California SONGS\OTC
Plants Assumptions
TEPPC – Data Work Group Call
Tuesday, September 15, 2015
2
Overview
• Status of OTC Replacement Assumptions For the TEPPC
2026 Common Case
– CEC Demand Forecast
– CEC Demand Response
– CAISO\CEC
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Monthly Peak/Energy Load?
AAEE assumptions? Embedded in monthly load or separate?
Other EE assumptions? Embedded in monthly load or separate?
BTM DG assumptions? Embedded in monthly load or separate?
DR assumptions? Embedded in monthly load or separate?
– Additional Generic Preferred Resources in the LA Basin
– OTC Replacement Assumptions for Northern California
– Final OTC Plant Assumptions Table
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Status
• Southern California
– Meeting participants generally agreed to a detailed spreadsheet
showing substation-level detail for CPUC-authorized Once-ThruCooling (OTC) replacement procurement assumptions.
– However, Few questions were raised about levels of Energy
Efficiency and Demand Response forecasts and recommended
treatment in TEPPC modeling.
• Northern California
– Just use assumptions in the CAISO 2015-2016 Study Plan, listed
in Table 4-4. Exception, use the CEC assumptions for Moss
Landing units 1&2.
(http://www.caiso.com/Documents/2015-2016FinalStudyPlan.pdf)
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Table 4-4: Once-through cooled generation in the California ISO BAA
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CEC Demand Forecast
Angela Tanghetti
California Energy Commission
CEC Demand Forecast
– 10 year forecasts of electricity consumption and
peak demand
– CED 2013 and 2014 Updated included 8 major
utility planning area in California, and 16 climates
zones
– CED 2015 uses a modified planning area scheme
more closely matched to the states balancing
authority areas
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A G E
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Energy Efficiency and CEC’s Demand
Forecast
• Energy Efficiency – CEC demand forecasts seek
to account for efficiency and conservation
reasonably expected to occur. Reasonably
expected to occur initiatives have been split
into two types: committed and additional
achievable energy efficiency
• The CED 2015 Preliminary baseline forecasts
continue that distinction, with only committed
efficiency included
P
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Energy Efficiency and CEC’s Demand
Forecast
• Committed includes utility and public agency
programs, codes and standards, and
legislation and ordinances having final
authorization, firm funding
• A demand forecast for resource planning
requires a baseline forecast combined with
additional achievable energy efficiency savings
(not yet considered committed but deemed
likely to occur)
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BTM PV Peak and Energy Impact On CEC
Demand Forecast
• For CED 2015 Preliminary, staff spent time
refining the peak factors used to translate PV
installed capacity to impact during the utility
annual peak hour.
• To refine PV peak factors staff examined
simulated PV production profiles provided by
CPUC relative to utility annual peak day
between 2011 through 2014.
P
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PV Peak Factors
Utility
PG&E
SCE
SDG&E
CED 2011 CED 2013 CED 2015
55%
50%
37%
62%
50%
40%
68%
50%
40%
Source: California Energy Commission, Demand
Analysis Office, 2015
P
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1 0
CED 2015 Mid Case BTM PV
Statewide
2026
Mid_Demand
Installed Capacity Peak Capacity
Energy
Capacity Factor
MW
MW
GWh
%
13,194
5,062
23,450
20.3%
If BTM PV is modeled as supply side resource
installed capacity in addition to peak impact and
energy is required. Hourly profile must have similar
capacity factor
P
A G E
1 1
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CEC Demand Response
Lana Wong
California Energy Commission
Demand Response
• Demand-side DR – embedded in CEC Demand
forecast
– Non-event based, critical peak pricing and peak time
rebates
– Non-dispatchable
– Customer controlled
– Draft June 2015 Demand report, 261 MW by 2026:
• PG&E 125 MW
• SCE 90 MW
• SDG&E 46 MW
Demand Response (cont.)
• Supply-Side DR – not embedded in CEC
Demand forecast
– Dispatchable
– Event based and price responsive
– Counts for Resource Adequacy - include in
planning reserve margin calculations
– CPUC LTTP Planning Assumptions based on
Utilities’ Load Impact Reports
Demand Response (cont.)
– Dispatchable DR (MW) - CPUC Scenario Tool 2014 for
2026
• PGE Bay – 139 MW
• PGE Valley – 634 MW
• SCE – 1,361 MW
• SDGE – 42 MW
Note: above values include avoided T&D losses;
Load Impact Reports of each IOU (Portfolio-adjusted ex-ante
estimates for August in a 1-in-2 weather year, generally average
load impact over the hours of the day an event may be called)
– Different quantities of DR are modeled depending on
the type of study
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CPUC-Authorized OTC Replacement Procurement
Assumptions for TEPPC 2026 Common Case
Jan Strack
Sempra Energy Utilities
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CPUC-Authorized OTC Replacement Procurement
Assumptions for TEPPC 2026 Common Case
• Substation-level detail for CPUC-authorized Once-ThruCooling (OTC) replacement procurement assumptions for
incorporation into the TEPPC 2026 Common Case.
• added 99 (100) MW of generic preferred resources +
storage in the LA Basin in order to reach the CPUC-specified
minimum procurement authorization for preferred
resources + storage. specific types as suggested by the
CPUC staff.
• It is assumed that the EE numbers included in this
workbook are incremental to the Additional Achievable
Energy Efficiency (AAEE) forecast developed by the CEC.
Likewise, the behind-the-load meter solar PV numbers
would be in addition to the amounts forecast by the CEC.
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Additional 100 MW of Preferred in the LA Basin
• The 25 MW of generic Behind-The-load-Meter (BTM) solar PV
(column G) would be modeled with the same shape as the 37.92
MW of BTM solar PV (column E).
• The 25 MW of generic storage (column P) would be modeled with
the same performance characteristics as the 100 MW (column L)
of 4 hour In-Front-Of-the-load Meter (IFOM) storage.
• The 25 MW of generic incremental Energy Efficiency (EE) (column
U) would be modeled with the same shape as the 124.21 MW of
incremental EE (column S).
• The 25 MW of generic demand response (column Z) would be
modeled with the same performance characteristics as the 75.05
MW (column X) of ISO market-implemented demand response.
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