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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 28 th , 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

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

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

  2. 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

  3. 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.

  4. History

  5. 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)

  6. 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 CA Demand Response Study RPS MPR 2008 2007 MPR & $30/ton CO2 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.

  7. 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

  8. 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

  9. 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

  10. 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

  11. 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.

  12. 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)

  13. 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

  14. 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.

  15. When is it appropriate to use long-term versus short-term avoided costs? Discussion notes here Resource Balance Year

  16. Is it appropriate to have different resource balance years for different demand-side programs? Discussion notes here Resource Balance Year

  17. Should the resource balance year be updated periodically, and if so, what is the appropriate process? Discussion notes here Resource Balance Year

  18. 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.

  19. Is it still appropriate to model avoided costs on natural gas generation, given that renewable generation will comprise the bulk of new additions? Discussion notes here Long-run Resource Cost

  20. Does the addition of the avoided RPS cost properly account for the change in the generation mix? Discussion notes here Long-run Resource Cost

  21. BREAK The workshop will continue at 11:45am.

  22. 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.

  23. 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

  24. 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

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

  26. Should the allocation method for generation capacity be changed? • Reasons to use 100 hours Discussion notes here • Reasons to use 250 hours Discussion notes here • Reasons to use other allocation methods Discussion notes here Allocation of Generation Capacity Cost

  27. 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.

  28. 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

  29. 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

  30. Would changing the step function to a linear function more accurately reflect the avoided utility procurement costs? Discussion notes here Avoided RPS Cost

  31. 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.

  32. 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

  33. 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

  34. 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?

  35. After 2013, will there still be a need for a separate GHG avoided cost? Discussion notes here GHG Costs and Double Counting

  36. 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.

  37. 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? Discussion notes here T&D Avoided Costs

  38. Should demand side programs apply higher avoided T&D cost savings to “hotspots” as in the feed-in tariff proceedings? Discussion notes here T&D Avoided Costs

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

  40. 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.

  41. 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

  42. 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

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

  44. 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.

  45. Is the after-tax WACC the appropriate discount rate? Discussion notes here Discount Rate

  46. 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? Discussion notes here Discount Rate

  47. Other Issues Discussion notes here • 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.

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