Cost-effectiveness Workshop One: The E3 Avoided Cost Model and Discount Rate

Cost-effectiveness Workshop One: The E3 Avoided Cost Model and Discount Rate Energy Division June 28th, 2012

Workshop Agenda Introduction and Overview 10:00 – 10:30am Resource Balance Year 10:30 – 11:00am Long-run Resource Cost 11:00 – 11:30am Break 11:30 – 11:45am Generation Capacity Cost Allocation 11:45am – 12:30pm Avoided RPS Cost 12:30 – 12:45pm GHG Costs and Double Counting 12:45 – 1:00pm Lunch 1:00 – 2:00pm T&D Avoided Costs 2:00 – 2:45pm Break 2:45 – 3:00pm Discount Rates 3:00 – 4:00pm Other Issues 4:00 – 5:00pm

Avoided Cost and Discount Rate Workshop Objectives To provide parties the opportunity to examine the E3 Avoided Cost Model and the Discount Rate currently used in cost-effectiveness tests. To provide parties the opportunity to determine whether modifications to the E3 Avoided Cost Model and/or the Discount Rate are necessary to improve cost-effectiveness analyses.

History

Avoided Cost Methodology • The 2004 Decision for EE highlighted some characteristics that are common to all of the methods. • The avoided costs resulting from E3’s methodology are also transparent and easily updated. In the existing hybrid market, an open and dynamic method is [of] critical importance. (D.05-04-024, pp. 38) • [T]he recommended methodology is relatively simple, transparent and relies on no proprietary data or software. (D.05-04-024, pp. 39) • The importance of transparency was confirmed for DR. • We find that any potential increase in accuracy that may be gained through the use of confidential data and proprietary models is outweighed by the lack of transparency introduced in the calculations through the use of these non-public data sources. As provided in Section 1.C of the attached 2010 Protocols, cost-effectiveness calculations must utilize publicly available data and data sources and must generate the results using publicly available models and methods. (D.10-12-024 p. 9)

Evolution of California Avoided Costs Building Standards MPR Demand Response Dist Generation Energy Efficiency TDV Area-specific costs 1998 Market-basedw/ adders 2004 Residual Capacity Adjustment 2006 Gas Update 2007 RPS MPR 2008 2007 MPR & $30/ton CO2 NEM Study Consensus Framework & Staff Paper 2009 MPR 2009 New Weather Data. Price shaped by renewable forecast. New T&D Costs 2010 CSI Phase II. MRTU Shape w/ Residual Capacity. T&D based on substation loads 2010 CE Protocols 2011 MPR, incl. implied CO2 Price DG Gen method, w/ updated T&D cost, orig T&D allocators 2011 Update for 2012-2014 filings, incl. temp effect for CT.

Building Standards • Time Dependent Valuation for 2005 standards (1998) • First recognition of area and time specific nature of benefits in building energy standards • Used simulated energy-only electricity market prices • Introduced the use of temperature as a proxy for T&D need • Programmable Controllable Thermostats (2006) • Introduced residual capacity adder for generation • 2013 Title-24 Standards (2010-2011) • Simulate electricity market shapes with changes due to renewable installations. Include residual capacity adder. • Introduce new weather files that are coordinated across the state • Update T&D costs using recent IOU fillings

Energy Efficiency • Methodology for EE (2004) • Electricity based on PX market shape and all-in cost of a CCGT • T&D costs estimated from utility plans, allocations same as TDV • Adders for environment, market multiplier effect • Misc Updates (2006-2010) • Gas prices, CCGT costs , and CO2 $30/ton scenario • Update for 2013 (2011) • Use generation methodology from DG proceeding • MRTU shapes • Residual capacity value with adjustment for temperature degradation • Solve for both CT and CCGT long-run costs • Synapse forecast of CO2 costs • 2017 resource balance year • Use T&D costs from updated IOU filings

DG Avoided Cost Framework D. 09-08-026 • Net Energy Metering Report (2009-2010) • Revised the EE method with the following changes and updates • Replace PX with MRTU-based Energy Prices, separate capacity value, addition of avoided renewable costs, and disaggregated presentation of ancillary costs and losses. • Update the Resource Balance Year • Update the CT Dispatch • Use actual instead of TMY weather data • Use escalating Synapse GHG Price Forecast • California Solar Initiative Cost-effectiveness Reports (2011) • Incorporate 2011 DR Protocols generation temperature degradation and refined generation allocations • Use substation loads for T&D allocations • T&D from specific utility project plans

DR & PLS • Permanent Load Shifting Cost-Effectiveness Report D. 09-08-027 (2011) • Uses CSI Avoided Cost Framework • DR Cost-Effectiveness Protocols R. 07-01-041 (2011) • Recognize temperature degradation of generation output • Allocation of generation capacity value • Updated financing assumptions and pro forma calculation to be consistent with MPR and CAISO Market Performance Report • Update forward prices for electricity and natural gas • Add Adjustment factors

Topic 1: Resource Balance Year • The Resource Balance Year determines when long-run equilibrium costs are used. • Determined as the year when capacity and energy markets reflect the full cost of new plants. • The current resource balance years are different for Energy Efficiency (2017), Demand Response (2010), and Distributed Generation (2015). • Discussion Objective: Develop a consensus on recommendations for consistency, updating, and appropriateness of the Resource Balance Year.

Example of Transition from short-run to long-run • Example shown for generation capacity with a Resource Balance year of 2015 • In the short-run, the value of capacity is based on current resource adequacy values, whose low magnitudes ($28/kW-yr in 2008) reflect the CAISO’s large current capacity surplus • In the long-run, capacity value is based on the residual capacity cost of a simple-cycle combustion turbine (cost of constructing a new unit, net of market margins, to meet reliability requirements)

Resource Balance Year Determination • Resource Balance year is when forecast supply can no longer meet peak load + reserves • Resource Balance year is affected by assumptions of inclusion of demand-side resources and new generation

Current Resource Balance Years • Demand Response: 2012 • As per Decision 10-12-024. • DG: 2015 • Based on CEC load forecast (from December 2009) and expected available capacity resources, including plant retirements and renewable additions • Energy Efficiency: 2017 • Based on utility 2011 LTPP filings, assumption of 10,000 MW of import capability, and without new EE/DR/CHP impacts.

When is it appropriate to use long-term versus short-term avoided costs? • Tom Beach (SEIA) – We’re adding resources for reasons with nothing to do with system need for capacity (e.g. balancing intermittency), resource balance year not the right metric. The RBY concept is flawed; we should be long-run avoided costs, like DR. • Bill Marcus (TURN) – with various energy & environmentally driven resources, capacity comes along too. Reality is we don’t need to encourage new capacity demand side resources. Use short-run w/ resource balance year for non-automated DR, EE & DG; use long-run for more dynamic programs like those provided by aggregators. Should differentiate between existing and new programs. • Kevin McKinley (SDG&E/SoCalGas) – emphasis should be on accuracy given anticipated conditions. We do need resource balance year to determine short term costs. • Sierra Martinez (NRDC) – using short-run costs undervalues EE so long-run costs should be used. • Monisha (DRA) – agrees with need for short and long-term costs. Believes that all DG resources be included in calculation of RBY. Resource Balance Year

Is it appropriate to have different resource balance years for different demand-side programs? • Mona Tierny-Lloyd (EnerNOC) – CAISO is seeking capacity not based on peak demand, mainly for LCR and flexibility. DR can avoid this capacity need as well, not just a peak capacity resource. Characteristics of demand side resources should drive avoided cost comparison. • Barbara Barkovitch(CLECA) – need to value different attributes more accurately, not just a single capacity category. • Bill Marcus (TURN) – question of difference in type/length of equipment/customer commitment for new programs. • Tom Beach (SEIA) – DSM resources not all dispatchable, but they do free up gas resources to operate more flexibly. LTPP modeling showed that including DG and DR resources into EE gives more flexibility into the system. Should not have different RBYs for different resources; all should use long term costs. Resource Balance Year

Should the resource balance year be updated periodically, and if so, what is the appropriate process? • Monisha (DRA) – update in alignment with LTPP. • Tom Beach (SEIA) – if RBY is retain, should take all preferred (DSM) resources out of calculation. • Bill Marcus (TURN) – committed DSM should be in, keep DR in (mostly) because it’s included in the demand forecast. Suggested looking at calculations program by program. • Kevin McKinley (SDGE/SCG)– calculate RBY using only resources funded in current cycle. Resource Balance Year

Topic 2: Long-run Resource Cost The long-run generation capacity is based on the cost of a combustion turbine (CT), while the long-run energy market price is based on the cost of a combined-cycle gas turbine (CCGT). CTs and CCGTs are the most common generation units built in California in recent years. Discussion Objective: Determine if there are compelling reasons to change the long-run cost basis of the avoided cost framework, and if so, examine the feasibility and value of doing so.

Is it still appropriate to model avoided costs on natural gas generation, given that renewable generation will comprise the bulk of new additions? • Bill Marcus (TURN) – keep using natural gas generation given that the least-cost resource generally provides capacity. • Barbara Barkovitch (CLECA) – agrees, not adding renewables for capacity. Would need to consider NQC of renewables, complicated issue. Keep using CT as long-run cost. • Tom Beach (SEIA) – agrees, like current modeling approach. Should use different mix only if comparing with 100% renewable generation (e.g., in cost-effectiveness of CSI). • Snu (E3) – for 100% renewable, what is ratepayer value if customer retains REC (and potentially sells that to utility). • Barbara (CLECA) – not easy to know what is avoided at the margin, could actually be fossil, depends on modeling assumptions. • Bill Marcus (TURN) – difference between short-term decisions and long-term predictable investments. Long-run Resource Cost

Does the addition of the avoided RPS cost properly account for the change in the generation mix? Bill Marcus (TURN) – theoretically, concept of renewable adder is sound. Long-run Resource Cost

BREAK The workshop will continue at 11:45am.

Topic 3: Allocation of Generation Capacity Cost The generation capacity costs are allocated among 250 hours in the year, in inverse proportion to the amount of generation headroom in each hour. Discussion Objective: Determine if, and how, the allocation method could be improved.

Allocation of Generation Capacity Costs • The Generation Capacity Cost is allocated to hours to reflect the likelihood that load reduction or generation addition is needed in that hour. • LOLP from simulation models is precise but complex and opaque • Allocating based on system load levels is simple and transparent • Equal weight to top 100 hours is a ratemaking method

Current Allocation Methods • Original Method: Capacity value is allocated to the top 250 load hours such that highest load hours get highest %. • Current Method: 1. Monthly shares based on top 250 hours over multiple years2. Allocate the shares based on top load hours within each 2010 month

Load Duration Curves for Top 400 Hours • Top 100 hours, instead of 250 hours has been suggested by parties.

Should the allocation method for generation capacity be changed? • Reasons to use 100 hours • Ulrich (PG&E) – What ever DR program is designed for (i.e. peaking resource), that is criteria against which cost-effectiveness should be based. Should use shorter hours based on program. • Dave Barker (SDG&E) – compared to LOLP, 100-250 hours should have such a high allocation of capacity value. Curve doesn’t go down steep enough. • Reasons to use 250 hours • George Simmons (ITRON) - going forward capacity is needed for reasons other than peak load, more diverse set of hours when capacity is needed. • Aloke (ED) – perhaps go longer for PLS. • Bill Marcus (TURN) – accounting for outages in shoulder months would suggest use of greater number of hours. • Reasons to use other allocation methods • Bill Marcus (TURN) – take a look at PG&E PCAF method; LOLP also worth looking at. Program that can be called 100 hours is less valuable than one that can be called 250, that should be reflected. • Kevin (SDGE/SCG) – should be able to use different hours for different utilities. Can utilities show results of LOLP in way that satisfies public stakeholder process. • Sadir (DRA) – still concerned about lack of transparency and not being able to share models even with NDA. • Barbara (CLECA) – advocates for using LOLP. Value is lost when only concentrating on summer months. Most alerts over last 10 years have been transmission, not generation related. • Jamie Fine (EDF) – concerned about missing high expense, low probability events that may be more common in the future; methods developed now may not be appropriate for future. • Joy (ED) – Consensus that we need a more sophisticated method that considers previous CAISO emergencies/DR events; something what would differentiate by program or utility Allocation of Generation Capacity Cost

Topic 4: Avoided Renewable Portfolio Standard Cost • The Avoided Renewable Portfolio Standard (RPS) Cost reflects: • The gap between RPS resource costs and conventional resource costs. • The percentage of utility sales that must be supplied via RPS-qualified resources. • Currently, the percentage of utility sales is a step function that increases with each interim goal. • Discussion Objective: Determine the most accurate and feasible method for modeling the RPS avoided cost.

Avoided RPS Purchases • Reductions to total retail sales reduce the required renewable energy purchases • To the extent renewable energy costs more than the long-run CCGT, there is a cost savings • E.g.: 33% RPS goal, 8 ¢/kWh “regular” avoided cost, 14 ¢/kWh renewable cost. • Renewable cost premium is 6 ¢/kWh (14-8) • Avoided cost savings is 2 ¢/kWh (6 ¢/kWh * 33%) • Renewable cost is based upon the Fairmont CREZ, the most expensive resource bundle that is included in the renewable portfolio in E3's 33% Model 33% Reference Case

RPS Treatment • California Solar Initiative Study • No avoided cost adder until 2020 • 33% of RPS cost premium in 2020 and beyond • EE 2013 update • Incorporates interim goals • 20% in 2013-2015 • 25% in 2016-2019 • 33% in 2020 and beyond • Parties have suggested a linear rather than step function on the annual goal percentages

Would changing the step function to a linear function more accurately reflect the avoided utility procurement costs? • Tom Beach (SEIA) – banking/trading would smooth things out, would expect more consistent/linear slope. • CLECA – procurement requirements might suggest average rather than marginal. Suggest look at using historical data that is available on procurement costs by zone/type. • Navigant – tie to what is coming out of RPS proceeding, which has linear. • Jamie Fine (EDF) – analytically, linear seems easier. Number is more important than linear vs stepwise. Avoided RPS Cost

Topic 5: GHG Costs and Double Counting Currently, the impact of CO2 reductions are added as an avoided cost stream separate from the avoided energy cost. Beginning in 2013, there will be a carbon price embedded in the wholesale energy prices used to determine the avoided energy cost. This carbon price will reflect the CA Air Resources Board’s program for achieving carbon reduction goals, but may no represent the actual cost of carbon. Discussion Objective: Determine a method for modeling GHG costs that avoids double-counting.

Valuation of Avoided Emissions • The value of avoided emissions is based on Synapse meta-analysis of numerous studies of potential federal climate legislation • This price forecast was developed specifically for use in utility integrated resource planning

Update Issues • Going forward, market price updates will not allow easy exclusion of CO2 market impacts from the electricity market price forecasts. • A method enhancement will be needed to continue the avoidance of double counting of CO2, and potentially NP-15 Implied Market Heat Rate NP-15 implied market heat rate shows that a cost adder for CO2 is likely embedded in futures prices

Market Estimations of CO2 Costs • The period around the Cap and Trade announcement provided data to estimate CO2 cost embedded in the market futures. • Othermarketsources?

After 2013, will there still be a need for a separate GHG avoided cost? • Dave Barker (SDG&E) – advance auction in 2012 for 2015. • Jamie Fine (EDF) – programmatic challenges with big increase in demand in 2015 and sunset in 2020. • General consensus that relationship between RPS and GHG should be accounted for consistently in GHG and RPS avoided cost calculations. “Traditional” costs against which RPS is compared should include GHG costs. Question of whether marginal avoided energy is all fossil – should have full GHG value, vs. should fact that fleet will be 33% renewable discount GHG value of avoided energy. • Barbara (CLECA): A recent journal article on topic (mentioned by Jamie Fine of EDF) should be vetted by workshop attendees. GHG Costs and Double Counting

Topic 6: Transmission & Distribution Avoided Costs Currently, the transmission & distribution (T&D) avoided costs are based on CPUC ratemaking proceedings. These costs vary by climate zone for PG&E, and are utility averages for SCE and SDG&E. Discussion Objective: Develop consensus on how to accurately calculate T&D avoided costs.

Are the current T&D avoided costs appropriate for demand-side programs? What is the appropriate level of disaggregation for T&D avoided costs, and should it differ for EE/DR/DG? • Joy (ED) – sometimes hearing from utilities that numbers are not reflective of actual marginal costs. • Bill (PG&E) – insufficient concentration of DR/DG/EE in any one area to actually avoid construction. Rate case is what utilities will spend, not what they will not spend as a result of lower loads. • Bill Marcus (TURN) – issue with utility planning that based on historical, not taking current and future EE and DR into account. • Tom (SEIA) – constant per capita energy use for decades suggests that T&D costs are actually avoided, planners only look at short term (2-3 years). • Marcel (TURN) – many different causes for changes in per capita energy use, need to look at whether projects are in fact actually avoided. Regression approach includes new business, which is not appropriate. • Mona (EnerNOC) – limited relationship between climate zones and actual need for curtailments for LAP/Sub-LAP. • Edison – during load forecast workshop on Tuesday, Edison T&D engineers said that forecast is based on known codes and standards and known programs combined with forecast needs. • Aloke (ED) – conceptually, T&D costs should be marginal costs and it should be up to the utilities to figure that out. Need consistent approach; the approach should have aggregate data, historical data, and regression analysis to figure out slope of the T&D function for whatever variable (e.g., peak demand, PV) • Suggestion that utilities take a stab at refined analysis of DSM avoidable T&D costs. T&D Avoided Costs

Should demand side programs apply higher avoided T&D cost savings to “hotspots” as in the feed-in tariff proceedings? • Marcel (TURN) – liked proposal for hotspots in DG proceeding, perhaps needs more categories. Would also need to track what DG has been built. • E3: using hot spots results in the need for a policy decision to determine if we want to target programs in particular areas. T&D Avoided Costs

How could these avoided costs be better estimated for different locations and measures? Discussion notes here T&D Avoided Costs

Topic 7: Discount Rate Currently, the discount rate applied in cost-effectiveness tests is the after-tax weighted average cost of capital (WACC). Discussion Objective: To examine the pros and cons of the various proposed discount rates.

Discount Rate “those looking for guidance on the choice of discount rate could find justification for a rate at or near zero, as high as 20% and any and all values in between.” Portney and Weyant, 1999, ‘Introduction’, Discounting and Intergenerational Equity, Resources for the Future Press, p. 4

Discount Rates • Two discount concepts • Reflect the opportunity cost of investing in lieu of other activities. • Reflect the relative weight of the economic welfare of different households or generations over time. • For EE/DG/DR we embrace the first approach

Typical discount rates • Social Rate of Time Preference • Social Opportunity Cost • Private Sector WACC

OMB Recommendation • OMB recommendation for Public Investment and Regulatory Analysis is real discount rate of 7%. (OMB Circular A-94, Section 8.b.1) • Shadow Price of Capital is analytically preferred (Section 8.b.3). The SPOC is difficult to calculate, however, as it requires determination of the social value of all consumption and private investment impacts. • Some Federal investments provide "internal" benefits which take the form of increased Federal revenues or decreased Federal costs. An example would be an investment in an energy-efficient building system that reduces Federal operating costs. Unlike the case of a Federally funded highway (which provides "external" benefits to society as a whole), it is appropriate to calculate such a project's net present value using a comparable-maturity Treasury rate as a discount rate. This does not apply, as the funding source and beneficiary are not the US Govt.

Is the after-tax WACC the appropriate discount rate? • Will (STEM) – projects with different risk profiles should have different WACC; suggests resource-specific discount rate (for EE, DG, and DR). • Bill (TURN) – sees before tax WACC as reasonable compromise. If we start to use different discount rates, need to evaluate all inputs. • Lara Ettenson (NRDC) – CPUC requiring long term investments based largely on policy, high WACC undervalues long-term investments. Suggests using different discount rates for different tests (e.g., PAC uses short-term discount rate, TRC uses long-term discount rate). • Barbara (CLECA)– need to be cognizant of cumulative rate impacts on ratepayers; different rates for different tests will not address issue. • Jamie Fine (EDF) – not appropriate to use a “reasonable” number; supports using different discount rates for different cost tests OR changing assumptions. • Charlie Buck (CCSE) – TRC should include blend of discount rates since it is a blend of perspectives. • Jeff Hirsch – combine discount rates – benefits use utility discount rate and costs use participant discount rates; weigh based on funding sources. • PGE – TRC and PAC should only include utility avoided costs; if societal avoided costs are considered, societal discount rate should be used. Cost-effectiveness tests should be reflective of where funding comes from; after tax WACC is used because avoided costs are looked at from utility perspective. • Policy reasons for not using actual consumer discount rate, overcoming barriers to EE investment and sub-optimal ratepayer investment. • SDG&E and SCE use before tax, PG&E after tax, SCE advocated higher discount rate for longer term investments. Discount Rate

Should a societal discount rate be considered for the current cost-effectiveness tests? When, if ever, is it appropriate to use a societal discount rate? NRDC – Commission is trying to achieve societal cost-effectiveness and so a societal discount rate should be used. Discount Rate

Other Issues • SCE – problem changing avoided costs mid process for program filings • Consensus on regular updates • Need to be able to fix errors • Parties would like to be involved and have sense of process from start to finish • Updates: Should input data be updated regularly, or should parties and/or the Commission examine the data before updating? • Discussion Objective: To determine the impact of regular data inputs.

Cost-effectiveness Workshop One: The E3 Avoided Cost Model and Discount Rate