issues summary
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Issues summary. Pre workshop comments. Scope of the 2006 Update. Common definition of peak Avoided cost and E3 Calculator updates for peak and critical peak How RA affects (1) and (2), and should RA drive the peak and critical peak definitions - PowerPoint PPT PresentationTRANSCRIPT
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Issues summary
Pre workshop comments
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Scope of the 2006 Update1. 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
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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
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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.
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Other Issues
(not load shapes, peak definitions, or avoided cost refinements)
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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.
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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.
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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
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Calculator Anomalies
SDG&ENA
SCEWork with ED re direct installs
DRADirect install costs should be included in TRC
as admin costs
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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)
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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
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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)
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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.
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CEC 2005 IEPR
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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 Average2005 DOE AEO: Pacific Region2006 DOE AEO: National Average
CEC Reference, http://www.energy.ca.gov/2005publications/CEC-600-2005-026/CEC-600-2005-026-REV.PDF2005 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
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Load Data
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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.
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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)
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PG&E Hourly ShapesPG&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
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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.
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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.
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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
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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
11
to 2
2 to
33
to 4
4 to
55
to 6
6 to
77
to 8
8 to
99
to 1
010
to 1
111
to 1
212
to 1
313
to 1
414
to 1
515
to 1
616
to 1
717
to 1
818
to 1
919
to 2
020
to 2
121
to 2
222
to 2
323
to 2
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PG&ESCESDG&E
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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$
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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.
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Peak Demand
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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?
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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.
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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
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What is DEER Reporting?
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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.
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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.
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TOD FactorsTOD Duration Curves
0%
50%
100%
150%
200%
250%
300%
350%
400%
1 1001 2001 3001 4001 5001 6001 7001 8001
Hours
TOD
Fac
tor (
% o
f Ann
ual A
vera
ge)
SCE SDG&E PG&E NP15SP15
SCE
SDG&E
PG&E
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TOD Factors for Top 500 hoursTOD Duration Curves
0%
100%
200%
300%
400%
500%
600%
1 101 201 301 401 501
Hours
TOD
Fac
tor (
% o
f Ann
ual A
vera
ge)
SCE SDG&E PG&E NP15SP15
SCE
SDG&E
PG&E
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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-3 energy 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
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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.
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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
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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)
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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.