1

Issues summary

Pre workshop comments

2

Scope of the 2006 Update

1. Common definition of peak2. Avoided cost and E3 Calculator updates for peak and critical peak3. How RA affects (1) and (2), and should RA drive the peak and

critical peak definitions4. Improve consistency in load data and peak methods5. Consider whether other peak definitions are needed6. Improvements to load shapes7. Calculation platform8. Correct calculator anomalies 9. Peak savings and consistent counting period10. Further refinements for common E3 calculator11. Update natural gas prices in avoided cost forecast

3

Agenda

Day 1 10am to 12pm: Overview and “Other” issues. 12pm to 1pm: Lunch 1pm to 3pm: Load Shapes 3pm to 5pm: Peak Definitions

Day 2 9am to 11am: Peak Costs 11am to 12pm: Resource Adequacy 12pm to 1pm: Lunch 1pm to 2pm: Load shape research plan recommendation 2pm to 4pm: Spillover issues

4

Schedule

Workshops today and tomorrow to gather participant input for E3 consultant report

Draft E3 report on update issues by February 20th

Workshops on draft E3 report (March?) Final E3 report, incorporating feedback from

workshops (April?) Comments on E3 report (May?) Commission decision in June or July 2006.

5

Other Issues

(not load shapes, peak definitions, or avoided cost refinements)

6

Other Issues

(7) Determine the most appropriate calculation platform to use for the program evaluations (i.e., spreadsheet or database).

(8) Correct calculation anomalies with respect to Standard Practice Manual cost-effectiveness indicators/methodologies.

(9) Convert annual savings to peak savings for all measures using a consistent counting period (useful lives > 2 years).

(10) Identify areas where further refinements of input assumptions/ model algorithms may be needed to create a common E3 calculator for use by all implementers.

(11) Update the natural gas prices in the E3 calculator based on current forecasts and consider whether the Commission should revise the ex ante assumptions of avoided costs to reflect these updated gas price forecasts, for the purpose of evaluating the performance of 2006-2008 energy efficiency programs.

7

Calculation Platform

PG&E Likes the transparency and flexibility of Excel, but file sizes are

an issue. SDG&E

Prefers to use SAS. Would conform to common input and output formats

DRA seeking Transparency of inputs assumptions & loads Consistent model input/output format and calculation

methodology (Nice to have) links to DEER or workpapers

SCE Cautions on other applications, but nothing stated on current

use.

8

E3 Calculator Applications

Reporting SCE: No. Use reporting formats being developed

in EE rulemaking PG&E: No

Ex-post cost effectiveness SCE: No. Use simpler spreadsheets for ex-post

calculations (e.g.: pre-1998 TOU spreadsheets)Forecasting

PG&E: No

9

Calculator Anomalies

SDG&ENA

SCEWork with ED re direct installs

DRADirect install costs should be included in TRC

as admin costs

10

Direct Install Costs

Such costs have historically been treated as “customer incentives” (transfer payments) in both the TRC and PAC cost effectiveness calculations.

The Standard Practice Manual states that “the costs in [the TRC test] are the program costs paid by both the utility and the participants plus the increase in supply costs for the periods in which load is increased. Thus all equipment costs, installation, operation and maintenance, cost of removal (less savage value), and administration costs, no matter who pays for them, are included in this test.” (Standard Practice Manual, July 2002, p.18)

11

Counting Period

Both considering and ignoring useful lives is sufficient (SDG&E)

Useful lives must be incorporated, and snapshots at particular points in time (DRA)

kW 2006 2007 2008 2009 2010 2011 2012 2013Reduction Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

Measure 1 2 2 2 2 2 2 2 2 2Measure 2 2 2 2 2 2 2 2 2 2Measure 3 2 2 2 2 2 2 2 2 2Measure 4 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3Measure 5 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3Measure 6 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3Measure 7 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4Measure 8 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4Measure 9 4 4 4 4 4 4 4 4 4 4 4 4 4Total 27 6 6 8 11 11 11 11 13 14 18 16 16 19 19 19 17 17 17 17 14 18 18 18 18 15 15 15 15 12 12 12 12

12

Common E3 Calculator

Not possible in current format because of IOU-specific information (SDG&E)

Commonality of inputs and outputs can be achieved (SDG&E, SCE, DRA, PG&E)

Load shapes should not necessarily be the same (SCE)

Peak reduction methodology should be consistent (DRA)

13

Natural Gas Update

Use 2005 Integrated Energy Policy Report inputs (SDG&E, PG&E) Feb 2005 EIA update (SDG&E) Dec 2005 early release EIA Update (PG&E believes last forecasts

PRIOR to 2006 program should be used for planning, authorizing, and funding.)

SCE does not necessarily endorse the EIA or CEC forecasts. SCE recommends a blend of market forwards and a fundamentals forecast.

TURN supports an update – but not as an excuse for higher incentive payments.

DRA supports updates, and recommends consistency with IEPR and LTPP cycles.

14

CEC 2005 IEPR

15

Comparison of EG Natural Gas (Forecasts: CEC, EIA 2005, EIA 2006)

Comparison of Electric Generation Natural Gas Forecasts

$-

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

2006

2008

2010

2012

2014

2016

2018

2020

2022

2024

2026

2028

2030

$200

6/M

MB

tu

2005 CEC IEPR: Statewide Average

2005 DOE AEO: Pacific Region

2006 DOE AEO: National Average

CEC Reference, http://www.energy.ca.gov/2005publications/CEC-600-2005-026/CEC-600-2005-026-REV.PDF

2005 EIA Referece: http://www.eia.doe.gov/oiaf/aeo/supplement/sup_t2t3.xls

2006 EIA Reference: http://www.eia.doe.gov/oiaf/aeo/excel/aeotab_3.xls

16

Load Data

17

Load Data Issues(4) Improve the consistency in underlying load shape data and the

methods by which that data is translated into peak savings estimates.

(5) Consider whether different definitions (different than that recommended in item (1)) of peak demand reductions for energy efficiency are needed for cost-effectiveness evaluation, establishment of energy efficiency peak reduction goals, evaluating achievement of those goals, critical peak pricing, and resource adequacy counting.

(6) Make improvements to measure load shapes, including: More accurate sources of data than those currently used. Improvements to the consistency in underlying load shape data and the

methods by which that data is translated into peak savings estimates. Specifications for the type of load shapes to be developed. Period for defining demand impacts (e.g.: 60-minute, run time

averages). Calibration of results to annual usage and end-use survey data. Management of data options (how to meaningfully synthesize hundreds

of simulation options per measure). How demand will be measured ex-post.

18

Review of Available End Use Information

Utility Hourly InformationTOU with kW linked to kWh

savings TOU with relative kW savingsPG&E Res (18): 6 A/C Shapes by CZ,

12 other shapes.

Non-Res (290): 2 CZ groups, 11 Sectors, 14 End Use shapes

23 Residential Shapes 17 Shapes across 3 Sectors

SCE Res (23): AC and Heat Pump shapes by 8 CZ, plus seven CZ-

independent shapes.

Non-Res (1096): 960 shapes across 8 CZs and 13 sectors,

plus 136 CZ-independent shapes.

SDG&E 225 CZ independent shapes (Res and Non-Res combined)

19

PG&E Hourly Shapes

PG&E Commercial Hourly ShapesClimate Zone Sector Shapes1 through 5 OTHER COM COOL

11 through 16 OFFICE COOKLODGING AIR

HOSPITALS PROCGROCERY MISCCOLLEGES H20H

WAREHOUSE HEATSCHOOLS MOTOR

RETAIL OFFICERESTAURANTS FRIDGE

REF_WAREHOUSE VENTLGHT_IN

LGHT_OUTWHOLE

PG&E Residential Hourly ShapesA/C Shapes Other Shapes

A/C:4 DRY:ALLA/C:11 FRZ:ALLA/C:12 HEAT_PUMP:ALLA/C:13 MICRO:ALL

A/C:2,16 PPPHRLY:ALLA/C:3,5 REFRIG:ALL

STOVE&OVEN:ALLSPA:ALL

STOVE:ALLWINDOW AC:ALL

DHW:ALLCLOTHES:ALL

20

Shape Cautions

PG&E’s hourly shapes reflect the average usage of an end use, not necessarily the savings profile for a measure.

TOU shapes are generally old and difficult to reproduce.

21

Measure versus Impact Shapes

Not an issue if reductions are proportional to base measure usage

Could be a significant issue for HVAC and shell improvements because of AC duty cycles.

Has been a major issue with two stage compressors.

22

Load Data Comments

Using the best data available (SDG&E) In most cases TOU data is sufficient (SDG&E) Inconsistencies exist in TOU periods, but should not be

considered significant (SCE) Unclear about inconsistencies in DEER methodology

(SCE) DRA’s desire for consistency:

Granularity (hourly vs TOU) Vintage (last update) Baseline assumptions

23

Existing Summer Peak TOU Period Definitions Summer Season

Summer Peak Period Hours

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov DecPG&ESCESDG&E

0 to

1

1 to

2

2 to

3

3 to

4

4 to

5

5 to

6

6 to

7

7 to

8

8 to

9

9 to

10

10 to

11

11 to

12

12 to

13

13 to

14

14 to

15

15 to

16

16 to

17

17 to

18

18 to

19

19 to

20

20 to

21

21 to

22

22 to

23

23 to

24

PG&ESCESDG&E

24

Variation in Avoided Costs Due to TOU Definitions

PG&E Definitions Avg Cost Usage Shares by TOUTOU Hours ($/MWh) Office Cool Office Light Res A/C:13 Res Refrig

1 774 118.82$ 28% 17% 29% 11%2 903 88.59$ 21% 15% 24% 11%3 2739 63.85$ 21% 17% 46% 33%5 1612 83.34$ 22% 33% 1% 17%6 2732 66.15$ 8% 18% 1% 28%

SCE Definitions Avg Cost Usage Shares by TOUTOU Hours ($/MWh) Office Cool Office Light Res A/C:13 Res Refrig

1 504 128.07$ 19% 11% 28% 7%2 756 83.73$ 16% 11% 29% 10%3 1668 62.66$ 14% 11% 36% 21%5 2210 87.05$ 37% 44% 4% 24%6 3622 65.48$ 14% 24% 4% 37%

PG&E TOU Avg Cost ($/MWh) 88.9$ 83.5$ 85.8$ 76.5$ SCE Avg Cost ($/MWh) 85.7$ 81.5$ 87.0$ 75.9$ Hourly Average Cost ($/MWh) 89.4$ 83.5$ 97.6$ 76.8$

25

Improvements to Load Shapes

M&E efforts in future for temperature sensitive loads. Until then, current methods are adequate. (SDG&E)

DEER Database should be updated to ensure consistent methodology. Until then utilities should continue to use the best available data. (SCE)

Work towards hourly data in the long term (SCE) CZ specific data for temp sensitive loads, and load

shapes specific to end-use sectors. (DRA) Don’t use uncalibrated load data, and balance timing

resource and accuracy considerations.

26

Peak Demand

27

Peak Questions

(1) Develop a common definition of peak (and critical peak or other terms, as appropriate) demand reductions to use in evaluating energy efficiency resources across proceedings.

(2) Update the interim avoided cost methodology/E3 calculator to more accurately reflect the impact of energy efficiency, distributed generation and demand response on peak and critical peak loads, including consideration of how critical peak avoided costs should be used in the context of energy efficiency measures that are not fully dispatchable.

(3) Consider how the recently adopted resource adequacy counting rules adopted in D.05-10-042 and D.04-10-035 might affect (1) and (2) above.6 For example, should the definition of peak or critical peak only apply to load reductions that count toward meeting resource adequacy requirements under the “top down” approach adopted by those rules?

28

Proposed Peak Definitions

SDG&E: 300 hour Coincident Peak (if temp responsive) DEER for non temp responsive TOU on-peak is adequate fall back for T&D

SCE: Average demand reduction during summer peak (conservative estimate), or

current TOU estimates for on-peak reductions. TURN:

Critical peak period, such as top 100 hours DRA:

Forecasting: 10 yr weather normalized system load factor Evaluating performance: System coincident peak hour (after testing validity)

PG&E Move toward RA definitions.

29

Peak Impact Examples

SCE Example: Demand Reduction = Basecase Max – EE Max

Time

Dem

and

on-peak period (hrs., days, etc.)

Dmax

Figure 2. Time varying on-peak demand (single site).

EEM (De)

Basecase (Db)

Tb Te

Db De

30

What is DEER Reporting?

31

Different Peak Definitions

None needed (SDG&E, SCE) Given any new definition, future goals should not

be unreasonable (SCE) Straw dog analyses of alternate definitions are

needed, and attention to cycling equipment is important (TURN)

Peak demand reductions for goals assessment should be NET (DRA)

Tailor definition to application. If procurement cost reduction is the value of EE, use RA.

32

Peak Costs Sufficiently Captured?

SDG&E: Refinements possible, but adequate for now. Does not support creating

smaller intervals if data is lacking. SCE:

Replace PX shapes with TOD values adopted in the RPS rulemaking TURN:

Additional refinement needed to value critical peak versus summer peak. May be an additional value during critical peak periods.

PG&E: No. Gen capacity should be separated then combined with RA

requirement reduction. Critical peak needs careful definition to be useful.

33

TOD FactorsTOD Duration Curves

0%

50%

100%

150%

200%

250%

300%

350%

400%

1 1001 2001 3001 4001 5001 6001 7001 8001

Hours

TO

D F

acto

r (%

of

An

nu

al A

vera

ge)

SCE SDG&E PG&E NP15SP15

SCE

SDG&E

PG&E

34

TOD Factors for Top 500 hoursTOD Duration Curves

0%

100%

200%

300%

400%

500%

600%

1 101 201 301 401 501

Hours

TO

D F

acto

r (%

of

An

nu

al A

vera

ge)

SCE SDG&E PG&E NP15SP15

SCE

SDG&E

PG&E

35

TURN Critical Peak Avoided CostsE-3 Modeling of Combustion Turbine and CPP Cost Duration Curves (2,500 highest cost hours, using E-3 model, 2010, $6.50 gas)

$0

$100

$200

$300

1 501 1,001 1,501 2,001

Hours

$/M

Wh

CPP Hours Non-CPP Hours

CT Profits

CT Costs CT does not run

CT Profitin CPP hours Avoided by CPP but included in E- 3energy price ,so it must also be subtracted from the capacity cost when using the E-3model

CT Profit in Non-CPP hoursExtra money saved by CT.Subtract from gross CT capacity cost when calculating CPP capacity benefit.

CT Costsin CPP hoursAvoided by CPP but included in E-3 energy price

Market Price

High cost non-summer hours

36

Dispatchability

SDG&E: No dispatchable programs funded in EE portfolio.

SCE: No revisions needed for EE programs.

PG&E: Dispatchable programs treated as DR.Would earn higher energy values than EE.

37

Dispatchability Adder Discussion

Higher average avoided cost by TOU period dues to ability to discard lower value hours

Higher value due to option value, which increases the value of a dispatchable program in the “shoulder” value hours. Hourly avoided costs are point estimates, but there is a

distribution around each point. For low cost and very high cost hours, the dispatch decision is

unaffected by the distribution --- so no option value change. For shoulder hours, combining the distribution of avoided costs

with the strike price could yield higher value that just using the point estimate of avoided cost

38

Resource Adequacy

Included as a reduction to load, so counting not an issue (SDG&E, SCE, TURN, DRA)

GROSS reductions should be counted as reductions, (not Net) (DRA)

RA Topdown approach reflects an interest in physical resources and is only an INTERIM protocol (DRA)

Assess difference between MW peak reductions from an RA perspective, so adjustments could be made in the future if needed. (PG&E)

39

Other Comments

TURN recommends a technical work group

TURN recommends that differing TOU period definitions for IOUs be assessed

TURN recommends immediate work to more reasonably reflect the lighitng and HVAC impacts.