3. The E3 Methodology and Forecast of Avoided Costs

In D.03-04-055, the Commission directed E3, in the context of energy efficiency, to develop a methodology and long-term forecast of electric and gas avoided costs for the use (1) updating the current cost-effectiveness inputs used in evaluating energy efficiency programs to more accurately reflect current conditions, and (2) provide the Commission with a method and model for updating cost-effectiveness inputs on an ongoing basis:

"The Commission will contract with a consultant to update the avoided costs and `externality adders' presently used in assessing the benefits of energy efficiency programs to reflect the current societal costs of energy. This study will consider [the] impact of including additional externality adders in program [cost-] effectiveness calculations. The Commission allocates a maximum of $600,000 of PGC funds to this project."⁸

The E3 report establishes a forecast for the years 2004 - 2023 of avoided electric generation and gas procurement costs and certain externality adders for use in quantifying the benefits of demand-reduction programs. E3's presentation of avoided costs is designed to update the current avoided costs described in the Policy Manual for use within the existing cost-effectiveness evaluation framework as defined by the Standard Practice Manual (SPM).⁹ The E3 report produces avoided costs that reflect certain changes in the methodology for determining avoided cost values. These methodological changes include (1) incorporating the market price effects, (2) including the value of reliability through ancillary services, and (3) the disaggregation of the avoided costs to time (hour, month, or time-of-use (TOU) period) and to California climate zones.

The E3 report computes total avoided costs from a societal perspective in order to capture the overall benefits to all energy consumers associated with reductions in energy demand, including both direct savings and externality values of unpriced emission (e.g., CO₂). The resulting avoided costs are therefore appropriate for applying the "Total Resource Cost (TRC) test - Societal Version" ¹⁰ or a variation of the TRC that includes non-price adders, which is currently the approach to cost-effectiveness evaluation for California efficiency programs.¹¹ This test, as defined in the SPM, is intended to measure the overall cost-effectiveness of energy efficiency programs from a societal perspective, taking into account benefits and costs from a wider perspective as opposed to one individual or stakeholder.

The E3 report documents a straightforward costing methodology that is implemented using a spreadsheet model and publicly available data, resulting in avoided cost estimates that are transparent and can be easily updated to reflect changes in major cost drivers, including the price of natural gas, the costs of new generation, and the expected load-resource balance year in California.

The E3 report and methodology incorporates a number of forecasting methods and results used by the California Energy Commission (CEC). While alternative data sources are available, the CEC products provide unbiased estimates of future energy costs.

One of the key differences between the avoided cost forecasts resulting from E3's methodology and previous values in California is segmentation of the avoided costs by hour of a typical year and by planning areas and climate zones within the State. The E3 report produces forecasts of avoided costs of electric generation, transmission, and distribution that vary by hour, and avoided costs of natural gas procurement, transportation, and delivery that vary by month.

In 2003, the CEC adopted a "Time Dependent Valuation" (TDV) methodology into the 2005 Title 24,¹² Building Standards.¹³ The TDV concept is that energy efficiency measure savings should be valued differently at different times and locations to better reflect the true avoidable costs to users, the utility system, and society. E3 utilized a large portion of the TDV methodology and data to develop the area- and time-specific (ATS) estimates of transmission and distribution (T&D) costs.¹⁴ The E3 Report presents electric T&D costs that vary by utility service territory, planning division and by the 16 CEC Title-24 climate zones used in the CEC's TDV study, while the costs of electricity generation and of natural gas procurement, transportation, and delivery vary by utility service territory. E3 asserts that the resulting methodology captures differences in avoided costs due to weather, local capacity-demand conditions, and investment plans at times of peak demand.

The externality adders utilized in quantifying program benefits in the E3 report are the following: (1) an environmental externality adder; (2) a transmission and distribution (T&D) adder (also a part of recent cost-effectiveness calculations, which captures incremental demand-related capital expenditures, line losses and maintenance costs associated with increased energy use); (3) a system reliability adder, which includes the cost of maintaining a reserve margin; and (4) a price elasticity of demand adder, which recognizes that reduced demand results in a decrease in the market-clearing price for electricity and therefore an increase in consumer surplus.

The price elasticity of demand estimate varies by time-of-use (TOU) period and by month. The cost of maintaining reliability is calculated as annual percentages applied to the hourly electricity cost values. The estimated costs of environmental externalities, maintaining reliability and the benefit multipliers resulting from price elasticity of demand are uniform across the state.

The costs of environmental externalities are computed by multiplying the emissions rate of the assumed marginal plant in each hour by a forecasted cost of each pollutant (CO₂, NOx, and PM-10). The forecasted cost of emissions is based on the expected cost of controls. The expected emissions rates are based on new gas technologies. No adders are included when market prices for electricity are used, only when the cost of a combined cycle generation turbine (CCGT) power plant is used as the long term avoided resource. Since the CCGT cost does not include the capitalized price of required emission offsets, it is appropriate to include an adder and there is no double counting.

The E3 avoided cost methodology and resulting costs presented in the report are most appropriate for evaluating resources that: (1) reduce load or produce energy for hundreds of hours per year in a predictable pattern, because reductions over hundreds of hours reduce the importance of knowing the exact shape of the electric generation market hourly shape during the peak hours; (2) are relatively small (such that they can be installed behind the customer meter), because the smaller the resource relative to the local T&D system, the less the utility needs to plan for the contingency case of the resource failing to provide reductions; and (3) are expected to be installed in large numbers, because the more resources that are installed, the more one can rely upon the expected level of reductions.

To account for the inherent uncertainty associated with forecasting avoidable electricity and gas costs over a long time horizon, the E3 methodology offers two options. First, even though the avoided cost estimates are used for programs with relatively long lives, E3's spreadsheet-based model allows input assumptions to be changed and updated by Commission staff as conditions warrant, perhaps as often as once per year, to reflect changes in important cost and policy drivers. Second, E3 developed a separate set of avoided costs for a stress case scenario characterized by high gas prices and poor hydro conditions. These avoided costs aim to capture the additional value that dispatchable resources can provide under stress case conditions.

The E3 methodology would replace the Commission's current avoided cost methodology (used for valuing certain energy efficiency programs) that has been in place for a number of years, and is set forth in the Energy Efficiency Policy Manual (Policy Manual).¹⁵ Under the current avoided cost methodology, "six sets of avoided cost streams were calculated on a statewide basis to apply to all program proposals":¹⁶

Electric ($/MWh, 20-year forecast, e.g., 2002-2021)

· Avoided Generation Costs ($/MWh). One annual value, e.g., $53.41/MWh.

· Avoided Transmission and Distribution Costs. One annual value, e.g., $5.74/MWh.

· Environmental externalities. One annual value, e.g., $7.04/MWh.

Gas ($/therm, 20-year forecast, e.g., 2002-2021)

· Commodity Procurement Costs. One annual value, e.g., $0.34/therm.

· Transmission and Distribution Costs. One annual value, e.g., $0.03/therm.

· Environmental Externalities. One annual value, e.g., $0.06/therm.

These statewide avoided cost figures are currently used by the utilities as the basis for cost-effectiveness evaluations of utility-specific energy efficiency programs.

Table 2 of the E3 report, shown below, compares the E3 avoided cost methodology with the Commission's current avoided cost methodology:

Table 1: Time and Area Dimensions of Avoided Costs and Externality Adders¹⁷

	E3 Avoided Cost Methodology		Current Commission Avoided Cost Methodology
Avoided Cost	Time Dimension	Area Dimension	Time Dimension	Area Dimension
Avoided Electricity Generation	Hourly	Utility specific	Annual Average Values18	Statewide
Avoided Electric Transmission and Distribution	Hourly	Utility, planning area and climate zone specific
Avoided Natural Gas Procurement	Monthly	Utility specific
Avoided Natural Gas Transportation and Delivery	Monthly	Utility specific
Environmental Externality Adders for Electric & Gas	Annual value, applied by hour according to implied heat rate	System-wide (uniform across state)
Reliability Adder	Annual value	System-wide (uniform across state)	None	None
Price Elasticity of Demand Adder	TOU period (on-vs. off-peak) by month	System-wide (uniform across state)	None	None

3.1. Electricity Avoided Cost Formulation

The E3 avoided cost methodology calculates and forecasts the total electric avoided cost using the same three basic components that are included in the current avoided costs described in the Policy Manual.¹⁹ These are the (1) avoided generation costs, (2) avoided transmission and distribution costs, and (3) environmental externalities. The costing methodology and data used in the E3 report were intended to reflect the most recent publicly available estimates of market-based avoided costs by hour and location for both natural gas and electricity. The E3 report calculates updated avoided cost values to reflect current conditions and provides the Commission with a methodology and associated spreadsheet models²⁰ for updating the cost-effectiveness inputs on an ongoing basis. The total avoided cost is computed as the sum of three main components for each utility, climate zone, voltage level, hour, and year.

3.2. Generation Avoided Cost

E3 calculates the avoided generation cost as the product of the hourly market price for firm energy in each year, one plus ancillary services percentage, one plus energy losses percentage, and the market multiplier. The market price is calculated as the product of an hourly market price shape and an average market price. The market multiplier is calculated as the residual net short position (RNS) (unhedged position) and the market elasticity estimate of price response for changes in demand level. Finally, the average market price forecast is developed over three distinct periods: (1) a period of forward market liquidity, (2) a transition period to resource balance, and (3) a post-resource balance year long run marginal cost (LRMC) forecast.

The E3 report uses two different approaches to forecasting future avoided generation costs. For 2004 and 2005, E3 uses on-peak electric futures prices (SP-15) published in Megawatt Daily as of October 15, 2003. E3 then escalates these prices to 2006 and 2007 using the observed 2004 -2007 escalation rates in NYMEX gas futures prices on that same date. The E3 report uses the cost of a new combined-cycle gas turbine (CCGT) power plant as a proxy for the future avoided cost of electricity production, post-2008, when the utilities are assumed to have achieved a state of resource balance. The E3 report uses the CEC generation cost report as the basis for its cost and performance data for the CCGT proxy.

3.3. Transmission and Distribution (T&D)
Avoided Cost

E3's estimate of electric T&D avoided cost is broken apart by utility, climate zone, division, voltage level, hour, and year. E3 calculated the avoided cost as the product of an estimate of T&D capacity by utility division and year, hourly allocation factors for each climate zone, and one plus the peak losses on the system. The T&D capacity value is an estimate of the forward looking avoidable delivery costs. Each utility estimated these costs using either the present worth (PW) method, or the discounted total investment method (DTIM). The T&D allocation factors are percentages of the total T&D capacity cost for each hour of the year. These percentages, or weighted allocation factors are based on typical meteorological year (TMY) weather data for each climate zone. Peak losses are an estimate of the incremental losses during the peak hour of the year between the end-use customer and the distribution system and transmission system. The T&D capacity costs are allocated by typical weather patterns for the State's climate zones, with the highest costs allocated to the hottest temperature hours, as done in the CEC TDV evaluation. Non-peak hours have zero avoided T&D capacity costs, reflecting that T&D capacity investments are made to serve peak hours. The losses vary by voltage level.

3.4. Environmental Externality Avoided Cost

E3 calculated the avoided environmental cost, or emissions costs as the sum of NOx, PM10, and carbon emissions (CO₂) costs increased by marginal energy losses for each TOU period. E3 estimated the emissions avoided cost streams by multiplying the costs per pollutant (on a yearly basis) by the emission rate (per hour of the year). The emissions costs vary by voltage level, hour, and year.

The NOx costs ($/MWh) are based on California offset prices generators must pay for NOx emissions, and the estimated emission rate of NOx at the implied heat rate of the market price. The NOx cost per MWh of energy saved at the customer is increased by the incremental energy losses in each TOU period between the end use and the bulk system. In Period 1, when the forward market prices of electricity are based on NYMEX forward market prices, we assume that these prices already include the cost of NOx emissions so this value is equal to zero in Period 1.

The PM10 costs ($/MWh) are computed similarly to the NOx costs, with the emission cost based on the California PM10 market prices and the estimated rates of emissions by implied heat rate. The PM10 costs are also assumed to be included in the NYMEX forward market prices.

The CO₂ costs ($/MWh) are an estimate of avoided costs for reduction in CO₂ per MWh saved at the customer site. There is not currently a requirement to purchase CO₂ offsets in California so the avoided cost of the CO₂ emissions is based on prices in other markets.

3.5. Gas Avoided Cost Formulation

The total gas avoided costs are the sum of the forecasted commodity price for natural gas, the avoided transmission and distribution costs, and the emissions costs. The total avoided gas costs are calculated for each utility, service class, combustion type (emission control technology), month, and year.

The avoided commodity is calculated as the product of the forecasted market price and one plus the avoided compression gas and reduced loss and unaccounted for gas percentages. Similar to the avoided electricity calculation, the gas commodity is forecasted for three periods. Period 1 is the period when forward market prices for gas are available from NYMEX, Period 2 is a transition, and Period 3 is based on a long-run forecast of future prices. In addition to the gas avoided cost, the gas commodity costs are used in conjunction with the UDC's gas transportation tariff for generation to estimate the long-run avoided electricity generation costs.

The avoided gas T&D costs represent an estimate of marginal transportation cost for delivering gas to end-users, calculated as the product of the T&D marginal cost for each utility, service class, and year by the monthly T&D allocation.

The avoided emissions are computed as the sum of the reduced NOx and CO₂ costs based on the same offset market prices used in the calculation of the avoided electricity prices. Since PM10 emissions are negligible for natural gas end-use combustion, they do not represent a significant pollutant and are therefore not included in this estimate of avoided costs for gas.

⁸ See D.03-04-055, p. 21.

⁹ California Public Utilities Commission, California Standard Practice Manual: Economic Analysis of Demand Side Programs and Projects, October 2001

¹⁰ The CPUC's "California Standard Practice Manual: Economic Analysis of Demand-Side Programs and Projects" designates five types of cost-effectiveness tests for programs, each of which captures the costs and benefits of a program from a different perspective. The Total Resource Cost Test: Societal Version (TRCSV), in attempting to measure the costs and benefits from the perspective of society as a whole, allows for the inclusion of externalities.

¹¹ California Public Utilities Commission, Energy Efficiency Policy Manual: Version 2, August 2003, Page 15, San Francisco, California.

¹² Title 24 refers to the Energy Efficiency Standards for Residential and Non-Residential Buildings in California, established in 1978. The TDV values are applied using the Alternative Calculation Methodology (ACM), PG&E was the lead contractor to the CEC on the TDV evaluation (Pat Eilert and Gary Fernstrom contract managers). Available on internet: http://www.energy.ca.gov/2005_standards/

¹³ Heschong Mahone Group & E3 2002.

¹⁴ E3 was the contractor responsible for estimating the avoided costs in the CEC's TDV project.

¹⁵ Energy Efficiency Policy Manual, Version 1, October 2001, D.01-11-066, Attachment 1, adopted in Ordering Paragraph 1. The Commission also employs separate avoided cost methodologies which are used to price power from Qualifying Facilities (QFs). QF avoided cost methodologies are not part of the Energy Efficiency Policy Manual.

¹⁶ Energy Efficiency Policy Manual, p. 20.

¹⁷ Table 2, E3 Report, p. 4.

¹⁸ In some cases, some utilities have broken down these annual average avoided cost values into "costing periods," which are analogous to time of use (TOU) periods.

¹⁹ Ibid., p. 21.

²⁰ E3 prepared two spreadsheet models, one to calculate electric avoided costs and another to calculate gas avoided costs. These spreadsheet models are available for download on the E3 website, http://www.ethree.com/cpuc_avoidedcosts.html.