Advanced Metering Infrastructure: The Business Case for San Diego Gas & Electric Ed Fong Director, AMI                                                                 11/23/2018 Ed Fong, SDG&E AMI

SDG&E’s AMI Proposal File application with California Public Utilities Commission on March 15, 2005 requesting authorization to deploy AMI for all customers Covers 1.4 million electric and 900,000 gas customers by 2010 Planning and analysis horizon from 2005-2021

Background on SDG&E Integrated electric & gas distribution utility 1.3 million electric, 820,000 gas customers Covers all of San Diego County and most of South Orange County for electric Subsidiary of Sempra Energy Only California electric utility to remain financially sound during energy crisis of 2000-01

SDG&E Service Territory

Impetus for AMI SDG&E long-time proponent Energy crisis filed “real-time energy metering” RTEM application with California Public Utilities Commission (CPUC), A.00-07-055 Authorization for RTEM for 5,000 customers (>100 kW) in May 2001 Support for state funded advanced meters in 2001, AB 29X First CA utility to have default 3 period TOU rates for commercial & industrial customers in late 1980’s First utility to propose and hourly pricing option (HPO)

Impetus for AMI Energy crisis initiated great interest in demand response Advocates at the CPUC, California Energy Commission (CEC) and Governor’s office for dynamic pricing Proceeding established in June 2002, R.02-06-001, to investigate and develop framework for AMI, demand response and dynamic rates President of CPUC, Mr. Peevey, is assigned Commissioner to this proceeding Proceeding has led to extensive Statewide Pricing Program (SPP) covering Summer ’03 and ’04 involving some 3,000 customers

What is AMI? Advanced Metering Infrastructure Solid state interval meter Two-way communications integrated with meter Supporting telecommunications network Traffic management systems Meter data base management systems Customer Information and Billing systems integration Application of dynamic rates Data presentation to customer Customer services field Enabling appliance control technologies Other supporting in-home customer technologies

AMI Technology Architecture Wide Area Network CDMA RF Fiber BPL Local Area Network RNC Axispath Relay Transceiver Electric Meter MV-90 ODS Gas Meter CISCO/IDS/PBS Water Meter SDG&E Bill

Why the BIG Push and Interest? Demand response impacts and benefits Statewide Pricing Pilot (SPP) results Reduces peak demand, avoid marginal generation Overall peak day conservation effect Customer acceptance of time-differentiated rates Customer benefits- direct bill Market benefits Technology advancements Micro-processing Telecommunications (public and private networks)

SDG&E’s Application Highlights Request authorization for full deployment of AMI Recovery of new net AMI capital investment Recovery undepreciated meter assets Full deployment: treats all customers equally & logistically more efficient Plan for full deployment with off-ramps after 1st phase Expedited authorization of pre-deployment 2005-06 costs of $50 million Commission decision by June 30, 2005 Design, development and testing Software systems development 10,000 customer beta test in 2006

SDG&E’s Application Highlights Positive net present value of $46 million over 2005-2021 period from operational and demand response benefits Operational benefits from meter reading, customer services field, reduced theft, demand response program administration T&D benefits from deferred capital projects Avoided peak generation capacity from demand response Energy use reductions from demand response Difficult to quantify environmental, reliability, market efficiency benefits Key policy positions Reform of AB 1X required for default dynamic rate structures for right price signal and demand response benefits Emphasis on customer education/communications- intelligent decision making AMI technology is not AMR, but requires integration of many components development and testing Off ramps to mitigate risks for SDG&E and customers

Significant AMI Benefits Operational benefits O&M cost savings & avoidance Meter reading, customer Services field Demand response prog. mgt Capital reductions, avoidance, deferrals Electromechanical meter replacements T&D capacity deferrals Demand response Avoided generation capacity Energy savings Environmental CO2 emission reductions Reliability- avoid rolling blackouts, value of service

Significant AMI Costs 3 major phases Capital O&M Design, development, testing & planning Deployment & installation Ongoing operations & maintenance Capital AMI meter, gas module, communications equip & installation IT systems development (e.g., meter data systems mgt, meter inventory, etc.) O&M Customer education, communications Measurement data operations AMI equipment maintenance Gas module battery replacements Telecommunications

Evaluated Two Preferred Deployment Scenarios Full deployment All 1.4 million electric, 600,000 gas customers Complete by year end 2009 Begins with partial deployment with Inland climate zone customers Proceed if off-ramps not triggered Partial deployment Inland climate zone 600,000 electric and 400,000 gas All commercial & industrial customers >20 kW (20,000) Complete by year end 2008

Net Present Value Societal Perspective Present Value of AMI Societal Costs and Benefits ($ millions) Present Value (2005-2021) 1 2 3 4 Cost Operational Benefits Demand Response Benefits Net PV Full Deployment $ 612 $ 392 $ 268 $ 48 Partial Deployment $ 340 $ 242 $ 207 $ 109 77% of demand response benefits from 40% of customers Reduction in special voluntary demand response programs contribute to large portion of operational benefits

Undiscounted Costs & Operational Benefits (includes overheads and inflations) ($ millions) Full Deployment   Development & Installation 2005-2009 On-going 2010-2021 Total 2005-2021 Costs Capital $ 438 $ 278 $ 716 O&M + Other $ 99 $ 274 $ 374 Operational Benefits $ 17 $ 205 $ 223 $ 67 $ 617 $ 684 Partial Deployment   Development & Installation 2005-2008 On-going 2009-2021 Total 2005-2021 Costs Capital $ 194 $ 200 $ 394 O&M + Other $ 52 $ 172 $ 224 Operational Benefits $ 9 $ 162 $ 171 $ 26 $ 348 $ 374

Costs Categories O&M Capital Communication System Facilities AMI Project Management Billing Customer Contact Center Claims Communication System Load Control Technology Facilities Gas & Electric Meters / Gas Modules & installation (Gas & Electric) HR Information Technology Load Research Mass Markets / Major Markets Meter Reading Communication System Facilities Gas & Electric Meters / Gas Modules & installation (Gas & Electric) Information Technology Transmission & Distribution

Operational Benefits Categories Capital Benefits O&M Benefits Avoided Load Research Programs / Projects Customer Service Field Demand Response Avoided / Deferred G&E Meters & Labor and other E&G Mtr Savings IT for Meter Reading Meter Reading Mtr-Elec-Residual Mtr-Gas-Residual Transmission & Distribution Avoided Load Research Programs / Projects Billing Customer Contact Center Customer Service Field Claims Dem Resp Prog Mgt Avoided / Deferred G&E Meters & Labor and other E&G Mtr Savings Meter Reading Transmission & Distribution

Demand Response Assumptions Concurrent implementation of dynamic rates Legislative constraint from 2001 energy crisis created AB 1X SDG&E assumes CPP price structure similar to SPP 15 CPP days called Demand elasticities from SPP Constant elasticity of substitution Daily price elasticity Demand response is sustainable $85 kW year for avoided generation capacity Customer opt-out rate 20% or less

Statewide Pricing Pilot (SPP) Funded by CPUC for $19 million for 2003-04 3,000 customers (PG&E, SCE, SDG&E) 1,950 treatment customers w/dynamic rates 1,050 control group customers SDG&E 300 residential customers on various dynamic rates and 200 residential in various control groups Summer ’03 & ’04 impact analysis by Charles Rivers Associates (CRA) Average demand residential customer reduction during critical peak days ~ 14.4% Average reduction in warmer climate zones ~ 16% Commercial customer reductions are less

SPP – Summer Event Day Impact CPP-F, 8/27/03 Nbr of customers = 42; This simple aggregation of load data for customers in sample is not necessarily representative of the population at large - Results for population at large cannot be calculated without appropriate weighting and statistical adjustment of sample. Baseline = prior 10 day average usage for sample customers (includes weekdays, does not include holidays or prior event days)

SPP – Summer Event Day Impact CPP-V, 8/27/03 Nbr of customers = 110; This simple aggregation of load data for customers in sample is not necessarily representative of the population at large - Results for population at large cannot be calculated without appropriate weighting and statistical adjustment of sample. Baseline = prior 10 day average usage for sample customers (includes weekdays, does not include holidays or prior event days)

Demand Response Benefits (Full Deployment) 2010 First Full-Year Demand Response Impact   $ Millions (Nominal) Peak MW Forecast MW Reduction Capacity Avoided Energy Bills Full Deployment Residential 1151 176 $18.5 $1.1 Small C&I (<20 kW) 409 26 2.7 0.3 Medium1 C&I (20-99 kW) 415 42 4.4 0.2 Medium2 C&I (100-300 kW) 338 44 4.6 Total 2938 360 $37.9 $2.3

Present Value of Demand Response Benefits 2004 $ ($ Millions)   Capacity Energy Total Full Deployment Residential $ 124.6 $ 8.9 $ 133.5 Small C&I (<20 kW) 16.9 2.4 19.3 Medium1 C&I (20-99 kW) 28.3 1.6 29.9 Medium2 C&I (100-300 kW) 29.7 1.4 31.1 Large C&I (>300 kW) 51.2 3.1 54.4 Total PV Full Deploy $ 250.7 $ 17.5 $ 268.2