Avoided Cost and E3 Calculator Update WorkshopMarch 14-15, 2006

Agenda – Day 1 Introduction 10:00 – 10:25 Discussion of major issues

Peak definitions 10:25 – 11:40 Load shape development 11:40 – 12:00 Lunch break

Critical and super peak periods 1:00 – 2:30 Break

Capacity adder and peak reshaping 2:45 – 4:30 Natural gas price update 4:30- 5:00

Agenda – Day 2

Housekeeping from Day 1 9:30 – 9:45 Miscellaneous issues 9:45 - 11:00

Application of E3 tool Recommendation for future tools Overhead double counting EE forecast in resource plans (net vs. gross) Applicability to demand response Other

Recap of consensus / non-consensus 11:00 – 12:00 Lunch Action Plan / Next Steps 1:00 – 2:30 Break Load shape development 2:45 – 5:00

Introduction

Scope and purpose for the 2006 update (ALJ Gottstein) See handout entitled Purpose and Scope of 2006 Update (per

December 27, 2005 ALJ ruling) Workshop focus and approach (E3)

Near term changes for rebalancing, tracking achievements and performance basis setting.

Recommendations for longer term changes for the 2009-2011 program cycle.

Broader consistency across proceedings/ resource types? Help to identify phase III issues. Working workshop second half of day 2 (load shape development) Approach to discussion

Brief summary of E3 findings and recommendations Summary of party positions and discussion Identify areas of consensus / non consensus Alternatives for ALJ consideration Consider both near term and long term

Peak Definitions

Peak definitions for EE are needed for MW goals, tracking the achievements of goals, evaluation of portfolios to reach goals, and determining performance basis.

Consistency within EE applications

Consistency with peak definitions for other resources or in other proceedings (DR, DG, RA).

Consider both near and longer term definitions as well as the data requirements.

Peak Metrics – 1DEER kW

Available for measures in the DEER database. For temperature sensitive measures, peak demand is defined as the average grid level impact for the measure from 2pm to 5pm on peak days.

Pro: Is currently used by utilities for measures where DEER kW is available, though there are some differences among utilities. Both SCE and SDG&E report DEER kW for all programs.PG&E states that only 60% of its program impacts are based on measures in the DEER database (the rest calculated from larger, complex projects)

Cons: Not available for all measures. DEER kW is derived using building simulation tools based on prototypical buildings and as such has some limitation in terms of accuracy.

Summer on peak kW

Based on old utility studies, or can be calculated from hourly end use or impact shapes

Pro: Readily available from old utility studies, which often used load research data and conforms with utility time of use period definitions.

Con: On peak periods vary for each utility, so the reported on peak demand reduction for the same measure could differ across utility service territory (even if all other things were equal)On peak demand estimates from the TOU studies can differ from the DEER kW estimates. This fact prompted SDG&E to report DEER kW (also referred to as Deemed kW) for all of their programs.

Peak Metrics – 2

•Load Factor based kW (CEC kW)

Annual energy reductions multiplied by a fixed conversion factor.

Pro: Easy to estimate. Requires little additional M&V effort.

Con: Does not recognize the fact that peak load factors vary by measure, and could therefore allow an overemphasis on poor peak-load-factor measures such as residential CFLs.

•Resource Adequacy (RA) consistent peak kW

Early discussions centered around requirements for Demand Response which currently counts peak load as the average reduction over 48 hours of operation, 4 summer months, 4 days per month, 3 hours per operation.According to the newly adopted RA counting rules, the RA value of energy efficiency is 115% of its monthly coincident peak impact.

Pro: Might reflect the actual avoided costs of capacity if resource adequacy (RA) counting rules were to apply to energy efficiency measures.

Con: RA rules are interim. Requires hourly data. Unclear which hours should be designated as the peak period dispatch hours, or the single hour monthly coincident peak. PG&E also cautions that peak impacts calculated from an RA perspective could be significantly lower than peak impacts estimated from past and current methods.

Peak Metrics – 3

Coincident peak kW

Requires hourly load shapes and specification of peak hours. For PG&E’s end use shapes, the peak hours were identified as the five top system load hours in each month. Monthly coincident peak kW = average load during the five peak hours. Coincident peak is the average July through September monthly peak kW.

Pro: Provides the most precise metric of peak or critical peak load reduction.

Con: Requires hourly load data which is not currently available. May be a challenge for M&V ex-post estimations.

E3 Recommendation for EE Proceedings E3 recommends two options for determining peak

demand reduction in the near term:1. Report DEER kW (deemed kW) where available, and utility best

estimates in other cases. 2. Use load factors by end use categories.

Longer term: (not addressed in the Draft Report) Move toward a concident peak measure that uses a weighted

average of many hours. The number of hours will depend upon the extent to which the

impact data and cost data are aligned. The better the alignment, the fewer hours needed.

Summary of Party Positions:Peak Definitions and Load Shapes

Peak Definitions and Load ShapesSCE Continue to use the current estimates for the 2006-2008 program cycle. (pp. 1-2)SCE RA Counting rules should not be used (p. 2)SCE Support development of hourly calibrated measure impact data for the next program

cycle (p. 2)SCE Prefers to use DEER database estimates rather than load factors by end use. (p. 3)TURN Opposes use of end-use load factors. (p. 3)TURN Recommends the Draft Report reflect additional criticisms of the RA method.TURN TURN suggests focusing the workshop on load shape and peak savings estimates

improvements.(p. 2)DRA Opposes the use of DEER kW values to report peak kW. Supports the use of end use

load factors until reliable load shape data becomes available for all utilities (p. 2)DRA Utility administrators should not be at risk for using the load factors (p. 2)DRA The workshop should discuss details of implementing and weighting load factors,

and the Commission may wish to revise the demand reduction goals for 06-08. (pp. 2-3)

PG&E Peak metrics should be consistent with methods used to determine the extent to which different resources contribute to the acheivement of RA requirements. (p. 2)

SDG&E Concurs with E3 recommendations, as issues not addressed in comments.

Peak Definition across applications Discuss as a group

Peak MW Application Granularity needed Potential Peak Definitions

Resource Adequacy Single coincident hour each month

Long term planning Single annual peak?

Load shape development

Requirements for Peak kW metricEE valuationRepresentation of EE in other applications

Calibration issues Working session to develop action plan,

second half of day 2.

Load Shapes

E3 recommends a research effort to develop calibrated load shapes for use in the 2009-2011 program cycle. Shapes should be impact shapes (not building shapes) that are

hourly in resolution Shapes should reflect diversified impacts at the grid level and

reflect run time averages Potential data sources

DEER CEUS? Building simulations, such as those used for Title-24.

Issues Calibration Alignment of loads with generation costs

Sample Impact Shape Results Res A/C is the PG&E residential end use shape DEER AC eff is the DEER impact shape Both shapes normalized so that total annual

reductions sum to 1.0

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Sample Commercial Impact Shape

Office Cool is the PG&E end use shape (CZ 13) DEER Chiller Eff is the corresponding impact shape Note that the DEER reduction is 0 in the second chart

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Comparison of TOU Shares

Commercial shares are comparable Normalized Residential DEER shape has

higher on-peak %, partly because of negative amounts in other periods.PG&E TOU Avg Cost Usage Shares by TOU

TOU Hours ($/MWh)Office Cool

DEER Chiller Eff Res A/C:13 DEER AC Eff

1 774 128.69$ 31% 32% 29% 44%2 903 93.94$ 22% 24% 24% 23%3 2739 67.39$ 35% 22% 46% 40%5 1612 86.56$ 7% 18% 1% -1%6 2732 68.73$ 5% 5% 1% -7%

Summary of Party Positions:Load Shapes

Load ShapesSCE Parties to the EE proceeding should work towards developing hourly, calibrated

measure impact data (p. 2)TURN TURN suggests focusing the workshop on load shape and peak savings estimates

improvements.(p. 2)SDG&E Concurs with E3 recommendations, as issues not addressed in comments.PG&E Silent on the issue in comments, but was generally in agreement with SCE's positionDRA Cost of obtaining hourly load data appears justified only for weather-sensitive measures.

(p. 4)

Need for critical or super peak periods Definitional needs

kW and TOU shares for use in other proceedings?

Recommended definitions Valuation issues

Adders to TOU average avoided costs? Short term options and long term ideal

E3 Recommendation

Critical peak metric not necessary for non-dispatchable (EE) programs.

Super peak periods could reduce the undervaluation of measures like Res AC that occur with the use of TOU average costs. BUT this would require that utilities could develop super peak impact profiles. E3 recommends that super peak periods not be used in the near term because Shape development would be difficult The examples in the Draft Report are based on PG&E’s building

end use shapes, not impact shapes Value could be added directly to programs such as Res

AC without the construction of super peak periods.

Super Peak Results:PG&E Generation Avoided Costs & Building End Use Shapes CZ13

CZ3

Peak TOU Period Definition

# of Peak Hours

Avg Cost ($/MWh)

Deviation (%)

Avg Cost ($/MWh)

Deviation (%)

Avg Cost ($/MWh)

Deviation (%)

Avg Cost ($/MWh)

Deviation (%)

Hourly Loads and Costs 97.2$ 86.6$ 104.6$ 80.9$ May - Oct. Noon-6pm 774 93.7$ -3.6% 86.1$ -0.7% 91.6$ -12.4% 80.6$ -0.4%

June - Sept. Noon-6pm 504 93.7$ -3.6% 85.9$ -0.9% 93.9$ -10.2% 80.6$ -0.4%May - Oct. 2 - 5pm 387 93.1$ -4.2% 86.0$ -0.8% 91.4$ -12.5% 80.5$ -0.5%July - Sept. 2 - 5pm 192 96.8$ -0.4% 85.9$ -0.9% 98.6$ -5.7% 80.9$ 0.0%

Office Cooling Office Lighting Res A/C Res Refrigeration

Peak TOU Period Definition

# of Peak Hours

Avg Cost ($/MWh)

Deviation (%)

Avg Cost ($/MWh)

Deviation (%)

Avg Cost ($/MWh)

Deviation (%)

Avg Cost ($/MWh)

Deviation (%)

Hourly Loads and Costs 95.5$ 88.2$ 103.4$ 80.9$ May - Oct. Noon-6pm 774 94.4$ -1.1% 88.1$ -0.1% 94.7$ -8.4% 80.6$ -0.4%

June - Sept. Noon-6pm 504 93.2$ -2.5% 87.9$ -0.3% 95.7$ -7.4% 80.6$ -0.4%May - Oct. 2 - 5pm 387 93.7$ -1.9% 87.9$ -0.3% 94.4$ -8.8% 80.5$ -0.5%July - Sept. 2 - 5pm 192 94.6$ -0.9% 87.8$ -0.4% 98.3$ -5.0% 80.9$ 0.0%

Office Cooling Office Lighting Res A/C Res Refrigeration

Summary of Party Positions:Critical Peak Periods

Critical Peak PeriodsSCE The development of estimates of demand reductions during these "critical peak" periods

and the assignment of avoided costs specific to these periods should be discussed in the development of cost-effectiveness methodologies of demand response programs. (p. 3)

TURN Suggests value adders to reflect super peak periods (p. 4)DRA Recommends against construction of a critical peak metric. Only needed IF the

Commission intends to develop a separate critical peak kW reduction goal. (p. 3)PG&E PG&E recommends critical peak KW definitions and critical peak TOU shares (because

of DR and DG?) (p2)SDG&E Concurs with E3 recommendations, as issue not addressed in comments.

Capacity adder and peak reshaping

Capacity AdderNeed to increase peak avoided costs?Methods to calculate a capacity adder

Peak ReshapingTOD profilesMethods to allocate capacity adder to hours

Phase 3 issues?

Draft Report

E3 does not believe the LRMC methodology should be modified to require entrant of a CT If the price shapes must accommodate a CT, the capacity adder

would be $40-50/kW-yr. This may represent a fundamental change in methodology

The LRMC is a full hedged physical product, so no hedge value adder is needed

TOD factors should not replace the PX shape because They lack granularity Represent a fundamental change to the avoided cost

methodology --- move to phase 3.

Draft Report Residual Capacity Adder

Using flat annual gas price

Using daily spot gas prices

All values in $/kW-yr 2008 2009 2010 2011 2012 2013 2014 2015CT Proxy Levelized Cost 79.2$ 80.8$ 82.4$ 84.0$ 85.7$ 87.4$ 89.2$ 91.0$ Contribution to Fixed (NP15) 42.3$ 41.7$ 42.3$ 43.3$ 44.8$ 46.2$ 47.2$ 49.2$ Contribution to Fixed (SP15) 47.2$ 46.6$ 47.4$ 48.6$ 50.2$ 51.9$ 53.1$ 55.3$ Residual Capacity Value (NP15) 36.9$ 39.1$ 40.1$ 40.7$ 41.0$ 41.2$ 41.9$ 41.8$ Residual Capacity Value (SP15) 32.0$ 34.2$ 35.0$ 35.4$ 35.5$ 35.6$ 36.1$ 35.7$

All values in $/kW-yr 2008 2009 2010 2011 2012 2013 2014 2015CT Proxy Levelized Cost 79.2$ 80.8$ 82.4$ 84.0$ 85.7$ 87.4$ 89.2$ 91.0$ Contribution to Fixed (NP15) 33.3$ 32.8$ 33.3$ 34.2$ 35.3$ 36.5$ 37.3$ 38.9$ Contribution to Fixed (SP15) 37.8$ 37.5$ 38.3$ 39.4$ 40.8$ 42.2$ 43.4$ 45.1$ Residual Capacity Value (NP15) 45.9$ 47.9$ 49.1$ 49.9$ 50.4$ 51.0$ 51.9$ 52.1$ Residual Capacity Value (SP15) 41.4$ 43.3$ 44.1$ 44.6$ 44.9$ 45.2$ 45.8$ 45.8$

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Adjusted Gen + Residual Capacity PG&E 2006 Gen & Env

Impact of $50/kW-yr capacity adder on EE valuation Average avoided costs and hourly shapes

Average avoided costs using TOU shapes

Climate Zone 13 Office Cool Office Light Res A/C:13 Res RefrigCurrent PG&E Gen & Env Avoided Cost ($/MWh) 97.24$ 86.64$ 104.55$ 80.92$

Gen + Residual Capacity Value ($/MWh) 113.62$ 89.35$ 129.78$ 82.36$ % Change 17% 3% 24% 2%

Climate Zone 3 Office Cool Office Light Res A/C:13 Res RefrigCurrent PG&E Gen & Env Avoided Cost ($/MWh) 95.51$ 88.15$ 103.42$ 80.92$

Gen + Residual Capacity Value ($/MWh) 106.25$ 91.88$ 118.71$ 82.36$ % Change 11% 4% 15% 2%

3 = Commercial HVAC

1 = Commercial Indoor Lighting

26 = Res. Central Air Conditioning

24 = Res. Refrigeration

Current PG&E Gen & Env Avoided Cost ($/MWh) 84.24$ 86.17$ 99.23$ 82.29$ Gen + Residual Capacity Value ($/MWh) 86.50$ 89.81$ 114.94$ 83.22$

% Change 3% 4% 16% 1%

Summary of Party Positions:Capacity Adder & Peak ReshapingCapacity Adder and Peak ReshapingSDG&E Concurs that PX shape should NOT be modified for the full recovery of a CT (p. 2)

Cites the RPS proceeding for support.SDG&E Opposes replacing PX with TOD shapes because of lack of granularity and mismatch

between TOD and EE TOU periods. (pp. 3-4)TURN E3 appears to misunderstand the basis for TURN's CT adder recommendation. (p. 5)TURN TURN characterizes the difference between E3's $50/kW-yr adder and TURN's $20-25

adder (p. 6)TURN

The CT adder is needed to make the playing field between EE and DR more level. (p. 6)DRA PX shape adjustment is beyond the scope of the update, and the PX shapes exhibits

adequate volatility (p. 5)SCE Supports the current costs with a natural gas update, and opposes a price shape

update. (pp. 4-5)

Natural Gas Update

Updated natural gas forecast with EIA Outlook 2006 forecast and the CEC’s IEPR forecast

NYMEX values were not updated in the report (but should be updated with the most recent data available)

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Gas Price Change

New forecasts are about 6-9% higher than the existing prices.

Year EIA

1/2006 CEC IEPR

SoCal Gas

4/2/04Updated Average

4/7/05 Average % Change

2006 7.73 4.25 5.06 5.68 4.82 18%2007 7.04 4.32 5.16 5.51 4.80 15%2008 6.77 4.17 5.12 5.35 4.72 13%2009 6.39 5.71 5.04 5.71 4.75 20%2010 6.14 4.33 5.02 5.16 4.80 8%2011 5.98 5.67 5.00 5.55 4.89 13%2012 6.05 5.25 4.98 5.43 5.03 8%2013 6.31 6.18 4.96 5.82 5.18 12%2014 6.34 5.83 5.10 5.76 5.43 6%2015 6.25 6.70 5.25 6.07 5.66 7%2016 6.32 6.80 5.39 6.17 5.81 6%2017 6.59 6.91 5.55 6.35 5.97 6%2018 7.04 7.48 5.72 6.75 6.25 8%2019 7.45 8.08 5.89 7.14 6.55 9%2020 7.73 8.19 5.96 7.30 6.81 7%2021 8.16 8.31 6.15 7.54 7.10 6%2022 8.52 8.70 6.34 7.85 7.36 7%2023 8.87 9.10 6.54 8.17 7.60 7%2024 9.30 9.38 6.75 8.48 7.89 7%2025 9.77 9.67 6.96 8.80 8.19 7%

Generation Avoided Cost Change

Updated gas price increases electric generation avoided costs by 4-5%

The electric avoided cost increase is dampened by O&M and capital costs that do not change.

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NYMEXGas

Long-Run Gas Forecast

Transition

SP-15

Latest NYMEX ForecastsForecast Comparison:

Gas Price to Electric Generators

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tu PG&E - Updated NYMEXSoCal Gas - Updated NYMEXSDG&E - Updated NYMEXPG&E - Draft ReportSoCal Gas - Draft ReportSDG&E - Draft Report

Note: 60 day average prices for all contract on or after April 2006 have been calculated using 60 calendar days of data up to 3/10/2006, as available.

Summary of Party Positions:Natural Gas Update

Natural Gas UpdateSCE Recommends updating the natural gas prices for use in both ex-ante and ex-post

measurement (pp. 5-6)SDG&E Since gas price change has a small impact, do not update if the PX price shape profile

is not changed (p. 5)DRA E3 should explain why an 8-10% natural gas price change results in only a 4-5%

increase in electricity avoided costs. (p. 5)DRA 4-5% change may be significant (p. 5)DRA E3 should provide the NYMEX gas futures (p. 5)

Day 2

Other Issues Application of E3 tool Recommendation for future tools Overhead double counting EE forecast in resource plans (net vs. gross) Applicability to demand response Other

Action Plan / Next Steps Load Shape Development

Draft Report

No need to depart from E3 calculator in near term

E3 requires no modifications to conform to SPM Overhead cost double counting is a caused by

reporting rules. Calculator improvements such as links to DEER

and load shapes should be held until the next program cycle when new load shape data is available.

Summary of Party Positions:Tool-related CommentsApplication of E3 ToolSCE E3 Calculator should not be used for reporting (p. 6)

Future ToolSCE Consider a tool that is more integrated with hourly data and the DEER database for the

next program cycle (p. 7)

Calculator AnomoliesSCE Recommend that subcontractor overheads remain in the direct installation category (pp.

7-8)SDG&E Recommends that overhead costs for some reporting categories, but not all, be

reported under Administrative costs (p. 5)PG&E The overhead double counting problem can be solved if overheads associated with

Admin, Mktg and Direct Implementation activities are properly attributed to each category and entered only once into the E3 Calculator.

DRA Consider revision of the EE policy rules to institute a cap on participant incentive amount to avoid TRC distortion. (p. 7)

Summary of Party Positions:Other Issues

EE Forecast (Net versus Gross)SDG&E Includes natural EE adoptions in its base load forecast. (p. 2)

Demand ResponseSCE The Commission should consider this separation of demand and energy in avoided

costs when assessing the development of appropriate avoided costs for use in evaluating Demand Response programs. (p. 5)

SDG&EConcurs that the methodology should not be extended to Demand Response (p. 4)

Other IssuesTURN

E3 ignored or overlooked majority stakeholder positions on several issues including critical or super peak estimation and avoided cost methodology changes. (p. 1)

TURN Draft report fails to provide strategic thinking on how to prioritize, investigate and advance the 2006 update fore portfoilio rebalancing and performance basis setting. (p. 2)