage of the tax credit, since the development time can be as little at 18 months, assuming the process goes smoothly. But, in all cases, it is best for a project to begin planning stages in advance, so the project is ready to go when the tax credit opens up again. 48 L.Ol(lll\nver Altern.llIYt' Energy I'Lm fnr Rt>pl<H iTlg Hw South t).l)' Pu\\'t-'I' l'l,mt Ft'hr\l,HV, 2()(17 Supplemental Energy Payments (SEPS) This payment structure covers the excess cost of renewable electricity over the prevailing price of natural gas generation. It applies to wholesale power purchased by utilities through contractual agreements that must be approved by the CPUC. This program may be changed or eliminated in the future, so it may not necessarily be relied upon for project planning. However, the elimination of SEP payments may leave Chuta Vista's renewables at a competitive advantage compared to privately developed facilities. The principle concern is not if the SEPs are eliminated, but rather if they are retained. In this case, it will be important to make sure the city's renewable facilities are eligible for the same payments as any potential competitor. 49 Local Power Alternative Energy Plan for Replacing the South Bay Power Plant February, 2007 7. Benefits Comparison of GEO Options to Gas-fired Replacement This section provides a brief comparison of the risks and rewards of investment in a new gas- fired plant vs. the portfolios outlined above. The three GEO options have significant projected benefits over their lifecycle. Criteria for this comparison include the protection of public health, environmental justice, enhancing energy security, and competitiveness with SDG&E's projected conventional power prices. Financial analysis of renewable facilities is provided in the appendices and supporting spreadsheets. In the analysis it is shown how the lower cost of capital of a municipality achieves a significant long term cost advantages over municipal or private investors in similar projects. Economic Benefits Financial Return on Investment The interest on a commercial loan, and the high rate of return demanded by private investors, imposes a cost on renewables that can be much larger than the original cost of the power plant. For example, a favorably priced large wind plant today might cost about $1.3 million per megawatt (and an unfavorably priced version would likely not get built), which implies that the first GEO portfolio option of a 400 megawatt wind plant would cost $520 million. A private investor, averaging in loans and profits, might require over II percent rate of return every single year on the entire capital investment. The interest rate on a municipal revenue bond places a much smaller cost of money on the project, and such bonds are modeled to bear a 5.5 percent or less rate of return. (Current long term municipal revenue bond rates, for well rated bonds, are closer to 4.5 percent). The municipal owner's cost of money is thus half that of a private investor, as the following table shows: lnvestor Cost of Wind Cost of lenn 1 otal Rate Total!o!crcs! plus RO! Farm Money (yrs) Private $520,000,000 11% 20 220% $1,144,000,000 CCA Revenue $520,000,000 5.5% 20 110% $572,000,000 Bond The private investor pays twice again the cost of the wind farm over a 20 year period, over a billion dollars. The cost of interest on the municipal bond is exactly half as much, which saves $570 million. This savings is worth more than the entire wind farm. While the private developer does have tax credits to offset some of this difference, the main tax credit only lasts for the first 10 years. This gives the municipal investor a large advantage that is difficult to overcome. Since both SDG&E and a CCA would need to procure renewable power, the cost incurred on the customers of SDG&E for a similar supply would be higher. Given that few renewables cost less than wind, this would make it difficult for SDG&E to match the price of such a power supply. This extra cost is embedded in customers' rates one way or another. The cost of wind power also intersects the likely cost of power from natural gas, even for a private investor. This is partly because of expected increases in the price of natural gas over the next 20 to 30 years, which is the financial life of a wind farm. The DOE expects that natural gas 50 Luc1l1\1\\'l'l" AltenhltiH' bwrgy I'tm for Rt'p],lLing thl' South H,lV J\)\\'t'f Pl,ml l:pbrudf\,2(l()7 will decrease in price over the next several years, reaching a low of $6.30/mmbtu in 2011. Thereafter, it is projected to increase in price at about 2% per year for the foreseeable future, roughly following general inflation, eventually reaching $11.7 4/mmbtu. An average price of $8.40/mmbtu during the period implies a cost of natural gas fueled base load electric generation of about 6.6 cents per kilowatt-hour. By comparison, a 20 year investment by a CCA in a wind farm would lead to a cost of 5.5 to 6 cents per kilowatt-hour, to which one must add about half a cent to firm up the capacity so that the power can be sold on the market. If the wind farm is financed using 30 year bonds backed by the capital value rather than a CCA revenue stream, then the cost of the wind power could drop below 5 cents per kilowatt-hour. Clearly wind is a good investment if you expect the price of natural gas to increase by anywhere close to the rate of inflation or higher. This is one reason why wind is one of the larger elements of the portfolios. But this also illustrates some of the reasons why a CCA or municipality can maintain wholesale energy costs competitive with the utility company. In fact, the CCA might find at some point that the utility company will wish to purchase some of the CCA' s lower cost wind power for its customers, too, particularly since SDG&E is required by law to have 20 percent of its electricity supply come from renewables. While an analytical comparison between the GEO portfolio and SDG&E future wholesale power costs is outside the scope of this project, the above discussion shows in principle why CCA's can remain competitive. Reports by Navigant Consulting have demonstrated how nearly every municipality of reasonable size can achieve substantial savings, usually in the tens of millions of dollars or more, by this sort of financial leverage. In general, our methodology has been to compare the cost of GEO portfolio elements with the comparable electric supply product derived from natural gas power plants owned by private investors. This is the basic method of analysis used by the CPUC, in which the price of natural gas is a benchmark for calculating what a typical generator must charge to recoup its money and make a standard rate of return. This, however, is not necessarily the same as calculating whether an investment will make or lose money. It is an important guideline in California, because so much of our energy comes from natural gas, yet it must not be forgotten that most of the electricity comes from other sources, including renewables. So, the natural gas benchmark cannot be used as the only guide. An additional factor is that a low carbon portfolio may become a carbon asset, with the ability to sell carbon credits. This could become a significant revenue stream if carbon prices rise, as many analysts expect. More Local Jobs Renewable energy systems create several times the level of ongoing employment than fossil fuel generation. This is partly a function of the fact that money is not being expended into high fossil fuel commodity costs that will be lost from the local economy. A 180 MW solar thermal peaking plant can be expected to produce about 70 ongoing jobs, while a large wind farm about 16 employment positions for each 100 megawatts of capacity. Thus a 400 megawatt wind farm would provide about 64 ongoing jobs. The natural gas peaking facility will produce between 15 and 20 jobs while the Pumped Storage facility will produce about 10 jobs. Thus the total direct employment would amount to approximately 164 people. This compares with approximately 22 51 Local Power Altemative Energy (JJan for Replacing the South Bay Power Plant February, 2007 employees that would be needed to run a 500 to 600 MW natural gas-fired power plant such as the SBRP.18 More Money in the Local Economy The amount of money saved on fuel expenditure is likely to be large, as the investment in renewables is a 20 to 30 year commitment that avoids most of the fuel that would be necessary to produce the same amount of electricity. A new natural gas plant running at the same capacity as the existing SBPP would use about 18.5 million MMBtulyear. This energy content translates into about 18 billion cubic feet of natural gas per year. At a cost of $6 per thousand cubic feet, this represents $110 million of fuel cost per year. Over a 30-year period this would be $2.3 billion worth of fuel, assuming fuel costs were to remain at current levels. Even the most optimistic cost projections do not assume decreasing nominal prices for natural gas, so an increase in fuel cost of about 2% per year or more is reasonable. Since not all the capacity of the plant will be replaced with renewables, the exact19 amount of fuel savings will depend on the scenario chosen, as well as the future price of natural gas. Decn,ased Reliance on Natural Gas The GEO portfolios provide more energy security than continued heavy dependence on gas-fired power plants. A replacement plant would consume 18 million MMBtu of natural gas per year. The GEO options would use far less than that, about 4-7 million MMBtu per year, and would considerably reduce ratepayer exposure to natural gas price volatility. Figure 2. New York Mercantile Exchange Futures Prices for Natural Gas. NYMEX Henry Hub Natural Gas Futures 512,00 S10.00 S2.00 Ii\._ 58.00 B ~ E 56.00 E " 54.00 /'V 50.00 ~'*' ~O} ."\ " ,,'" ," ~cf' , ,,& '): ,,' '],,, ,,&- '): ~ '],,, cl" '],,, ,,<9 '): Comparative Cost of California Central Station Electricity Generation Technologies, California Energy Commission Staff Report, August 2003, Doc. 100-03-001. 19 California Energy Commission Staff Report, August 2003. Natural Gas Market Assessment. http://www.energy.ca.gov /reports/2003-08-08 _, 00-03- 006.PDF#search~%22natura'%20gas%20market%20assessment%22. Accessed October 2006. 18 52 I (l(;lll\n\'cr Altt'rnati\'L' Enl'Tgy 1'),1n tor RcpL\lI11g the Suuth HdY' Pu\\t'r 1)lanl hA")f1J<lf\', 2(l(l7 Overexposure to one fuel makes SDG&E's monthly electric bill also volatile. In 2000, gas spot- market prices quadrupled in less than nine months peaking in January, 2001. Domestic gas supplies are constrained, yet SDG&E is planning new gas-fired power plants and seeking to obtain the gas via its holding company, Sempra, from overseas. By focusing resources on accelerated renewable energy and conservation development, Chula Vista can reduce ratepayers' exposure to increasingly volatile natural gas prices, and steer away from SDG&E's new dependency on Liquefied Natural Gas imported from overseas at great expense. Environmental Benefits The Green Energy Options outlined in this report would provide a number of significant environmental benefits, including improved air quality, environmental justice, and reduced global warming emissions. In this section, we evaluate the operating impacts in these areas of the GEO options compared to the proposed South Bay Replacement Project, and to a load- following natural gas plant. In comparing the Green Energy Options to natural gas burning plants, it is important to understand that the manner in which a natural gas power plant is run determines its air pollution and greenhouse gas emissions. Like a car, a plant's efficiency will be different if it is run steadily, (as in freeway driving) as opposed to ramping up and down (as in City driving or driving in stop and go traffic). Thus, when we compare air pollution and greenhouse emissions from the Green Energy Options to those from a natural gas plant, we must be clear about what energy needs and market conditions the GEO portfolios and the natural gas plants are designed to meet. As is explained in Section 3, the GEO portfolios are designed to meet the energy needs currently being met by the South Bay Power Plant. The SBPP runs as a load-following plant that ramps up during periods of high demand, which usually occur from midday through the evening, with highest demand typically needed to meet air conditioning needs on hot summer days. For this reason, we compare the GEO options to a new state of the art load-following natural gas plant, whose energy production 'follows' the daily and seasonal fluctuations in energy demand 'load'. We also compare the GEO portfolios' environmental impacts to those of the proposed South Bay Replacement Project (SBRP). The SBRP is proposed to be a base-load plant, that is, a plant that runs relatively steadily to meet 24-hour daily energy demand. The plant will, however, have a duct- firing component to it, which would allow a part of the plant's capacity to run more as a load- following or peaker plant. The plant's efficiency is much lower when it is producing energy through duct firing. It is unclear at this point how much duct firing the plant is planning to use, but we have used the best available information on the plant as provided in LS Power's CEC permit application (AFC) to estimate emissions from the SBRP. The GEO options are designed to meet RMR needs, and provide dispatchable energy on demand. To meet the RMR criteria, the GEO options rely in part on some natural gas capacity that can kick-in when the solar and wind components of the portfolios are unavailable. This is why the GEO portfolios would create some emissions of air pollution and greenhouse gases, though far less than either the current or proposed replacement plant. 53 Local Power Alternative Energy Plan for Replacing the South Bay Power Plant February, 2007 Air Quality Benefits Chula Vista's air quality is currently unhealthy, and particulate matter emissions are a major concern. Levels of particulate matter (PM) measured at the San Diego Air Pollution Control District's Chula Vista monitor exceed state and national air quality standards.20 While there are many sources of PM - including cars and trucks - a power plant can be a significant source of this pollutant, especially in a localized area near the plant. The manner in which the SBPP is replaced will thus be an important factor in determining future air quality in Chula Vista. The size of particulate matter from natural gas plants is almost all 2.5 microns or less, which is designated PM2.5. PM2.5 particles travel deep into the lungs where they can seriously damage lung tissue. They are so small that they can get into the blood stream through the lungs, and carry pollutants that are adsorbed to the particles throughout the body.21 A battery of studies has linked PM to a number of health hazards, including a~favated asthma and lung disease, decreased lung function, heart attacks and premature death. Natural gas power plants also emit nitrogen oxides (a precursor to ozone or smog) as well as other air pollutants. The South Bay Power Plant is a major source of air pollution. In 2003 (the most recent year for which a San Diego Air Pollution Control District inventory is available), it emitted nearly 95 tons of particulate matter (PM) and 86 tons of nitrogen oxides (NOX)23 LS Power, the developer of the South Bay Replacement Project (SBRP) has proposed that the new plant will emit no more pollution than the existing South Bay Power Plant.24 The California Energy Commission has raised concerns about the methods used in LS Power's CEC permit application to estimate emissions from the existing and proposed fslant. It is thus unclear at this point what the actual emissions from the SBRP are likely to be. 5 LS Power has estimated the existing plant's actual PM emissions are at 69 tons per year and the proposed SBRP's maximum emissions to be about 69 tons PM per year. Our estimates put the SBRP's likely emissions at about 94 tons per year, running as a typical base-load plant (at 80% capacity factor) with intermittent duct firing (at 9% capacity factor). A new plant could emit a comparable amount of pollution as the existing plant because, although the new SBRP will be more efficient than the existing plant, it will be run more often. Therefore, under the current proposal, the West Chula Vista community could see no improvement in air quality with the shutdown and replacement of the South Bay Power Plant, and might even see an increase in air pollution. 20 San Diego Air County Air Pollution District. Monitoring data from the Chula Vista monitoring station 2000- 2005. Available at: http://www.sdapcd.org/air/reports/smog.pdf 21 Lipmann, M. et. al. (2003). The U.S. Environmental Protection Agency Particulate Matter Health Effects Research Centers Program: A Midcourse Report of Status, Progress, and Plans. Environmental Health Perspectives III (8) 1074-1092. 22 US Environmental Protection Agency. Health and Environmental Effects of Particulate Matter http://www.epa.gov/ttn/oarpg/naaqsfin/pmhealth.html. Accessed February 17, 2006. 23 SDAPCD Emission Inventory at http://www.sdapcd.org/toxics/Projectl/SourceEmissions.htmIAccessed 11/8/2006. 24 LS Power. 2006. Application for Certification to the California Energy Commission for the South Bay Replacement Project. Page 8.1-54, Table 8.1-34. 25 CEC Data Requests to LS Power Generation LLC as of October 31, 2006, Docket 06-AFC-3. 54 LUldl J'o\\"(~r AlkrnilLivl' Energy !']<:11l for Replacing the Suuth lLl)' [\)\\'l'r l'ldnl rl'hrUiHV, 20117 If the existing SBPP were to be replaced with a load-following plant that generated a comparable amount of electricity as the existing plant (32% capacity factor), its total PM emissions would be slightly lower than the existing plant's, at about 68 tons per year.26 The GEO portfolios would only emit from 14 to 27 tons per year?7 The GEO portfolios would thus emit 60-80 percent less particulate matter than a load-following natural gas plant. The portfolios would emit 70-85 percent less pollution than would the proposed SBRP. (Appendix H) The air quality impacts that are created by a given project's emissions are a product of the project's location and other project-specific factors. The SBRP is proposed to be located next door to the existing SBPP on the Chula Vista Bayfront, directly upwind of the residential and densely populated area of West Chula Vista. While it is not clear if any natural gas capacity is needed on the bay, the preferred option would be to have no, or very little, capacity at this site. Nonetheless, even if all the natural gas portions of the GEO portfolios were located at this site, the PM emissions would still be much lower than the SBRP's. Environmental Justice For over 40 years, the community downwind of the existing power plant has borne the pollution burden of a facility that serves the energy needs of a good portion of the County. The proposed plant would generate far more electricity than is needed by the City of Chula Vista. Even if we look into future energy demand in Chula Vista, and assume minimal energy efficiency improvements, projected energy demand in the City of Chula Vista is estimated to be 1,345 GWh by the year 2023?8 The proposed SBRP would produce about 3,600 GWh per year, so West Chula Vista residents would continue to bear the pollution burden for others' energy use. Locating another large plant near the site of the existing power plant would perpetuate environmental injustice. The community living within a six-mile radius of the South Bay Power Plant is 77% Latino, with 21 % of residents closest to the plant living below the poverty leve1.29 As does everyone, residents in West Chula Vista deserve healthful air to breathe. Replacing the energy currently being provided by the SBPP with the GEO options would move Chula Vista in the right direction, toward attaining air quality standards and environmental justice. Reduced Global Climate Change Impacts The GEO portfolios would avoid significant emissions of greenhouse gases, and reduce the region's contribution to the global climate crisis. The predicted impacts from Global Climate Change are severe. In California, global warming is predicted to create more severe heat, worsened air quality, threatened agriculture, coastal flooding, increased wildfires, and decreased Sierra snow pack which provides water resources to much of the State, among other serious 26 Assuming a 32% capacity factor and a heat rate of 9,400 MMBtu/kwh, a typical heat rate for a new load- following plant. 27 Also assuming a 32% capacity factor and a heat rate of 9,400 MMBtu/kwh for natural gas portion of the GEO portfolios. 28 Navigant Consulting, Study for City ofChula Vista on MEV Feasibility. March 19,2004. Based on SANDAG growth projections. 29 Western Chula Vista Revitalization Population, Market, and Housing Trends, City ofChula Vista, Feb 2, 2006, p.9 55 Local Power Altemative Energy Plan for Replacing the South Bay Power Plant February, 2007 threats.3o The GEO portfolios offer Chula Vista and the San Diego regIOn an excellent opportunity to reduce this major threat to our State and the World. If the proposed SBRP were running as a typical base load plant with intermittent duct firing, it would produce about 1.5 millions tons per year of carbon dioxide (C02), A load following natural gas plant would produce about 1.1 million tons/yr of CO2. In aggregate, the SBRP would produce more carbon dioxide, but per unit of energy produced, the load-following plant would produce about 1100 tons per megawatt hour of electricity produced as compared to about 830 tonslMWh for a base-load SBRP (Appendix H). The GEO portfolios would emit far less carbon dioxide per year than either the SBRP or a natural gas burning load-following plant: about 220,00-420,000 tons of C02 per year. This is 60- 80 percent lower than a load-following natural gas plant and 70-85 percent lower than the proposed SBRP. The annual savings in carbon dioxide emissions provided by the GEO portfolios is equivalent to taking 200,000 - 250,000 cars off the road.3! On a C02 emissions per unit of energy basis, the GEO portfolios would also emit far less, with emissions of from 382 to 386 tons of CO2 per megawatt hour, or about only Y, to Y, of the emissions from the exclusively natural gas options. Chula Vista has been a leader in pursuing local initiatives to reduce the City's contribution to the global climate crisis. In 2000, the City adopted a CO2 reduction plan as part of its participation in the International Council for Local Environmental Initiatives (ICLEI). This plan directs the City to seek green power purchase options. The City's facilitating the development of the Green Energy Options outlined in this report would set the City firmly on a path to global climate responsibility and leadership. 30California Climate Change Center, a project of the State of CA. July 2003. Our Changing Climate, Assessing the Risks to California. "US Climate Technologies Cooperation Gateway, Greenhouse Gas Equivalency Calculator. http://www.usctcgateway.netltooV Accessed October 2006. 56 LU,-illl\n",,'1 Alternilti\'l' Energy ['Ian I(l" Rl'pli1Cing the Suuth 1:),1)" J'tl\\'er JlI,lnl FL'bruarv 2(107 GEO Report Findings The Greener Energy Options Portfolios are economicalIy viable The low cost financing available to a city through municipal bonds can leverage significantly lower cost for renewable generation. Also, the he largely fixed cost of the renewables provides a hedge against substantial risk of increasing natural gas prices over the next 20 to 30 years. There are essentially two scenarios examined here. The first assumes portfolio costs under a 30 year capital or revenue bond, which would optimize cash flow in the earlier years of the investment. This is how the different projects are evaluated as separate investments. This contrasts with the second scenario examined in the report, a 20 year term investment under a CCA revenue bond, where the cost to own and operate a plant on a per kilowatt-hour basis is significantly higher during the bond period. Once the bond is paid off, however, the capital cost is removed. The result is that, from year 20 to year 30, the only real cost will be operation and maintenance, and possibly some equipment replacement. This will mean very inexpensive overhead, especially when compared to the earlier years, which may amount to only a few cents per kilowatt-hour for peak power generation. The result is that substantial returns on the investment can be made during these "out years", when cost of operation is low and fuel and retail electric rates are likely to be higher than today. It may well be worthwhile for Chula Vista to invest in the capital asset to accumulate an equity position at a rate that preserves the cash flow of the projects during the 20 year CCA revenue bond period. The return on this investment will then be achieved in the out years (year 20 to 30). A full economic evaluation of a CCA is outside the scope of this report, and would involve base load power supplies, transmission and distribution, and other operating expenses not considered here. These in turn would need to be modeled against expected future SDG&E rates. While some renewables owned by the CCA may cost more than natural gas power plants, this 'higher price" will be offset by similar renewable requirements for SDG&E. Thus it is unlikely that the portfolio considered here would result in any higher cost than for any other customers in the region. In particular, the low cost financing is likely to provide the least cost option for the renewable portion of the portfolio that will significantly offset the compressed timeframe (20 year CCA bond term) for repayment of the assets. We have used the Market Price Referent (MPR) methodology, derived from the price of natural gas electric generation, as a basis for comparison between GEO energy supplies and to provide a general sense of the viability of an investment. Yet the investments are not taken in isolation; they serve as hedges one against the other. A significant portion of natural gas generation is included for reliability of power supply, but also to take advantage of any drop in natural gas prices. The wind and solar components protect against any increases in the price of natural gas. Losses that may occur in one segment are offset by other parts of the portfolio; and the losses should not be examined in isolation, since a change in market conditions may reverse the loss. In general the natural gas component is designed either to make money on the open market, or save CCA ratepayers on their bills, under all scenarios. That is because, first, the price of natural gas is similar for all generators over the long run, but the CCA has lower cost of money. This locks in a differential with other natural gas generators with which the CCA gas plant is competing. 57 Local Power Alternative Energy Plan for Replacing the South Bay Power Plant February, 2007 Second, the plant is intended to operate as a cogenerator, which means that waste heat is capture and sold at or below cost. Most commercial power plants do not operate in this way, and older cogeneration plants will be less efficient than a modern one. Thus the CCA natural gas plant can provide a double revenue stream, while conserving natural gas. The GF:() Portfolios offel" signitlcant hencfits As is detailed in the preceding section, the GEO portfolios offer a number of benefits over a gas- fired plant. The GEO portfolios would result in 60-80 percent less emissions of particulate matter air pollution and would promote environmental justice. The GEO options would also produce more local jobs, decrease the region's over-reliance on natural gas, and keep more money in the local economy. Pursuing the GEO options would get us firmly down the road of a more secure and sustainable energy future for the region, and would lessen the region's contribution to the global climate crisis. The initiative must he led by Chula Vista Over the past four years, the City of Chula Vista has prepared extensively for the implementation of Community Choice Aggregation ("CCA") and/or development of green and renewable power generation facilities. CCA would allow Chula Vista to find an alternative electricity supplier to SDG&E, and to decide what kinds of electricity to purchase. In addition, municipalities and other local public agencies like Chula Vista may issue municipal revenue bonds ("H Bonds") to finance renewable energy and conservation facilities. These mechanisms will be analyzed in this Plan. A strong argument can be made that CCA in conjunction with H Bonds allows the greatest potential for cost-effective, cleaner and more sustainable replacement of the South Bay Power Plant ("SBPP"): . First, as a Community Choice Aggregator (CCA), Chula Vista would be poised to solicit competitively priced power from competitive suppliers for its residents, businesses, and municipal facilities." . Second, Chula Vista may profitably develop a revenue-producing renewable energy facility with pumped storage or gas-fired facilities for capacity balancing. Using the unique leverage that municipal revenue bonds and CCA facilitates, it is now possible to serve Chula Vista residents, businesses, and public agencies with this qualitatively superior, greener, more reliable energy source. New, city-owned, facilities could generate electricity, at rates equal to or lower than SDG&E's rates, both for local use and profitable sale of excess power in wholesale markets or to other public agencies. As stated above, this level of analysis is beyond the scope of this report. However, the conclusion is supported by the fact that both the CCA and SDG&E will require a substantial renewable portfolio, and the CCA has at its disposal a significantly lower cost for capital that places it at a significant advantage. In addition, if the city elects to sell power, it will be able to command a market price comparable to private vendors, and any 32 Chula Vista commissioned Navigant Consulting to prepare a Feasibility Study on CCA in Chula Vista, conducting peer review with several public hearings. 58 [(Killl'(lwl'r AlterndtiVt' Energy Fldn tpr Rlvl.llmg tlw South HdY ]lO\\t'i" l'l,ml FL'brUdJ\ 20()7 "over market" costs (i.e. costs above natural gas generation) will thus be rate-based for SDG&E customers, since SDG&E will need to meet its renewable obligation. This report identifies several specific opportunities available to Chula Vista, with a variety of locally feasible technologies and partnerships. However, even if CCA is not pursued by Chula Vista, other governance structures and initiative options are available for the City to pursue some or all of the green energy options outlined in this report Community Choice Aggregation (CCA) and Public Investment is the best Approach Unless Chula Vista forms a CCA, any transmission facilities must either be owned by SDG&E or some other transmission entity such as a Tribal Government. The City of Chula Vista signed a 20-year franchise agreement with SDG&E in 2004 committing "that the City will not participate in the provision of electric or natural gas Distribution Services by itself or others within its jurisdictional boundaries for the term of the franchises." Thus, Chula Vista may not sell "distribution" services to consumers. The MOU defined "distribution" as "the ownership and/or operation by the City itself, or with or by any third party, of any facilities, including pipes, wires, and electric and gas utility plant and related services for the transmission or distribution delivery of electricity or natural gas to consumers within the boundaries of the City of Chula Vista." The MOU excluded from this rule the ''performance of (i) those rights and duties specific to Community Choice Aggregation... within or outside CITY limits if authorized and as approved and implemented by the CPUC, if such is required or (ii) generation of electric power. ,,33 However, a CCA and renewable generation project would enjoy a full range of options. Thus, if Chula Vista forms a CCA or builds a power generation facility, it may elect to sell transmission services within or outside Chula Vista. There are at least two options to accomplish this. The first option is to develop future renewable energy and conservation facilities that require transmission service by taking action to: . Acquire access to existing transmission capacity; · Arrange with SDG&E to provide transmission access, pursuant to Federal Energy Regulatory Commission (FERC) Order 888, or; · Arrange to purchase transmission services from another party such as a tribal government. The second, and probably more important, option is to develop local power resources that require little or no transmission facilities to deliver the power to customers. As this report will show, the Chula Vista region offers opportunities to develop a large solar concentrator and other renewables in the immediate Chula Vista and neighboring areas interested in participating in the development of the facilities and/or the purchase of power from such facilities. 33 Memorandum of Understanding Between San Diego Gas & Electric Company and the City ofChuta Vista, October 12, 2004, p. II, Section 1.14.A. 59 Local Power Alternative Energy Plan for Replacing the South Bay Power Plant February,2007 Both options are more local in natnre than the power supply now being provided to residents and businesses in Sempra's service territory. Both options are financially feasible at competitive wholesale and retail prices, with either a CCA or a city-owned merchant facility, or both, being the structuring principle of the project. CCA is by far the best way to ensure success and achieve the kind of scalability needed to physically alter the need for generation in this part of the electric grid. Photovoltaics (PV) on Chula Vista rooftops, energy efficiency, demand response may be fundable with existing ratepayer funds if a CCA is formed and the opportunity to administer the funds is requested at the California Public Utilities Commission.34 Other distributed generation may be undertaken within the City under a CCA or a revenue bond funded ("H Bond") program, and may invest General Funds in renewable energy projects for non-CCA customers if the City wishes to operate the plant as a public enterprise. Because scaled projects such as those presented in this Plan are necessary to eliminate multi-hundred Megawatts of regional demand in order for the Independent System Operator (CAISO) to accept a downscaling of new power generation on the South Bay site, this report identifies several physically viable, legally developable and economically competitive green power facilities, estimates facility costs, schedules for payback and power pricing. Specific facility scales in each Scenario are based on a variety of potential market structnres, including Community Choice Aggregation (CCA) the use of H Bonds, and potentially available state of California funding for energy efficiency programs pursuant to the Community Choice law, ABII?". The ability to eliminate or reduce the need for power generation at the South Bay Power Plant site depends on the municipality's degree of public investment, as well as investment by potential strategic partners in the region. This investment may be structnred as follows: . Municipal Enterprise. Chula Vista can meet their interest in an entrepreneurial energy ventnre by owning renewable energy and conservation facilities as a municipal enterprise while also meeting its mandate for first-class environmental leadership; . Creation of a CCA adds even larger-scale private sector purchasing power to public financing, enables a commensurate scaling-up of renewable energy development, and provides a secure revenue stream for the H Bonds that the city and/or its other public partners elect to issue for solar photovoltaics and the other locally feasible investments in the Chula Vista area and East County; . Chula Vista investment in renewable energy and conservation facilities involves a lower degree of municipal risk than investment in a 100% natnral gas generation power plant, because there is reduced exposure to the highly volatile price of natural gas that constitntes 50% to 80% of the life cycle cost of a gas-fired power plant. 34 35 CPUC Proceeding R.01-08-028. Migden, 2002 60 I UC<l11\\,.Vl'l' Altt'lT'\"tivl' Energy [It,lIl tur Rl'P1,ll.:ing the South HdV r\\\\'t'r I'Llnt Februar\,,20()7 Such investments can provide benefits including: · As free-standing investments, any profits realized from renewable energy or conservation facilities, they can benefit taxpayers by contributing funds to the City of Chula Vista General Fund. · If the renewable energy or conservation facilities are incorporated into a CCA, then they can realize long term savings for ratepayers compared to market prices for similar energy supply. · Renewable and conservation facility assets will retain their market value and generate revenue for decades after H Bonds or other financing are repaid, offering both returns on public investment and a lower cost of energy for local residents and businesses. The GEO Portfolios are consistent with existing local, state and federal policy, regulations, and law All alternatives proposed in this Alternative Energy Plan meet the stated project objectives in the AFC for the South Bay Replacement Project. These are: · Commercially-viable and capable of supplying economical electrical services - capacity, reliability, ancillary services, and energy supply - to the San Diego Region. · Capable of ensuring the timely removal of the existing South Bay Power Plant and that fulfills the obligation found in Article 7.l.a of the Cooperation agreement, which states, "use commercially reasonable efforts to develop, finance, construct and place into commercial operation a new generation plant replacing the South Bay Power Plant... which shall have a generating capability at lease (sic) sufficient to cause the ISO to terminate (or fail to renew) the must run designation application to the South Bay Power Plant on or before termination of the lease" 36 and upon which the size of replacement power is based. · Meets applicable laws, ordinances, regulations, and standard (LORS) of the California energy Commission, Chula Vista, the Unified Port of San Diego and other agencies, and complies with the Applicant's Environmental Policy. · Consistent with the objectives, guidelines and timing goals of the emerging Bay Front Master Plan. · Assists in maintaining and/or increasing the regional electrical systems' efficiency and reliability. 36 LS Power. 2006. Application for Certification for the South Bay Replacement Plant, footnote 5, page 1-7 61 Local Power Alternative Energy Plan for Replacing the South Bay Power Plant Pebruary, 2007 . Supports attainment of the state-mandated 20 percent Renewable Portfolio Standard (RPS) requirements for renewable energy, which will be required if a Chula Vista CCA is formed.37 The renewable generation could also support SDG&E to achieve compliance with its RPS requirements under potential power purchase agreements. . The GEO options would have a lower cost of electric generation over the life of the assets than if Chula Vista CCA or SDG&E were to purchase similar legally required renewable power supplies on the open market, due to the low cost of municipal financing. This meets one of the key requirements of state regulation (CPUC) that electric generation resources be "least cost". . The GEO options can replace the function of the current plant, to provide urgently needed power during times of peak demand, when the stability of the electric grid is most at risk. The proposed "all natural gas" replacement on the bayfront would achieve this to a much smaller degree, since it is mainly designed to supply 24 hour a day base load. Thus, the GEO meets the other key requirement of the CPUC that electric generation resources be "best fit". 37 Application for Certification for the South Bay Replacement Plant, page J-7 62 L.Oldl (\l\\'l'r ,\lternMivt' Energy ['!.m fur [~cpLH~ing tJ-le Snuth Hill' PO\\ l'f J'Llnl h:'i~nlMY, 2007 Recommendations · Chula Vista should present evidence to the ISO and other regulatory bodies, proving why a replacement for the current plant is not needed on the Bayfront. This report shows that about 2000 megawatts of alternative options exist within San Diego County, some of which would cost far less than replacement of the South Bay Power Plant at its current site. In some cases merely changing regulatory status or evaluation of existing or planned resources, or the need for them, is aU that is required. It is unlikely that replacement of more than a fraction of the current plant is reaUy necessary to meet the needs of the region for years into the future. That is the most important reason why a range between 50% and 90% replacement of existing capacity has been proposed in this report. · Chula Vista should further investigate the options identified in this report to begin discussions with potential site owners, financing sources and partners for different projects. Scoping needs to move as soon as possible to the next level of specificity to answer critical questions. · Chula Vista should fund and prepare an Implementation Plan and draft a Request for Proposals for Community Choice Aggregation and H Bonds that includes designing, building, operating and maintaining a solar concentrator, wind and pumped storage facility in conjunction with local solar photovoltaics, distributed generation, energy efficiency and conservation. These measures should be supplemented with natural gas fired co-generation to balance out the portfolio risk and energy costs, as weU as to insure the fuU reliability requirements are met. · Chula Vista should only entertain sites for facilities that minimize the need for new transmission, and only aUow transmission that is placed on existing rights of way. Any new lines should be occupied only by clean energy capacity. No major power lines on new corridors are needed, as they will impose billions of dollars in costs on ratepayers as well as make the region even more dependent upon energy imports. These imports send dollars and jobs out of the region while new transmission corridors would spoil the county's landscape and natural beauty. · Chula Vista should participate in the ISO RMR designation to ensure the RMR IS calculated appropriately to include all renewable and other green energy sources. · Chula Vista should participate actively at the California Energy Commission, Independent System Operator (CAISO), California Public Utilities Commission, and Federal Energy Regulatory Commission to propose the options identified in the GEO as preferable to repowering the South Bay Power Plant site. · At present two of the largest generating plants in the region, representing nearly 1000 megawatts of capacity, contribute nothing to grid reliability, according to ISO evaluation. 63 Local Power Alternative Energy Plan for Replacing the South Bay Power Plant February, 2007 San Onofre Nuclear Generating Station is not counted at all toward regional generation, even though it supplies over 400 megawatts of power, 24 hours a day, to San Diego County. That is because it uses up capacity on the same transmission line that is used for importing electricity. And the new Palomar plant, at over 500 megawatts, does not count either due to a mere technicality. Chula Vista should urge the ISO, CEC and CPUC to move forward with assuring that the Palomar power plant is fully accounted for as reliable generation capacity, and that a short transmission line be added to the existing South of SONGS (SOS) corridor to connect the plant directly to the regional grid without casting a transmission shadow for electricity imports from the north. These two tasks would together supply approximately 500 megawatts of additional reliable capacity to the region for by far the least cost and environmental impact. . Chula Vista should challenge the "bait and switch" tactic of justifYing a new 24-hour a day "all natural gas" powered base-load replacement plant on the bay, based upon the ISO reliability contract on the existing plant. The current plant is considered necessary for meeting peak demand when power is urgently needed for grid stability, and only runs its generators part-time. The function of the current plant is completely different from the one proposed to replace it, and should require a separate evaluation of need. . Chula Vista and other local and regional land use authorities should adopt stringent building standards that maximize energy efficiency, demand response, and development of clean, renewable energy sources integral to new and renovated building construction. 64 L(ll~dj r 'pwer Altl'rn,lti\l' Energy ['].lll tm RepI,-King the Suuth Kcl\ ]'ll\\t'l' j'l,mt Ff'brUM\'. 2()()7 Appendices Appendix A Appendix B Appendix C Appendix D Appendix E Appendix F Appendix G Cost Factors for a Wind Farm ..................................................................... 1 Solar Thermal wi Natural Gas and Cogeneration ..................................... 6 Natural Gas Costs ....................................................................................... 11 Photovoltaics ................................................................................................ 19 SDGE&E Rates and San Diego Electric Resources ................................. 21 Portfolios and Financing............................................................................. 24 Pollution Com parison Calculations ........................................................... 29 List of Tables in Appendices Table A-I. Wind Cost Summary ........................................................................................................... 3 Table A-2. Wind Farm Electric Generation Cost with Private and Public Financing...........................4 Table B-1. Concentrating Solar Thermal Power ................................................................................... 7 Table C-1. Natural Gas Price Projections to 2040...............................................................................12 Table C-2. New Combustion Turbine Peaker, CCA Ownership......................................................... 14 Table C-3. New Combustion Turbine Peaker, Private Ownership...................................................... 15 Table CA. New Combined Cycle, Base Load, Private Ownership..................................................... 16 Table C-5. Cost of operating a natural gas peaker plant at low, base, and high natural gas projections under private ownership.......................................................................... ..17 Table C-6. Cost of operating a natural gas peaker plant at low, base, and high natural gas projections under public ownership.......................................................................... ..18 Table D-I. Photovoltaic Power Production Full Lifecycle Accounting: Commercial Ownership ..... 20 Table E-I. SDG&E Energy and UDC Charges as of 2/1/2006........................................................... 22 Table E-2. San Diego County Power Plant Construction 2001-2009. ................................................23 Table F-1. Green Energy Options- South Bay Power Plant Replacement Generation Portfolios....... 25 Table F -2. Financing Assumptions...................................................................................................... 28 Table G-1. South Bay Power Plant Replacement Options, Comparison of Air Pollution and Greenhouse Gas ................................................................................................................ 29 Appendix A Cost Factors for a Wind Farm The cost of wind power has dropped from a range of 30 to 50 cents per kilowatt hour in the early 1980s to between 5 and 8 cents per kilowatt hour today. This is now competitive with other forms of electric generation, especially natural gas and nuclear power. On the low end of its price range wind may even compete with new coal plants, due to pollution control requirements, and long term risk of carbon emission liability. There are three key factors that determine the cost of the electricity generated from wind power: the installed cost of the wind farm, the financing cost, and the wind resource. The installed cost of wind farms was between $1000 and $1200 per kilowatt in 2003; however a few factors have combined recently to increase that cost. The unpredictable US production tax credit for wind causes a "boom and bust" cycle in demand for wind turbines in this country. The credit has been in effect for the last two years, which has pushed up demand to historical highs with a new wind farm being built every two to four weeks. In fact, far more wind than coal capacity is currently being added. State policies requiring utilities to put renewable electricity sources into their portfolios, as well as increases in the price of natural gas and higher retail electric rates, has helped drive growth in wind power. In the late 1990s only a few hundred megawatts of wind were installed each year in the US; this reached 2431 megawatts in 2005 and 2454 megawatts of new capacity was added in 2006. Manufacturers can barely keep up, and most production capacity is reserved in advance for the next two years. Increased demand, higher raw material prices, and the low value of the dollar have caused the price of wind turbines to go up. The result is that wind farms in the US now range from $1300 to $1750 per kilowatt. We project a lower end cost, assuming that the project will be well planned, and that the current overheated market will cool as manufacturing capacity catches up to demand. There are important factors that can offset this recent trend. The cost of the tower and turbine is only about half the installed cost, which also includes labor, access roads, power lines, etc. Thus, even a 50% increase in material costs will result in a smaller impact on a total project. Manufacturers are also helping in important ways. The size of individual wind turbines is increasing, which lowers unit costs. Efficiency and performance of wind turbines is steadily increasing year by year. This is a function of improved design, careful measurement of wind resources, and better placement of wind turbines. The effect has been dramatic. The electric generation from a given sized wind farm has increased by more than 50% since the early 1980s. There have also been great improvements in quality and durability, with the result that wind turbines need less servicing, and are available 98% of the time for generating electricity. An opportunity may come for Chula Vista when the Federal wind tax credit expires, and the city should prepare to take advantage if a window opens up. The tax credit is paid to private investors in wind farms, based on the electric generation of the facility, at the rate of 1.9 Appendices cents per kilowatt hour presently, but this is indexed to inflation; we project a rate of 2 cents/kwh by 2009 if the credit is reinstated. Since government entities do not get tax credits, Chula Vista is not dependent on the credit to make wind power an attractive investment. The low-interest financing from municipal bonds can bring the cost of wind power to an even lower level than a private investor would achieve with the support of the credit, Because the private investor's tax credit expires after the first ten years of the project's operation, a municipal owner of a wind farm has a long term competitive edge over other owners. The value of low cost financing is substantial. A 400 Megawatt wind farm installed at the rate of $1350 per kilowatt will cost $480 million. A private investor that has an average cost of capital of 11.8% will incur about $1.9 billion in expenses to cover interest on borrowed funds and profit for investors over a 30 year period. By comparison, a publicly financed wind farm need not provide any profit for investors, and is only obligated to repay the bond principal and interest. At 5.25 percent interest over 30 years this will cost about $850 million. The low-interest municipal financing saves over $1 billion dollars over the 30 year period, far more than the entire installed cost of the wind farm. This demonstrates the huge effect of low cost borrowing on renewable generation sources like wind, and why there is a unique opportunity for municipalities. At the time when other investors will be leaving the market, municipalities will retain their low cost financing advantage. This places them in a unique position when tax credit expires to take advantage of any price reductions in wind farms. Wind resource is also vitally important for project viability. The East County has class 5 and class 6 winds. By placing a wind farm in the higher class region, a significant improvement is performance is very likely. Improving the output of a wind farm from a 32% operational capacity (capacity factor) to 35% would reduce the cost of the electricity generated and achieve a more rapid payback on investment. It also increases the cost threshold for a viable proj ect. Maintaining a high capacity factor is important for economic viability not only of the wind farm but also of the pumped storage portion of the facility. The cost assumption for the pumped storage of $1000 per kilowatt is conservative to high if an existing reservoir is used, but may be low if a new reservoir must be built. We recommend using existing reservoirs in the San Diego region, of which there are several. The given price is the maximum that would make the proposition viable for a CCA, thus it is only likely to make sense as an investment if an existing reservoir is used. There are also considerable environmental advantages when compared to building a new reservoir, creating an alignment between environmental and economic goals. Appendices 2 T bl A 1 W. d C t S a e - . In os ummarv Private Investor Chula Vista/ muuicipality Installed Cost Rate $1350 per kilowatt $1350 per kilowatt Tax Credit 2 cents/kilowatt hour, none first 10 vears Financing Cost 11.8% 5.25% Economic Lifecyc1e 30 years 30 years Wind Class 6 6 Operation / Capacity 35% 35% Cost per kilowatt-hour 7.4 cents/kwh 4.8 cents/kwh 1 st 10 year cost after credit 5.4 cents/kwh not applicable Electricity sale price (initial) 5.2 cents/kwh 4.8 cents/kwh Simple Payback 8 years 9 years Appendices 3 Table A-2. Wind Farm Electric Generation Cost with Private and Public Financing Levelized Cost Analysis in Class 6 Region* Private Finance Public Finance 11.8% Avg. Cost of Capital: 2 cent/kwh Production Tax Credit. Bond financing no tax credits Caoital Cost: Caoital Cost: Installed Cost Rate $1,350 per kw Installed Cost Rate $1,350 per kw Capacity 400,000 kw Capacity 400,000 kw Total Cost $540,000,000 Total Cost $540,000,000 Tax Credit 0% Tax Credit 0% Net Cost $540,000,000 Net Cost $540,000,000 Utility Finance: Public Finaoce: Avg. Cost of Capital 11.8% Bond Rate 5.25% Term 30 yrs Term 30 yrs Financing Cost $1,911,600,000 Financing Cost $850,500,000 Ooeration and Maintenance: Ooeration and Maintenance: Personnel 64 Personnel 64 Assumed avg. Salary $55,000 Assumed avg. Salary $55,000 Annual Personnel Cost $3,520,000 Annual Personnel Cost $3,520,000 Maintenance &other rate/capital-yr. 1.6% Maintenance &other rate/capital-yr. 1.6% Maintenance & other cost/year $8,640,000 Maintenance & other cost/year $8,640,000 Annual O&M $12,160,000 Annual O&M $12,160,000 Lifecycle O&M $364,800,000 Lifecycle O&M $364,800,000 Electric Generation: Electric Generation: Capacity Factor 35% Capacity Factor 35% kwh/k Generation rate 3,066 w Generation rate 3,066 kwhlkw Gross Annual generation 1,226,400,000 kwh Gross Annual generation 1,226,400,000 kwh Parasitic Load factorlloss 0.1% Parasitic Load factor/loss 0.1% Annual Loss 1,226,400 kwh Annual Loss 1,226,400 kwh Net Annual Output 1,225,173,600 kwh Net Annual Output 1,225,173,600 kwh Ar~p,ndices 4 Private Finance Public Financl' Electric Generation Cost: Electric Generation Cost: Lifecycle Cost $2,816,400,000 Lifecycle Cost $1,755,300,000 Lifecycle Output 36,755,208,000 kwh Lifecycle Output 36,755,208,000 kwh Avg. O&M rate $0.010 A vg. O&M rate $0.010 per Cost of Electricity $0.077 kwh Cost of Electricity $0.048 per Production Tax Credit (2009) $0.020 kwh Production Tax Credit $0.000 per Net first 10 year cost $0.057 kwh Net first 10 year cost $0.048 Sales from Wind Farm per Wind Purchase Price kwh Wind Wholesale Price Generation per year 1,225,173,600 kwh Direct sales per year 664,533,600 kwh Annual A vg. revenue $63,709,027 Annual revenue from Direct Sales $34,555,747 Annual A vg. Cost $93,880,000 Sales rate to Pumped Storage $0.048 Annual A vg. Cost first 10 years $69,376,528 Sales to Pumped Storage 560,640,000 kwh Annual Income from Pumped Storage $26,774,203 Total Wind Farm Annual Revenue $61,329,950 Annual Operating Cost $58,510,000 Annual Wind Farm Net $2,819,950 Simple Payback Wind 8.48 yrs Simple Payback Wind 8.80 years *Levelized cost does not show the time-dependent changes in O&M cost for wind farms. Appendices 5 Appendix B Solar Thermal wi Natural Gas and Cogeneration The cost of solar thermal power has decreased in the last two years, and there is general agreement that it will continue to drop. Current cost of solar thermal generation can range between 13 and 25 cents per kilowatt-hour, depending on scale of the installation, financing and availability of tax breaks. Private developers can take a generous 30% tax credit until 2008, which will revert to 10% unless the higher credit is further extended. DOE projects that solar thermal electric generation will fall to about 4 cents per kilowatt- hour within a decade, but Local Power considers this projection too optimistic. Those in the industry currently consider it reasonable to expect that the price will fall below 10 cents per kilowatt-hour, a range that will make solar thermal potentially cost competitive with the peak power generated by natural gas power plants. The first spreadsheet analyzes the cost and performance of a Concentrating Solar Thermal power plant. The first column shows the economics of a privately financed facility to allow comparison with a publicly financed one. The proposed solar thermal project would have about 10% to 15% lower solar resource than the recently developed solar thermal plants in Nevada and Arizona if located in the East County, and 20% to 25% lower if placed in the vicinity of Chula Vista. It would also not be eligible for a tax write-off due to the fact that it would be owned by a municipality. Countering this disadvantage is the much lower cost of capital, which is only the interest payment on the bond. Recycling the heat through a cogeneration system will bring the cost down further. The net cost to produce a kilowatt-hour, and the profitability of the plant, is significantly influenced by the efficiency with which the heat can be recycled. The assumption is only 50% of the waste heat can be recovered and sold at prevailing energy rates. This is very conservative, as such systems can achieve 75% to 80% recovery on the high end. If the recovery is efficient enough, then the heat can be sold at a discount to make the proposition attractive to a commercial venture. A solar thermal plant's economic viability is to a large extent locked in at the time of purchase. Unlike a natural gas power plant, very little of the long term cost is bound up in fuel. The major expense is the purchase cost itself, and the cost of financing. Whether this will be competitive with natural gas peak power depends on the future cost of natural gas. The second sheet shows the breakeven costs for the solar plant assuming a range of average prices for natural gas. In this sheet, the assumption is that the plant is financed over a 30 year period by a capital bond as a "self supporting" investment. Appendices 6 Table B-1. Concentrating Solar Thermal Power Private Finance, 2010 to 2015 Public Finance, 2010 to 2015 Public Finance, 2010 to 2015 ',"'/nO tax Crl'dit & 5.25l% 30 year municipal bond wino tax credit & 5.:::!5('l.. 30 year municipal Wi ta\ credit & 11.50;,i, Cost of Capital financing bond financing Reference ~atural Gas Price Reference 'aWnl Gas Price High :'\latural Cas Price Scenario Capital Cost: Capital Cost: Capital Cost: Installed Cost Rate Installed Cost Rate Installed Cost Rate Target $2,500 per kw Target $2,500 per kw Target $2,500 per kw Capacity 160,000 kws Capacity 160,000 kws Capacity 160,000 kws Total Cost $400,000,000 Total Cost $400,000,000 Total Cost $400,000,000 Tax Credit (enter 10% or 30%) 10% Tax Credit 0% Tax Credit 0% Net Cost $360,000,000 Net Cost $400,000,000 Net Cost $400,000,000 Private Finance Public Finance: Public Finance: A vg. Cost of Capital 11.8% Bond Rate 5.25% Bond Rate 5.25% Term 30 years Term 30 years Term 30 years Financing Cost $1,274,400,000 Financing Cost $630,000,000 Financing Cost $630,000,000 Ooeration and Ooeration and Ooeration and Maintenance: Maintenance: Maintenance: Personnel 70 Personnel 70 Personnel 70 Assumed avg. Salary $55,000 Assumed avg. Salary $55,000 Assumed avg. Salary $55,000 Annual Personnel Annual Personnel Cost $3,826,087 Annual Personnel Cost $3,826,087 Cost $3,826,087 Maintenance &other Maintenance &other Maintenance &other rate/capital-yr. 0.6% rate/capital-yr. 0.6% rate/capital-yr. 0.6% Maintenance & other Maintenance & other Maintenance & other cost/year $2,400,000 cost/year $2,400,000 cost/year $2,400,000 Annual O&M $6,226,087 AnnuaIO&M $6,226,087 Annual O&M $6,226,087 Lifecyc1e O&M $186,782,609 Lifecyc1e O&M $186,782,609 Lifecyc1e O&M $186,782,609 O&M per kwh $0.021 O&M per kwh $0.021 O&M per kwh $0.021 Appendices 7 Private Finance. 2010 to 2015 Public Finance. 2010 to 2015 Public Finance. 2010 to 2015 wino tax credit & 5.25% 30 year municipal bond wino tax credit & 5.250/0 30 :year municipal wi tax credit & 11.5% Cost 01' Capital financing bond financing Reference Natural Gas Price Reference Natural Gas Price High Natural Gas Price Scenario Solar Electric Solar Electric Solar Electric Generation: Generation: Generation: Capacity Factor 23% Capacity Factor 23% Capacity Factor 23% Generation rate 2,015 kwhlkw Generation rate 2,015 kwhlkw Generation rate 2,015 kwhlkw Gross Annual Gross Annual Gross Annual generation 322,368,000 kwh generation 322,368,000 kwh generation 322,368,000 kwh Parasitic Load Parasitic Load Parasitic Load factorlloss 8% factor/loss 8% factorlloss 8% Annual Loss 25,789,440 kwh Annual Loss 25,789,440 kwh Annual Loss 25,789,440 kwh Net Annual Output 296,578,560 kwh Net Annual Output 296,578,560 kwh Net Annual Output 296,578,560 kwh Solar 'Electric Solar 'Electric Solar 'Electric Generation Cost: Generation Cost: Generation Cost: Lil'ecycle Cost $1,861,182,609 Lil'ecycle Cost $1,216,782,609 Lil'ecycle Cost $1,216,782,609 Lil'ecycle Output 8,897,356,800 kwh Lil'ecycle Output 8,897,356,800 kwh Lil'ecycle Output 8,897,356,800 kwh Cost 01' Solar Cost 01' Solar Electricity $0.209 per kwh Electricity $0.137 per kwh Cost of Electricity $0.137 per kwh Gas Electric Gas Electric Gas Electric Generation: Generation: Generation: Capacity Factor 11% Capacity Factor 11% Capacity Factor 11% Generation rate 964 kwhlkw Generation rate 964 kwhlkw Generation rate 964 kwhlkw Gross Annual Gross Annual Gross Annual generation 154,176,000 kwh generation 154,176,000 kwh generation 154,176,000 kwh per per per Fuel Cost $6.50 MMBtu Fuel Cost $6.50 MMBtu Fuel Cost $10.00 MMBtu heat rate 9400 btulkwh heat rate 9400 btulkwh heat rate 9400 btulkwh el'ficiency 0.36 efficiency 0.36 efficiency 0.36 annual energy input 1,449,254 MMBtu annual energy input 1,449,254 MMBtu annual energy input 1,449,254 MMBtu annual energy cost $9,420,154 annual energy cost $9,420,154 annual energy cost $14,492,544 A"'~endices 8 Private Finance, 2010 to 2015 Pnblic Finance. 2010 to 2015 Public Finance, 2010 to 2015 '''"/no tax credit & 5.25(YO In year municipal hond wlnn tax credit & 5.251~() 30 ~:car municipal . wi tax credit & 11.5~/n Cost of Capital financing bond financing Referenet' '\Jatllral Gas Price Referenn ~atural Gas PriCt' High 'atural Gas PriCl' Scenario Lifecycle energy Lifecycle energy input 43,477,632 MMBtu Lifecycle energy input 43,477,632 MMBtu input 43,477,632 MMBtu Lifecycle electricity Lifecycle electricity Lifecycle electricity output 4,625,280,000 kwh output 4,625,280,000 kwh output 4,625,280,000 kwh Lifecycle cost of fuel $282,604,608 Lifecycle cost of fuel $282,604,608 Lifecycle cost of fuel $434,776,320 Combined Cost of Combined Cost of Combined Cost of SolarlNatural Gas SolarlNatural Gas SolarlNatural Gas Generation Generation Generation Generation 13,522,636,800 kwh Generation 13,522,636,800 kwh Generation 13,522,636,800 kwh Capacity Factor 32.2% Capacity Factor 32.2% Capacity Factor 32.2% Total Cost $2,143,787,217 Total Cost $1,499,387,217 Total Cost $1,651,558,929 Combined Cost of Combined Cost of Electricity $0,159 Electricity $0.111 Cost of electricity $0.122 Thermal Enenrv Thermal Energv Thermal Enemy annual natural gas 1,449,254 MMBtu annual natural gas 1,449,254 MMBtu annual natural gas 1,449,254 MMBtu annual solar thermal 2,780,500 MMBtu annual solar thermal 2,780,500 MMBtu annual solar thermal 2,780,500 MMBtu annual total thermal annual total thermal annual total thermal input 4,229,754 MMBtu input 4,229,754 MMBtu input 4,229,754 MMBtu annual generation 450,754,560 kwh annual generation 450,754,560 kwh annual generation 450,754,560 kwh annual heat value 1,537,073 MMBtu annual heat value 1,537,073 MMBtu annual heat value 1,537,D73 MMBtu residual heat value 2,692,681 MMBtu residual heat value 2,692,681 MMBtu residual heat value 2,692,681 MMBtu Cost of Electricity Cost of Electricity Cost of Electricity Usinl! COl!eneration Usinl! COl!eneration Usinl! Coeeneration cogen heat per cogen heat repurchase per cogen heat repurchase per repurchase rate $6.50 MMBtu rate $6.50 MMBtu rate $10.00 MMBtu recovery rate 50% recovery rate 50% recovery rate 50% heat recovered per heat recovered per heat recovered per year 1,346,341 MMBtu year I ,346,341 MMBtu year 1,346,341 MMBtu Appendices 9 Private Finance. 2010 to 2015 Public Finance. 2010 to 2015 Public Finance. 2010 to 2015 wino tax credit & 5.250/0 30 year municipal bond wIno tax credit & 5.25%) 30 year municipal wi tax credit & 11.5% Cost of Capital financing bond financing Reference Natural Gas Price Reference Natural Gas Price High Natural Gas Price Scenario totallifecycle heat 40,390,219 MMBtu totallifecycle heat 40,390,219 MMBtu totallifecycle heat 40,390,219 MMBtu total economic value $262,536,422 total economic value $262,536,422 total economic value $403,902,188 net electric cost SO.139 per kwh Dct electric cost SO.091 per kwh net electric cost SO.092 per kwh Electricity Wholesale Electricity Wholesale Electricity Wholesale PriceIMPR $0.095 per kwh Price/MPR $0.095 per kwh PriceIMPR $0.128 per kwh Generation per year 450.754.560 kwh Generation per year 450,754,560 kwh Generation per year 450,754,560 kwh Annual Sales $42,866,759 Annual Sales $42,866,759 Annual Sales $57,696,584 simple payback 9.3 years simple payback 9.3 years simple payback 6.9 years Financial Cycle Financial Cycle Financial Cycle Balance -$595,248,035 Balance $49,151,965 Balance $483,240,769 Annual Net -$19,841,601 Annual Net $1,638,399 Annual Net $16,108,026 30 Year Net -$595,248,035 30 Year Net $49,151,965 30 Year Net $483,240,769 generation fuel generation fuel output generation fuel output output cost $0.061 cost $0.061 cost $0.094 with mpr capital and with mpr capital and with mpr capital and variable cost $0.095 $0.034 variable cost $0.095 $0.034 variable cost $0.128 $0.034 Ar~~ndices [(l Appendix C Natural Gas Costs Table C-l uses DOE projections for natural gas prices until 2030, and extrapolates these to 2040, showing fixed 2004 dollars as well as the corresponding higher nominal inflated dollar equivalent. This places natural gas at a nominal average of $10 per MMBtu between 2009 and 2040, which we use as a HIGH natural gas price scenario. The BASE CASE price is set at $6.50 per MMBtu, while the LOW CASE is $5.00 per MMBtu. We see this as conservative, particularly for a date range running from 2010 to 2040. It is important to take into account this conservative basis when evaluating the investments in the renewable portfolio, as this offers opportunity to profit from upside natural gas risk. Since a significant part of the portfolio is also tied to natural gas, any decreases in natural gas prices will partly offset the renewables that would become relatively more expensive. On the other hand, if natural gas prices rise above current levels, as reflected in the base case, then the renewables will be the lower cost investment. Diversification of the portfolio leads to a double hedge. The gas price figures are input into a model for electric generation cost for a peaking plant, assuming a heat rate of 9400 Btu per kilowatt-hour for a simple cycle combustion turbine. Variable and fixed costs are set for a plant that operates at 32% capacity factor. A higher natural gas price will tend to favor renewable facilities, making these investments into natural gas price hedges, as they lock in the cost of generating electricity just as a fuel futures contract would. The difference, however, is that renewables provide this hedge out to 30 and 50 or more years, much longer than any available natural gas contract. By this time, it is expected that the US may face serious depletion of natural gas fuel. Facilities that either do not rely on natural gas, or that rely on it minimally, will be at a great advantage. Tables C-2 through C-4 compare a variety of natural gas plant investments. The current plant is relatively cheap to run, (with the exception of unit #4), because the capital expense is mostly paid off. A newer peaking plant is not necessarily much more efficient in fuel consumption, as heat rates for simple cycle combustion turbines range from about 9000 Btulkwh to 10,000 Btulkwh, with the higher end quite close to the existing plant. For this reason, a new natural gas plant is not likely to avert any future fuel consumption or expense. The economics of a peaking plant is only partly determined by the heat rate. More important is how many hours per year it is run. The fewer the hours, the more expensive the power, since capital cost becomes more important than fuel as capacity utilization drops. A simple cycle plant is modeled here, because the report examines a functional replacement for the current plant. However, it would be possible to purchase a combined cycle plant with baseload or multiple functionality. The other major factor is financing cost, as for the renewables. The CCA, using low cost bonds, is at a great advantage in this regard, and can use the natural gas peaker to offset some of the potential near term losses for the fixed cost, renewable generators. Tables C-5 and C-6 show the cost of operating a natural gas peaker plant under private and CCA ownership at low, base, and high natural gas price projections. Appendices II Table C-l. Natural Gas Price Projections to 2040 in dollars per million btu Year delta 1003 1004 1005 1006 1007 1008 1009 1010 1011 1011 1013 1014 1015 NG for electric power; 2004 dollars 0.30% $5.81 $6.07 $8.29 $7.43 $6.71 $6.38 $5.92 $5.60 $5.40 $5.38 $5.49 $5.41 $5.21 Nominal dollars $5.66 $6.07 $8.50 $7.77 $7.16 $6.96 $6.60 $6.38 $6.30 $6.44 $6.73 $6.80 $6.70 Heat rate 9400 9400 9400 9400 9400 9400 9400 9400 9400 9400 9400 9400 9400 efficiency 36.28% 36.28% 36.28% 36.28% 36.28% 36.28% 36.28% 36.28% 36.28% 36.28% 36.28% 36.28% 36.28% generation fuel output cost $0.053 $0.057 $0.080 $0.073 $0.067 $0.065 $0.062 $0.060 $0.059 $0.061 $0.063 $0.064 $0.063 with capital and variable cost $0.034 $0.087 $0.091 $0.114 $0.107 $0.101 $0.099 $0.096 $0.094 $0.093 $0.095 $0.097 $0.098 $0.097 Consumer price index GDP Chaln- Type Price Index (2000=01.000) 2.00% 1.063 1.091 1.119 1.141 1.164 1.189 1.216 1.242 1.273 1.306 1.338 1.370 1.404 2004 index 0.974 1.000 1.026 1.046 1.067 1.090 1.114 1.139 1.167 1.197 1.226 1.256 1.287 Year 1016 1017 1018 1019 1010 1011 1011 1013 1014 1015 1016 1017 1018 NG for electric power; 2004 dollars $5.19 $5.23 $5.40 $5.54 $5.53 $5.66 $5.73 $5.79 $5.90 $6.02 $6.08 $6.17 $6.21 Nominal dollars $6.83 $7.05 $7.46 $7.85 $8.03 $8.42 $8.74 $9.04 $9.42 $9.84 $10.16 $10.55 $10.86 Heat rate 9400 9400 9400 9400 9400 9400 9400 9400 9400 9400 9400 9400 9400 efficiency 36.28% 36.28% 36.28% 36.28% 36.28% 36.28% 36.28% 36.28% 36.28% 36.28% 36.28% 36.28% 36.28% generation fuel output cost $0.064 $0.066 $0.070 $0.074 $0.075 $0.079 $0.082 $0.085 $0.089 $0.092 $0.096 $0.099 $0.102 with capital and variable cost $0.098 $0.100 $0.104 $0.108 $0.109 $0.113 $0.116 $0.119 $0.123 $0.126 $0.130 $0.133 $0.136 Consumer price index GDP Chain-Type Price Index (2000-1.000) 1.436 1.471 1.508 1.546 1.584 1.624 1.663 1.703 1.742 1.783 1.824 1.866 1.909 2004 index 1.316 1.348 1.382 1.417 1.452 1.488 1.525 1.561 1.597 1.634 1.671 1.710 1.749 Ar-.ondices 12 Year 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 Average NG for electric powerj 2004 dollars $6.28 $6.41 $6.43 $6.45 $6.47 $6.49 $6.51 $6.53 $6.55 $6.57 $6.59 $6.60 $6.09 Fixed $ Nominal dollars $11.24 $11.74 $12.01 $12.29 $12.57 $12.86 $13.16 $13.46 $13.77 $14.09 $14.41 $14.74 $9.44 Nominal $ Heat rate 9400 9400 9400 9400 9400 9400 9400 9400 9400 9400 9400 9400 efficiency 36.28% 36.28% 36.28% 36.28% 36.28% 36.28% 36.28% 36.28% 36.28% 36.28% 36.28% 36.28% generation fuel output cost $0.106 $0.110 $0.113 $0.115 $0.118 $0.121 $0.124 $0.127 $0.129 $0.132 $0.135 $0.139 with capital and variable cost $0.140 $0.144 $0.147 $0.149 $0.152 $0.155 $0.158 $0.161 $0.163 $0.166 $0.169 $0.173 $0.123 per kwh Nominal $ Consumer price index GDP Chain-Type Price Index (2000~ 1.000) 1.953 1.998 2.038 2.079 2.120 2.163 2.206 2.250 2.295 2.341 2.388 2.435 2004 index 1.790 1.831 1.868 1.905 1.943 1.982 2.022 2.062 2.103 2.146 2.188 2.232 Projections to 2030 from: Annual Energy Outlook 2006 with Projections to 2030 Report #: DOEIEIA-0383(2006) Release Date: December 2005 Table 19. Macroeconomic Indicators Appendices 13 Table C-2. New Combustion Turbine Peaker, CCA Ownership Natural Gas to Generate 1 KWh CostlMMBtu $6.50 Size of Plant 160,000 kw conversion to kwh 3419 btu/kwh Annual Generation 448,512,000 kwh Lifecycle fuel-cost/kwh $0.022 Generation 8,970,240,000 kwh heat rate 9400 btu/kwh efficiency 36.4% Lifecycle Costs factor 2.75 Capital Cost $76,000,000 electricity fuel-cost/kwh SO.061 Cost of Money $83,600,000 Lifecycle Fuel Cost $548,081,664 Cost of Gen Facility Variable Cost $51,918,348 Total Lifecycle Cost of Equipment $0.48 per watt Cost $759,600,012 lifecycle 20 years Savings Vs. Private capacity factor 32% Ownership -$30,720,384 output rate 2803 kwh/kw-yr life output/watt 56.06 kwh unfinanced cost $0.008 per kwh interest rate + ROI 5.5% cost of money $0.009 per kwh total cap cost $0.018 per kwh Variable costs $0.006 per kwh Total Gen Costs SO.085 per kwh Appendices 14 Table C-3. New Combustion Turbine Peaker, Private Ownership Natural Gas to Generate 1 KWh Cost/MMBtu $6.50 Size of Plant 160,000 kw conversion to kwh 3419 btu/kwh Annual Generation 448,512,000 kwh fuel-costlkwh $0.022 Lifecycle Generation 8,970,240,000 kwh heat rate 9400 btu/kwh efficiency 36.4% Lifecycle Costs factor 2.75 Capital Cost $76,000,000 electricity fuel-costlkwh $0.061 Cost of Money $179,360,000 Lifecycle Fuel Cost $548,081,664 Cost of Gen Facility Variable Cost $51,918,348 Cost of Equipment $0.48 per watt Total Lifecycle Cost $855,360,012 lifecycle 20 years capacity factor 32% kwhlkw- output rate 2803 yr life output/watt 56.06 kwh unfinanced cost $0.008 per kwh interest rate + ROI 11.8% cost of money $0.020 per kwh total cap cost $0.028 per kwh Variable costs $0.006 per kwh Total Gen Costs $0.095 per kwh Appendices 15 Table C-4. New Combined Cycle, Base Load, Private Ownership Natural Gas to Generate 1 KWh Cost/MMBtu $6.50 Size of Plant 500,000 kw conversion to kwh 3419 btulkwh Annual Generation 3,591,600,000 kwh Lifecycle fuel-costlkwh $0.022 Generation 107,748,000,000 kwh heat rate 6200 btulkwh efficiency 55.1% Lifecycle Costs factor 1.81 Capital Cost $325,000,000 electricity fuel-costlkwh $0.040 74.27% Cost of Money $1,150,500,000 Lifecycle Fuel Cost $4,342,244,400 Cost of GeD Facility Variable Cost $243,367,254 Cost of Equipment $0.65 per watt Total Lifecycle Cost $6,061,111,654 lifecycle 30 years capacity factor 82% output rate 7183 kwhlkw-yr life output/watt 215.50 kwh unfinanced cost $0.003 per kwh interest rate + ROl 11.8% cost of money $0.011 per kwh total cap cost $0.014 per kwh Variable costs $0.002 per kwh Total GeD Costs $0.056 per kwh Appendices 16 Table C-5. Cost of operating a natural gas peaker plant at low, base, and high natural gas projections under private ownership. Natural Gas to Generate 1 KWh Low Base DOE/Hillh Cost/MMBtu $5.00 $6.50 $10.00 conversion to kwh 3419 btu/kwh 3419 btu/kwh 3419 btu/kwh fuel-cost/kwh $0.017 $0.022 $0.034 heat rate 9400 btu/kwh 9400 btu/kwh 9400 btu/kwh efficiency 36.4% 36.4% 36.4% factor 2.75 2.75 2.75 electricity fuel-cost/kwh $0.047 $0.061 $0.094 Cost of Gen Facility Cost of Equipment $0.48 per watt $0.48 per watt $0.48 per watt lifecycle 20 years 20 years 20 years capacity factor 32% 32% 32% kwh/kw- output rate 2803 yr 2803 kwh/kw-yr 2803 kwh/kw-yr life output/watt 56.06 kwh 56.06 kwh 56.06 kwh unfinanced cost $0.008 per kwh $0.008 per kwh $0.008 per kwh interest rate + ROt 11.8% 11.8% 11.8% cost of money $0.020 per kwh $0.020 per kwh $0.020 per kwh total cap cost $0.028 per kwh $0.028 per kwh $0.028 per kwh Variable costs $0.006 per kwh $0.006 per kwh $0.006 per kwh Total Gen Costs $0.081 per kwh $0.095 per kwh $0.128 per kwh Appendices 17 Table C-6. Cost of operating a natural gas peaker plant at low, base, and high natural gas projections under public ownership. Natural Gas to Generate 1 KWh Low Base DOE/Hiah Cost/MMBtu $5.00 $6.50 $10.00 conversion to kwh 3419 btu/kwh 3419 btu/kwh 3419 btu/kwh fuel-cost/kwh $0.017 $0.022 $0.034 heat rate 9400 btulkwh 9400 btu/kwh 9400 btu/kwh efficiency 36.4% 36.4% 36.4% factor 2.75 2.75 2.75 electricity fuel-cost/kwh $0.047 $0.061 $0.094 Cost of Gen Facility Cost of Equipment $0.48 per watt $0.48 per watt $0.48 per watt Iifecycle 20 years 20 years 20 years capacity factor 32% 32% 32% output rate 2803 kwh/kw-yr 2803 kwh/kw-yr 2803 kwh/kw-yr life outpullwatt 56.06 kwh 56.06 kwh 56.06 kwh unfinanced cost $0.008 per kwh $0.008 per kwh $0.008 per kwh interest rate + ROI 5.5% 5.5% 5.5% cost of money $0.009 per kwh $0.009 per kwh $0.009 per kwh total cap cost $0.018 per kwh $0.018 per kwh $0.018 per kwh Variable costs $0.006 per kwh $0.006 per kwh $0.006 per kwh Total Gen Costs $0.071 per kwh $0.085 per kwh $0.118 per kwh rate savings $0.011 per kwh $0.011 per kwh $0.011 per kwh AppeD,1'~es 18 Appendix () Photovoltaics Table D-I examines the effect of various financial inputs into the cost per kilowatt-hour of electricity generated by solar photovoltaic system. One assumption here is that commercial entities will purchase the photovoltaic systems, and be eligible to receive tax credits and state rebates. The federal tax credit is conservatively assumed to revert to 10%, as it will naturally do after 2007 if no legislative action is taken. If the current 30% credit is extended, then the economics of photovoltaics will significantly improve for commercial/industrial sector customers that have a tax liability. The model assumes that commercial customers will borrow money for a 5 year period, paying 7.5% interest on a conventional commercial loan with a declining balance. The interest is taken on the full purchase price, not the after rebate price of the solar system. That is because we expect the new rebate program under the California Solar Initiative to payout performance incentives over a 5 year period, so they will not affect the amount of the initial borrowing. However, upfront rebate payments under the current program design will be offered for photovoltaic systems smaller than 100 kilowatts. The model also makes some generic assumptions about electric rates, such as a 5% local tax on sales of electricity and an initial 12 cent a kilowatt-hour rate. These only represent approximations for comparison sake. The lifecycle costs are modeled for a medium to large (10+ kilowatt) sized commercially owned photovoltaic system, and would have to be significantly modified for publicly owned or publicly financed systems, or for small home sized systems. The analysis uses a range of cost per watt for capital expense as the basic input on the left side, running from $6.00 to $9.00 per watt of direct current electric generation capacity, a range that most photovoltaic systems would fall into. This installed capacity cost is then translated, using the various input values for performance, tax credits, loan terms and rebate, entered in the boxes in the lower part of the spreadsheet, into an effective electric rate expressed as a cost per kilowatt-hour over the life of the photovoltaic system. The lifecycle is assumed to be 30 years, which is likely to be conservative since photovoltaic modules can usually produce electricity for many more years. Most of the cost is upfront, but there is a small ongoing operation and maintenance expense, and every 10 to 20 years the inverter needs to be replaced. The larger the system, the longer the inverter is likely to last (and the lower the unit cost for replacement). Appendices 19 Table D-l. Photovoltaic Power Production Full Lifecycle Accounting: Commercial Ownership pretax Tax PVnet PV System PV System after rebate Interest* O&M inverter total cost cost/kwh henelit net cost costlkwh cost/watt cost/watt cost/watt cost/watt (de) (ac) (ac) (ac) $0.60 48% $9.00 $10.84 $8.84 $2.19 $0.33 $0.60 $11.97 $0.272 $5.49 $6.47 $0.147 $8.50 $10.24 $8.24 $2.07 $0.33 $0.60 $11.24 $0.255 $5.16 $6.09 $0.138 $8.00 $9.64 $7.64 $1.95 $0.33 $0.60 $10.52 $0.239 $4.82 $5.70 $0.129 $7.50 $9.04 $7.04 $1.83 $0.33 $0.60 $9.79 $0.223 $4.48 $5.31 $0.121 $7.00 $8.43 $6.43 $1.71 $0.33 $0.60 $9.07 $0.206 $4.14 $4.93 $0.112 $6.50 $7.83 $5.83 $1.58 $0.33 $0.60 $8.35 $0.190 $3.80 $4.54 $0.103 $6.00 $7.23 $5.23 $1.46 $0.33 $0.60 $7.62 $0.173 $3.47 $4.15 $0.094 . assumes pbi paid out over time, full upfront cost on declining balance loan Underlined row shows the tvoical cost within the last two years for commercial-scale oroiects in California DC output 1400 kwh/kw-yr AC derate 83% 1.20 rate years value kwh/kw- years 30.0 Initial output (ac) 1687 yr tax credits 10% I 10% loan term 5 years Final 1248 Fed tax rate 33% 5 33.00% interest rate 7.5% average 1467 state tax add 7% 12 7.00% Rebate/watt* * $2.00 total electricity/watt 44.02 kwh federal basis 95% tax on electric 0% net tax benefit 48.00% initial electric rate $0.120 per kwh solar peak premium $0.015 per kwh initial PV value rate $0.142 inverter cost $0.60 per watt total cool roof $0.000 per kwh inflation 81.1% inv. lifecycle 20 years final value local tax 5% rate $0.257 per kwh replacements total customer premium $0.000 per kwh avg. eff. rate $0.199 per kwh inverters $0.60 annual escalation 2% after tax rate $0.199 per kwh o&m 0.0075 per kwh per watt REC/environmental $0.000 per kwh accumulation $8.77 ac Appenrl;"es 20 Appendix ~~ SDG&E Rates and San Diego Electric Resources Tables E-l and E-2 give some basic facts about electric generation in San Diego County. Table E-I shows current rates for electric commodity charges by SDG&E, which pulls out the cost of electricity at different times of the day and year for time of use customers. These rates shown in the upper part of Table E-I exclude distribution and service charges, as well as surcharges and taxes, which form the rest of the bill. These costs tend to reflect the average wholesale cost of generating electricity, and range from 4 to over II cents per kilowatt-hour. The bottom part of the table adds the full charges back into the rate, showing an annual average cost of electricity of 15.44 cents per kilowatt-hour for customers on this rate schedule. It is noteworthy that the full cost range for photovoltaic electricity in Table D-I falls below this rate, which makes photovoltaics an excellent hedge against future electric rate increases, effectively freezing a commercial customer's rate below what they are presently paying. Table E-2 shows new power plants in San Diego County since 2001, and planned through 2008. A total of 1437 Megawatts of capacity will have been added during this period. This is likely enough to supply all the electricity needs of San Diego County's one-million-plus residential customers. · * According to the California Energy Commission, San Diego County had 1,013,799 residential customers in 2000 that consumed a total of 6,04] million kilowatt-hours, which equates to 5959 kilowatt-hours per account per year. This represents an average load of 5959 I 8760 ~ 0.68 kilowatts. Therefore, 1437 Megawatts of capacity would provide 1,437,000 divided by 0.68 ~ 2,113,345 customers' average load, about double the actual total number of customers. Of course, the electric system capacity has to be sized for maximum, not average, load. Yet, just the added capacity from 2001 through 2008 should meet all the needs of the county's one million residential customers, both base and peak load. Appendices 21 Table E-l. SDG&E Energy and UDC Charges as of 2/112006 02/01/2006 0.06855 0.04678 0.6855 0.04678 0.06855 0.04678 0.06855 0.04678 0.06855 0.04678 rat.~. for non-residential customers whose use is greater than 20kw 02/01/2006 0.11515 0.06637 0.04537 Schedule A- Residential and commercial customers whose use does not exceed 20 kw . '~~". ~.~ii&);C.;j6:; ~":t~. 02/01/2006 0.08144 0.05617 Department of Water Resources (DWR) Bond Charge ~;"F,~;Sifr~t'%_ill)~:.:~:~}~i~f:-f':"I::;!~~;)~::;i\:::;-:i;/';:;: 01/01/2006 0.00485 care and medical baseline excluded Schedule A- Residential Annual Service demand avg. fee avg. electricity service/kwh per month kw kwh 02/0]/2006 0.08144 0.085]5 0.17144 0.05617 0.07647 0.13749 0.154465 $9.10 5 3600 0.002527778 Appep ~: ces 22 Table E-2. San Diego County Power Plant Construction 2001-2009. Docket Capacity Construction Date Construction Original Actual On- Project number Status (MW) Completed Approved Start Date On-line line Date (percent) Date Wildflower Larksour - lntergen Ol-EP-I Operational 90 \00 04/04/2001 04/05/2001 07/01 07/16/2001 Escondido - Caloeak Ol-EP-IO Operational 49.5 100 06/06/200 I 06/07/200 I 09/01 09/30/2001 Border - Caloeak 01-EP-14 Operational 49.5 100 07/11/2001 07/12/2001 09/01 10/26/2001 Palomar Escondido - Semora 01-AFC-24 Operational 546 \00 08/06/2003 06/01/2004 03/06 04/06 Miramar Plant Operational 46 100 07/2005 online 1/2006 781 MW I;)' ';1 MMC Eseondido '".fi'lx-" '., 44 90% 07/2006 Biofuel Peaker Annonnced 22 Otav Mesa - Caloine 99-AFC-5 Construction 590 9 04/18/2001 9/10/01 9/10/0 01/08 by 2008 1437 MW Chula Vista 2 - Rameo 01-EP-3 62 0 06/13/2001 Cancelled Cancelled - Appendices 23 Appendix F Portfolios and Financing Table F-l shows the cost range of three different portfolio options, the expected annual electric generation, and the effective load carrying capacity of the facilities individually and in each of the portfolios. Some of the elements, such as photovoltaics, and perhaps wind, may not be counted by the ISO for reliability purposes. Partly for this reason, each portfolio is rated a bit higher than the stated level, but it would be possible to add to the size of the natural gas plant to make up for the difference. This would incur the least capital cost as a remedy. In addition, adjustments in the natural gas plant size may be necessary as different models come into production. If the City elects to get a mixed-use combined cycle natural gas plant, then the cost for a given size plant will likely be about 25% higher. On the other hand, the fuel efficiency may also be significantly higher. On the other hand, adding capacity to a natural gas power plant should be a last resort, used only if other strategies do not meet the requirements. We recommend meeting the resource needs by 1) examining the full range of resource options within the county using updated demand figures, 2) evaluating construction of the appropriate Green Energy Option, and 3) challenging the ISO to account adequately for the full range of clean energy sources. The financing assumptions are contained in Table F-2. It shows four different investor categories for power plants. These figures are used for all the plants evaluated, such as wind, pumped storage, concentrating solar thermal, and natural gas: 1) A 3'd party, private investor that borrows half the money from a bank and invests the other half out of their own resources. The expected rate of return for the portion they own is 14%; in reality this is likely to vary depending on the perceived risk. Half the money is assumed to be equity and half on borrowed funds from a bank. When the return on equity is averaged with a bank loan of7.5%, the average cost of money is shown to be 11.8%. These figures do not account for the effect of taxes. 2) Utility owner. These have lower borrowing rates than private investors, and lower rates of return on equity in the power plant. 3) City or JP A ownership. This is a 30 year bond financed facility based upon the capital asset and long term contracts to sell power. The rate of return, 5.25 percent, is interest paid annually on the full amount of the bond, which differentiates a bond from the standard declining balance mortgage or credit card loan with which most people are familiar. Current interest rates on municipal 30 year bonds are about one percent lower. This reflects conservative assumptions, as well as embedded finance costs. 4) CCA ownership. This would be a revenue bond, limited to 20 years, with repayment based on the general ratepayer revenue stream from electric bills to the CCA. The interest rate is shown as Y. point higher at 5.5 percent, to reflect the higher rate of return required for revenue bonds compared to bonds that are secured by a capital asset. Appendices 24 Table F-l. Green Energy Options-South Bay Replacement Generation Portfolios with Cost of Electricity (COE) \ for Wholesale Peak Power Generation Supply '" '" + . . c ~ .. c ~ ~E c" - = . ~ '" ..J .:._ ~"E- ~ .~ ~ ~~=: . ~ ... ~ EstirlUtH'd Cost Pl'ak COE low t'ast' Peak COE base cast' Peak COE hif!:h cast' = " . ... ~ " ... .- 1.0 C. .... ="~ . ~ . . ~ = = a'" < ~ U "u ~ ~UU ~ Cost .:: '" " per per per watt Total Cost kwh annual kH}h amllur! kwh lltllllwl Cunt'nt Plant \alue 700 700 23% 1,410,360,000 $0.15 $105,000,000 Current Plant ReplacClIll'nt (potential) 620 620 80% 4,344,960,000 $0.65 $403,000,000 ,"atural Cas Peaker See Table C-5 for calculations ~ $0.081 $0.095 $0.128 Gr<<JlEnel'gy J>1>tltfO}jQS '\Itl%'!'iolllti.... Wind Plant 400 20% 80 35% 1,226,400,000 $1.35 $540,000,000 Pumped Storage net adjust -183 100% 35% -560,640,000 Pumped Storage 150 100% 150 32% 420,480,000 $1.00 $150,000,000 $0.094 $39,525,120 $0.094 $39,525,120 $0.094 $39,525,120 Natural Gas Plant 220 100% 220 32% 616,704,000 $0.48 $105,600,000 $0.071 $43,785,984 $0.085 $52,419,840 $0.118 $72,771,072 Solar Thermal w/gas eDgen 160 100% 160 32%. 448,512,000 $2.50 $400,000,000 $0.091 $40,814,592 $0.091 $40,814,592 $0.092 $41,263,104 Photovoltaic 20 60% 12 17% 29,784,000 $7.00 $140,000,000 Demand reduction 20 100% 20 20% 35,040,000 Total 970 642 2,216,280,000 $1,335,600,000 $0.084 $124,125,696 $0.089 $132,759,552 $0.103 $153,559,296 ELCC Target 630 32% 1,766,016,000 Appendices 25 ." ~ 'g S + ~ u C '" .. c ~ :E ~ = '" .... '~'- '" -;~ ~ _ u ~ oE- ~ ,~ = ~ <>: Cl. = ... a .- ... 0.. ~ ~ ~ ~ tl = = t: !:IS !:IS u < = u t u ~ ~uu ~ Cl. u .. '" ~ '-' u Cost! watt >;:;';~~){~:~'~~N~~?"~0:,~'Q',-:-. Estimated Cost Peak COE low case Total Cost per kwh annual .~,B:-~0~i.;~~ji~~~t~~:-i per kwh Wind Plant 325 20% 65 35% 996,450,000 $1.35 Pumped Storage net adjust -120 100% 35% -336,384,000 Pwnped Storage 90 100% 90 32% 252,288,000 $1.00 Natural Gas Plant 190 100% 190 32% 532,608,000 $0.48 Solar Thermal w/gas cageD 160 100% 160 32% 448,512,000 $2.50 Photovoltaic 20 60% 12 17% 29,784,000 $7.00 Demand reduction 20 100% 20 20% 35,040,000 Total 805 537 1,958,298,000 ELCC Target 490 32% 1,373,568,000 AppeIl,l;~es $438,750,000 $90,000,000 $0.094 $91,200,000 $0.071 $400,000,000 $0.091 $140,000,000 $1,159,950,000 $0.083 26 $23,715,072 $37,815,168 $40,814,592 $102,344,832 Peak COE base case Peak COE hi2h case $0.094 $0.085 $0.091 $0.089 annual '0h:j;.,';-%:' --.... c~,,;, : $23,715,072 $45,271,680 $40,814,592 $109,801,344 per kwh ",,',:'-,'-! .,>J>;.",,-,.f'-' $0.094 $0.118 $0.092 $0.104 annual $23,715,072 $62,847,744 $41,263,104 $127,825,920 '0 '0 + Estimated Cost Peak COE low case Peak COE base cast' Peak COE hit!h case = = c o .. C o .. c .€ '"' = 'u ...;l .S ._ ..J .5 'u u 0 ";~ = ~ ~ u ~ C> = = ~ = = a: '" = I.. a. ".l:l '"' Q. ~~ ~ii~ = tl = = u = = u"" < = u t U U ~uu u Cost/ per pl" .. " '" W~)tt Total Cost kwh annual kwh allllllul er kwh annual 5&% Solilliful Wind Plant 150 20% 30 35% 459.900.000 $1.35 $202.500.000 Pumped Storage net adjust -80 100% 35% -224,256,000 Pumped Storage 60 100% 60 32% 168,192,000 $1.00 $60,000,000 $0.094 $15,810,048 $0.094 $15,810,048 $0.094 $15,810.048 Natural Gas Plant 90 100% 90 32% 252,288,000 $0.48 $43,200,000 $0.071 $17,912,448 $0.085 $21.444,480 $0.118 $29,769,984 Solar Thermal w/gas cagen 160 100% 160 32% 448,512,000 $2.50 $400,000,000 $0.091 $40,814,592 $0.091 $40,814,592 $0.092 $41,263,104 Photovoltaic 20 60% 12 17% 29,784,000 $7.00 $140,000,000 Demand reduction 20 100% 20 20% 35,040,000 Total 500 352 1,169,460,000 $845,700,000 $0.086 $74,537,088 $0.09 $78,069,120 $0.10 $86,843,136 ELCC Target 350 32% 981,120,000 Efficiency of Pumped Storage 75% Appendices 27 Table F-2. Financing Assumptions Private Utili tv Public CCA Equity 50% 50% 0% 0% Annual Return on Investment (RO!) 14.0% 10.5% 0.0% 0.0% Term years 30 30 30 20 Total ROI on Investment 2.10 1.58 0.00 0.00 Loan 50% 50% 100% 100% Interest rate 7.50% 7.00% 5.25% 5.50% Term years 20 30 30 20 Total Interest 0.75 1.05 1.58 1.10 Balance of term on equity 10 0 0 0 Balance on equity $0.70 $0.00 $0.00 $0.00 Total Cost of Capital per dollar of principal $3.55 $2.63 $1.58 $1.10 Average Effective Rate of Capital 11.8% 8.8% 5.3% 5.5% Appendices 28 Appendix G Pollution Comparison Calculations Table G-l shows the estimated particulate matter and carbon dioxide emissions from the existing South Bay Power Plant, the proposed South Bay Replacement Project, and the three Green Energy Option portfolios. Of the criteria pollutants, we chose to estimate emissions of particulate matter (PM), as this is the primary air pollution concern from the existing and proposed plants. Emissions of PM from power plants are significant, and PM levels in Chula Vista exceed state and national air quality standards. We also estimated carbon dioxide emissions to illustrate the differences in greenhouse gas emissions among the energy portfolio options. Table G-l. South Bay Power Plant Replacement Options, Comparison of Air Pollution and Greenhouse Gas Natural Gas Use Emissions Emissions Scenario Capacity Capacity Annual Heat PMI0/2.5 CO2 PMI0/2.5 CO2 Factor Generation Rate MW GWh/year btu/ MMBtu/ MMscf/ Tons/ Tons/ year Ibs/ lbs/ kwh year year year MWh MWh Existing South Bay Power Plant 700 320/0 1 1,962 10,068 19,755,832 19,180 72.9 1,155,716 0.074 1178 Proposed South Bay running as a base-load plant wi intermittent duct firing Replacement Plaut Base load 5002 80% 3,504 69933 24,503,472 23,790 90.4 1,433,453 0.052 818 With duct firing 120 9%4 96 9488 910,848 884 3.4 53,285 0.070 1110 Total for SBRP 620 66% 3,600 25,414,320 24,674 93.8 1,486,738 0.052 826 New Natural Gas Peaking Plant 700 32% 1,962 9400 18,445,056 17,908 68.0 1,079,036 0.069 1100 1 For comparison with the Green Energy Portfolios, the capacity factor is consistent with that of the GEOs. LS Power's AFC on the South Bay Replacement Project states that the SBPP's capacity factor is currently at about 30%. 2 SBRP AFC before CEC page 2-38 3 Table 2.3-6 in SBRP AFC before the CEC 4 Assumes 800 hours duct firing per year per CEC data request. Appendices 29 Natural Gas Use Emissions Emissions Scenario Capacity Capacity Factor Annual Generation Heat Rate btu/ MMBtu/ MMscf/ kwb year year \,~)j;;~s':":-ijt.t~;~:;7,':;i~S~; :\:}~:;2::~~~:F?1:~,~. ~:;. ,iH~:tf~~~!':1~!;:~.'l\~:r:' PMIO/2.5 CO2 PMIO/2.5 CO2 MW GWh/year '_l'v'ff_8t~~;c:';;':~'i'.lf!I';:/f:c,'jfc';~~Ci~",..,Cj.~:'.' T ons/ year Tons/ year Ibs/ MWh Ibs/ MWh :f:-i:?i'!'Sij~":. jdc' -'0-<"'" "'C:'-'J:; '>;;;f}'?k:;:;;=:0'-'^ Wind Plant 400 35% 1,226 Pumped Storage net adjust -183 35% -561 Pumped Storage 150 32% 420 Natural Gas Plant 220 32% 533 9400 5,797,158 5,628 21.4 339,126 0.069 llOO Solar Thermal 160 2]% 294 Natural Gas from Solar Thermal 160 11% 154 9400 1,449,254 1,407 5.3 84,781 0.359 5693 Photovoltaic 20 17% 30 Demand reduction 20 20% 175 2.216 7.246.242 7,035 26.7 423,907 0.024 383 Wind Plant 325 35% 996 Pumped Storage net adjust -110 35% -336 Pumped Storage 90 32% 252 Natural Gas Plant I ]90 32% 533 9400 5,006,515 4,861 18.5 292,88] 0.069 1]00 Solar Thermal 160 2]% 294 Natural Gas from Solar Thermal ]60 11% 154 9400 1,449,254 1,407 5.3 84,781 0.069 llOO Photovoltaic 20 17% 30 Demand reduction 20 20% 175 Toral 945 1.958 6,455,770 6.268 23.8 377.663 0.024 386 Appen,1;~es 30 Natural Gas Use Emissions Emissions Scenario Capacity Capacity Annual Heat PMIO!2.5 CO2 PMIO!2.5 CO2 Factor Generation Rate MW GWh!year btul MMBtu! MMscf! Tons! Tons! year Ibs! Ibs! kwh year year year MWh MWh 50% S9rotIell 3SOl\ifWELC Capadty Wind Plant 150 35% 460 Pumped Storage net adjust -73 35% -224 Pumped Storage 60 32% 168 Natural Gas Plant 90 32% 252 9400 2,371,507 2,302 8.7 138,733 0.069 1100 Solar Thermal 160 21% 294 Natural Gas from Solar Thermal 160 17% 238 9400 1,449,254 1,407 5.3 131,026 0.069 1100 Photovoltaic 20 17% 30 Demand reduction 20 20% 175.2 1.169 3.821J.761 4.477 l~.l 223515 1J.1J2~ 3H2 Notes: Efficiency of Pumped Storage 75% Btus natural gas!cubic foot 1031J Emission Factors: Particulate Matter 7.6 Ibs!scf EP A AP 42 emission factor for lotal PM C02 emission factor 117 pounds per MMBtu ofNG burned US EP A. Personal Emissions Calculator References. www.epa.gov/climatechange/emissions/ind_assumptions.html Appendices 31 · SDG&E is responsible and accountable for the electric and gas needs of San Diego County · We work with many agencies, municipalities and organizations to fulfill this responsibility · SDG&E's 2007 service area's peak load forecast: - 4,450 MW based on expected weather - 4,825 MW based on 1 in 10 hot weather · SDG&E will have sufficient resources under contract to meet this summer's forecasted peak load, plus a 150/0 planning reserve margin 2 CO'DG.~ ~, IE A ~ Sempra Energy uUHty" SAN DIEGO COUNTY N A Otay Mesa (-S60MW) "SA -/cO ~rgy utility- · Energy resource additions follow the State of California's "Energy Action Plan" and preferred sequencing order 1) Energy efficiency levels set based on cost-effectiveness analysis 2) Demand Response tied to CPUC goals 3) Renewable Power based on legislation 4) Generation based on "least cost/best fit" analysis 5) Transmission as required to meet reliability and cost criteria 4 CO'DG~ ~j !f A ~ Sempra Energy utility. · Electric load is forecasted to grow by 1.5 to 20/0 (-100-125 MW) a year; SDG&E will meet this growth with a balanced resource plan: Energy Efficiency that reduces demand by 487 MW and 2,561 GWHR by 2016 Demand Response will reduce peak demand by 249 MW Distributed Generation, including the California Solar Initiative, will reduce peak load by 225 MW Renewable Power will meet 20% of energy needs by 2010 and continue to grow over time Additional resources needed to meet a 15-17% planning reserve margin ~ Approximately 2,000 MW of contracts are terminating by 2012 ~ Resources to meet this need come from multiple sources, including current RFOs 5 CO'OG~ ~j !f A ~ Sempra Energy uWily. 2007 Mix Market Purchase 5% Nuclear 21% 2010 Mix Natural Gas 13% Renewables 6% Market Purchase 3% Nuclear 15% Coal 4% Natural Gas 29% DWR Contracts 19% Cogeneration 10% Cogeneration 9% Energy supplied under DWR contracts is primarily natural gas Renewables 22% 6 ~'DGr ~J IE A ~ Sempra Energy utility. 6COO Peak Demand + 15% Reserve Margin Peak Demand 10:0 6COO 4OCO ~ 30:0 20:0 o 2010 2011 2012 2013 2014 2016 ~'JExis:1in9 Renewable::: _Exisiing Resources '//.Peaking .......TotaJ Resouroe Requirement (Load + 15% Margin) _Exis:ting Generation """Base to Intermediate _Dispab::hable Demand Response _otay '/./~Ne.l\I RenE!lAlables ~SDG&E Load 7 CI'DG.~ ~, IE A ~ Sempra Energy utility' · Generation resources selected from the "least cost/best fit" proposals in "Request for Offers" Lowest total cost for customers Resource type driven by load shape Resource locations driven by transmission limitations All evaluations shared with the independent Procurement Review Group Selected resources filed with CPUC for approval, as required 8 tt'DG~ ~J !f A ~ Sempra Energy utility. · SDG&E works with the California Independent System Operator (CAISO) to plan expansion of the transmission system and maintain grid reliability · CAISO grid reliability criteria requires that the system must be able to service load on a hot summer day with a generation and transmission outage: - Loads based on 1 in 10 year hot weather - Loss of single largest generating plant (Palomar!Otay) - Loss of single largest transmission line (Southwest Powerlink) · The CAISO has approved addition of the Sunrise Powerlink to the Southern California electric power network · The CAISO has verified the Sunrise Powerlink as being the "least cost" method for meeting the regions energy objectives (grid reliability/renewable energy additions/cost) · The California Public Utilities Commission is now reviewing the proposed project. A decision is expected in January 2008. 9 "'DG~ ~, JE A ~ Sempra Energy uWily. To Oregon 500 kV Arizona 500 kV PGE-SCE San Franciscol Oakland 500 KV Cut Plane 500 kV DC 500 kV DC Utah Oregon 500 kV Nevada 500 kV Southern Nevada & Eastern LA Basin 4 - 230 kV Lines 500 kV LADWP-SCE SOB/' ...JE A ~ SempraEnagy u.'"," 5 - 230 kV Lines 500 kV Arizona 500 kV DC 500 kV 230 kV 500 kV Southern Nevada & Eastern LA Basin L"'DG~ ~j JE 1Q 230 kV MexIco A ~ Sempra Energy uliI"'. 1) Otay-Mesa Generating Station Bankruptcy Resolution Financing Arrangements - Construction Contract - Equipment Ordering 2) Local Power Supplies Evaluating bids for peaking supplies with 2008/2009 In-Service Dates R~O Issued for new supplies in 2010-2012 3) Sunrise Powerlink Project Licensing (January 2008) Construction & Operation (2010) 11 CO'DGl. ~j !f A ~ Sempra Energy u@ty" SDG&E has made significant progress toward meeting the MOU Objectives · Otay Metro Powerloop (OMPL) status - Project on schedule for energization to achieve undergrounding of the new 230 kV line by June 2007. · Underground conversion of 138 kV on Chula Vista Bayfront - Underground civil work (trenching, vaults, conduit) 95% complete. Project on target for completion prior to December 2008. · Silvergate Substation - CPUC permitting approved Sept. 2006. Demolition of Silvergate power plant underway. Project is scheduled for completion by end of 2008. · South Bay Switchyard Relocation - To be completed upon final disposition of South Bay power plant. · Overhead 138 kV Bayfront lines and Structures Removal - Dependent on decommissioning of the South Bay power plant, per CAISO. CO'DG~ ~j !f 12 A ~ Sempra Energy uW;ty. \ Pocilk: OCHn Old Town Substation < .. ~....... Replace existing 230-kV structures with new deadend and cable ole , 1lI"" , f 'Y Silvergate Substation Demolish existing structures Construct 4 bays of 230-kV buswork, 13 bays of 69-kV buswork, and install 2 transformers ./ ~t-- ,,~ , d' . , , , .....-~-_.. 1------ , Lemon Grove .....one.., '... -,.. ':t_oI!Ii , ~ Main Street Substation / ".'." " , Legend "'. -', ProJt>dOWI'il(l'''. _ lh);;"gm..lld.odF"OOiTIclTL13H!; -Elil~~AlIlJ""fT1'Wl11 . SlD.I"llI1'- a,.,lltIJMJlOIl; t . . , 'l~' \ EI Cajon _.....T , J J . ~ ....... ,."".. Chu Is Vista ~r~liIIKINolr 6000 lEm ;.4~:oj F~, ~.- . .. C!il30 . OMPL New 230 kV UG Line Installed 13 tt'DG~ ~, !f A ~ Sempra Energy utility' · SDG&E is responsible for our region's energy needs, which includes soliciting input and feedback from our region's stakeholders. · SDG&E's regional energy plan includes a balance of energy efficiency, renewable resources, as well as new generation (both owned and purchased) and transmission additions. · SDG&E's plan is in alignment with the State's Energy Action Plan and is subject to various regulatory approvals, including the CAISO, CEC and CPUC. · SDG&E's regional energy plan ensures the energy security of our region well into the future. 14 CO'DG~ ~j IE A ~ Sempra Energy "iliIy.