Low Carbon Grid Study (LCGS) Workpapers:
Assumptions for production cost modeling and revenue
requirement impact analysis
TABLE OF CONTENTS
I.
Introduction........................................................................................................................................... 2
II.
Acronyms .............................................................................................................................................. 2
III. Assumptions behind 2030 emissions target .......................................................................................... 3
IV. Assumptions and data sources in all cases............................................................................................ 4
V.
Case-specific assumptions .................................................................................................................... 9
VI. Tables comparing portfolios in Baseline, Target, and Accelerated Cases .......................................... 10
VII. Assumptions for revenue requirement analysis .................................................................................. 14
VIII. APPENDIX A: Load forecast calculations ......................................................................................... 16
IX. APPENDIX B: Renewable net short for portfolio construction ......................................................... 18
X.
APPENDIX C: Calculations associated with revenue requirement impact analysis .......................... 19
1
I.
Introduction
These workpapers are intended to provide transparency in the assumptions that were made in the LCGS
analysis. The body of this paper details the assumptions, with links to sources where possible, embedded
in portfolio development, PLEXOS model runs, and revenue requirement impact analysis. Appendices
detail processes or calculations used to arrive at relevant values. Supplemental spreadsheets containing
more lengthy calculations are posted with this document and referred to throughout the text. If an
assumption or source is unclear or a link does not work, please contact [email protected].
II.
Acronyms
AAEE: additional achievable energy efficiency
CAES: compressed air energy storage
CAISO: California Independent System
Operator
CARB: California Air Resources Board
CC: combined cycle
CEC: California Energy Commission
CHP: combined heat and power
CPUC: California Public Utilities Commission
CSP: concentrating solar power
CT: combustion turbine
DR: demand response
EE: energy efficiency
EIA: Energy Information Agency
EIR: environmental impact report
EV: electric vehicle
FERC: Federal Energy Regulatory Commission
HSR: high speed rail
IEPR: Integrated Energy Policy Report
IOU: investor-owned utility
IPP: Intermountain Power Plant
ITC: investment tax credit
LADWP: Los Angeles Department of Water and
Power
LBNL: Lawrence Berkeley National Laboratory
LCGS: Low Carbon Grid Study
LFC: levelized fixed cost
LTPP: Long Term Procurement Plan
MMT: million metric ton
NQC: net qualifying capacity
NREL: National Renewable Energy Laboratory
O&M: operation and maintenance
OTC: once-through cooling
PHS: pumped hydro storage
POU: publically-owned utility
PPA: power purchase agreement
PTC: production tax credit
PV: photovoltaic
QF: qualifying facility
RPS: renewables portfolio standard
SCIT: Southern California Import Transmission
TEPPC: Transmission Expansion Planning
Policy Committee
WACC: weighted average cost of capital
WECC: Western Electricity Coordinating
Council
WWSIS: Western Wind and Solar Integration
Study
ZEV: zero-emission vehicle
2
III.
Assumptions behind 2030 emissions target
The portfolios in the LCGS were constructed with the goal of achieving emissions reductions of at least
50% below 2012 levels in 2030. This was selected to be consistent with the statewide emissions trajectory
proposed in the CARB AB 32 First Update to the Climate Change Scoping Plan between the AB 32 2020
emissions target of 1990 levels to the EO S-3-05 2050 emissions target of 80% below 1990 levels. In the
Scoping Plan, two trajectories between 2020 and 2050 are proposed: a constant annual mass reduction or
constant annual percentage reduction.1
 The electric sector has historically made up slightly over 20% of statewide emissions. Assuming
that the electric sector continues to contribute about 20% of statewide emissions,2 electric sector
should emit ~50 MMT in 2030 to remain on the constant annual percentage reduction trajectory.
The target of 50% below 2012 emissions levels, or 47 MMT, falls just under the constant annual
percentage reduction trajectory (see Figure 1).
 All emissions data was taken from CARB’s California Greenhouse Gas Emissions Inventory.3
Figure 1: Target of 47 MMT in 2030 (just under 50% below 2012 levels) plotted with CARB constant annual percentage
reduction trajectory between 2020 and 2050, as well as 2012 actual emissions.
Actual 2012 electric sector emissions: 95.09 MMT. Estimated electric sector emissions in 2020: 85.4 MMT and 2050: 17.2 MMT.
1
For an illustration of the two trajectories, see p. 33 of the CARB Scoping plan (link).
This analysis does not intend to claim that the electric sector will continue to contribute 20% of statewide emissions by 2030.
However, in the absence of adopted sector-specific targets, this assumption is a useful proxy for determining a 2030 goal.
3 See CARB’s Greenhouse Gas Emission Inventory (link).
2
3
IV.
Assumptions and data sources in all cases
The following assumptions are included in all cases in Phase I of the LCGS. Assumptions with square
bullets note differences between the Target Case and sensitivities that were run to examine the effects of
fewer measures that mitigate renewable generation curtailment.
WECC load, generation, and transmission
Load, transmission, and generation assumptions in non-California western states were based on the
TEPPC 2020 and 2022 Common Cases, updated with details assumptions from the NREL’s Western
Wind and Solar Integration Study, Phase 24
• The 2022 Common Case includes all other WECC states meeting their current RPS targets, 5
scaled to 2022
• Announced fossil retirements in the TEPPC 2022 Common Case were implemented (see Table 1)
• Intermountain Power Project (units 1 and 2) was also assumed to be retired6
• Transmission additions in the TEPPC 2022 Common Case are shown in Figure 2
Table 1: Retirements assumed in the 2022 Common Case (adapted from Table 2 of the 2022 Common Case assumptions)
Province/State
Alberta
British Columbia
California
Colorado
Nevada
New Mexico
Oregon
Texas (EPE)
Washington
Unit Name
Fuel
Battle River 3,4
Coal
HR Milner
Coal
Sundance 3
Coal
Burrard Thermal 1-6
Natural gas
Coolwater 1,2
Natural gas
Kearny 1-3
Natural gas
Mandalay 3
Natural gas
Pittsburg 7
Natural gas
see OTC list for other OTC related retirements
Arapahoe 3,4
Coal
Cherokee 1,2
Coal
Cherokee 3,4
Coal
Valmont 5
Coal
Zuni 1,2
Natural gas
Fort Churchhill 1,2
Natural gas
Reid Gardner 1-3
Coal
Sunrise 1,2
Natural gas
Tracy 1,2
Natural gas
Four Corners 1-3
Coal
Rio Grande 6,7
Natural gas
Boardman 1
Coal
Newman 1-3
Natural gas
Centralia 1
Coal
Fredonia 1,2
Natural gas
Frederickson 1,2
Natural gas
Whitehorn 1,2
Natural gas
4
Original dataset was built from the 2020 Common Case (link), updated with the TEPPC 2022 Common Case (link), and
enhanced with detailed assumptions from the Western Wind and Solar Integration Study, Phase 2 (NREL 2013, link).
5 RPS targets across the United States can be found in the Database of State Incentives for Renewables & Energy Efficiency
(DSIRE, link). If the Common Case did not include the full RPS in a given state, the renewable generation in that state was
scaled up to meet its announced RPS by 2030.
6 IPP, located in Utah and linked to the LADWP service territory, is scheduled to retire by 2025. See p. 7 of 2013 Power
Integrated Resource Plan (link to website).
4
Figure 2: New transmission assumed in the 2022 Common Case (Figure 1 in Common Case Report)
5
California load (total load without including incremental EE: 379 TWh)
For more detail on load forecast calculations, see APPENDIX A: Load forecast. Load assumptions for
California in 2030 were based on the CEC’s 2014-2024 “mid” demand forecasts7 with the following
modifications:
• The Governor’s mandate8 of 1.5 million ZEVs by 2025 was met and surpassed by 2030
• All cases assume 12.4 TWh of EV load in California in 2030
• This is equivalent to approximately 4.25 million EVs, of which 1/3 are battery EVs and
2/3 are plug-in hybrid EVs
• Half the EV load (6.2 TWh) was designated schedulable and contributed to the DR total
• Load from high speed rail segment scheduled to come online in 2029 (5.4 TWh) is included
• Load forecast includes generation served by customer-sited resources
California generation and transmission
California’s 2020 generation portfolio was based on the CPUC’s 2012 LTPP, which includes the
following resource additions (incremental from 2014):9
• New thermal generation: 500 MW combined cycle and 2000 MW combustion turbine
• New renewable generation: the LTPP portfolio meets the 33% RPS mandate in 2020
The generation portfolios assumed to be built between 2020 and 2030 differed between the cases.
• See Case-specific assumptions and Table 6 for more detail
The LCGS portfolios also included the following modifications to the 2012 LTPP portfolio:
• All plants affected by the State Water Resources Control Board OTC regulations10 were assumed
to be retired or replaced by 2030, according to the TEPPC Common Case
• The retirements and replacements are listed in Table 2
□ Diablo Canyon Power Plant was assumed to retire when up for license renewal in 2024
• California utilities maintained their current share of Palo Verde Generating Station, AZ (~8.7
TWh annual nuclear energy)11
• The 3000 MW target in the initial program period of CPUC’s QF and CHP program settlement
was assumed to be met12
• In the PLEXOS database, 3300 MW of gas-fired generation was designated as CHP, of
which 1400 MW was designated as must-run
• Although not explicitly modeled, in post-processing steps, this was treated as 3000 MW
of CHP, in accordance with the CPUC settlement. Of this, 500 MW is treated as
dispatchable and 2500 MW is treated as must-run
• An 800 MW AC-DC:DC-AC flow controller was added between LADWP and CAISO territories
Other California policies
• Portfolios required to maintain 15% planning reserve margin, using NQC methodology13
7
Load projected to 2030 from California Energy Demand 2014-2024 Final Forecast (link), with some modification.
Governor’s Executive Order B-16-2012 (link) sets a target of 1.5 million zero emission vehicles in California by 2025.
9 Energy and capacity numbers from the 2012 LTPP portfolio can be found in Tables 2 and 3 of Estimating the Value to UtilityScale Solar Technologies in California Under a 40% Renewable Portfolio Standard (NREL, 2014 link). Details of capacity in
2020 portfolio can be found in Table 6.
10 Fact sheet from SWRCB lists the 19 OTC plants (link)
11 California utilities own 27.4% of Palo Verde Nuclear Generation Station’s capacity (link).
12 Because the MW target in the second program period is not settled, it was not included in Phase I of this work. Sensitivities
around this settlement will be run in Phase II. Information on the settlement can be found on the CPUC’s website (link).
13 For consistency with CPUC requirements, LCGS portfolios were constructed to maintain a 15% reserve margin, computed
using CPUC methodology (link).
8
6
□
•
Exports from California were limited to 2000 MW, based on a slight increase from historical
trends14
CPUC storage procurement target, which requires IOU procurement of 1325 MW15 of small-scale
storage by 2020, was met in all cases. 1500 MW of small storage was assumed in all cases to
account for some growth after 2020.
Other Western Interconnection policies
• Frictionless optimal dispatch throughout the Western Interconnection was assumed (this is
equivalent to a day-ahead, day-of, and real time energy imbalance market)
Table 2: OTC retirements/replacements as listed in Table 3 of 2022 PC1 Common Case, Sept 19, 201316
Resource Name
2009
Load serving
Group17
Capacity
entity
Capacity
Retired
Capacity
Added
Year Added or
Retired
Comments
Alamitos 1-6
2,010
OTC -
SCE
2,010
2020
Contra Costa6
337
OTC -
PG&E
337
2014
Contra Costa 7
337
OTC -
PG&E
337
2014
El Segundo 3
335
OTC -
SCE
335
2013
Replaced by NRG El Segundo Repower
Project (see below)
El Segundo 4
335
OTC -
SCE
335
2017
Not part of unit 1-3 repower, may be
repowered separately later
OTC +
SCE
El Segundo RP
560
2013
Encina 1-5
945
OTC -
SDGE
945
2017
Encina GT
15
OTC -
SDGE
15
2017
OTC +
SCE
1,000
2020
OTC +
SCE
1,000
2020
OTC -
LDWP
341
341
Generic CC
(SCE)
Generic CT
(SCE)
Haynes 5
341
Haynes 6
341
Mandalay 1-2
2013
OTC -
LDWP
OTC +
LDWP
226
OTC -
SCE
226
2020
226
OTC -
SCE
226
2020
225
OTC -
SCE
225
2013
227
OTC -
SCE
227
2013
430
OTC -
SCE
430
2020
See addition of Generic CC/CT (SCE).
2014
Replacing Contra Costa 6 & 7
Haynes GT 1-6
Huntington
Beach 1
Huntington
Beach 2
Huntington
Beach 3
Huntington
Beach 4
Replaced by Marsh Landing Project (see
below)
Marsh Landing
2013
600
719
2012
OTC +
PG&E
Morro Bay 3
325
OTC -
PG&E
325
2015
Morro Bay 4
325
OTC -
PG&E
325
2015
See addition of Generic CC/CT (SCE)
above.
See Walnut Creek; retired early to
transfer air permits to WC.
14
Page 88 of Investigating a Higher Renewables Portfolio Standard in California (E3, 2013, link) states that maximum historical
exports from California total 1500 MW.
15 CPUC Decision 13-10-040: Decision Adopting Energy Storage Procurement Framework and Design Program (link) requires
the procurement by California IOUs of small storage facilities (<50 MW) totaling 1,325 MW by 2020. Some installations may
occur after 2020, but all are assumed to be completed in the Baseline Case, with 175 MW incremental storage, as noted.
16 TEPPC 2022 Common Case assumptions (link)
17 [footnote from TEPPC document] “OTC –” represents retirements due to OTC implementation. “OTC +” represents generator
additions or retrofits intended to replace retired OTC generators.
7
Resource Name
2009
Load serving
Group17
Capacity
entity
Moss Landing
1-2
Capacity
Retired
Capacity
Added
PG&E
Year Added or
Retired
2017
Moss Landing 6
754
OTC -
PG&E
754
2017
Moss Landing 7
756
OTC -
PG&E
756
2017
Ormond Beach
1-2
1,516
OTC -
SCE
1,516
2020
Pittsburg 5
312
OTC -
PG&E
312
2017
Pittsburg 6
317
OTC -
PG&E
312
2017
1,343
OTC -
SCE
1,343
2020
445
OTC -
LDWP
445
2016
OTC +
LDWP
Redondo Beach
5-8
Scattergood 3
Scattergood CC
509
Comments
considering retrofit of existing units
also considering retrofit; assume
retirement
See Generic CC/CT (SCE).
2016
8
V.
Case-specific assumptions
The three primary 2030 portfolios, the Baseline, Target, and Accelerated Cases, were constructed by
adding generation and other energy resources to the 2020 portfolio (2012 LTPP) as described below. See
Table 3, Table 4, Table 5, and Table 6 for detailed comparisons between the cases.
 The Baseline Case, a “business as usual” case, was built on the assumption that all current
policies (i.e. AB 32, 33% RPS, CPUC storage procurement targets, requirements of the first
program period of the QF/CHP settlement, etc) were successfully implemented, but that no new
clean energy or emissions reduction policies were introduced.
o To meet the 33% RPS in 2030, 9.1 TWh (4,110 MW) of wholesale solar PV was added
o A new 600 MW combined cycle plant was also added to maintain a 15% planning
reserve margin, as currently required by the CPUC
o The CEC’s “mid” level of EE was included, consistent with jointly-adopted CPUC
rulemaking R13-12-01018
o No storage past the current bulk storage and the small storage procurement target was
included
o Some demand response was added
 The Target Case was constructed to meet the study’s emissions target of at least 50% emissions
reductions from 2012 levels by 2030. See APPENDIX B: Renewable net short for portfolio
construction for more information on this calculation.
o A diverse portfolio of renewable energy (79 TWh) was added to the 2020 portfolio with
the goal of meeting the 2030 emissions target
o The CEC’s “high mid” level of EE was included, consistent with the “Expanded
Preferred Resources” scenario in the jointly-adopted CPUC rulemaking R13-12-010
o 1000 MW of pumped hydro storage (CA) and 1200 MW of CAES (UT) were added
o More demand response was added than in the Baseline Case
o Some transmission in WY and NM was added to accommodate additional wind resources
o Other than the renewables added to reduce emissions, no generation was needed to meet
the planning reserve margin requirement.
 The Accelerated Case was constructed to achieve deeper emissions reductions than the Target
Case, to examine the effects of expediting California’s progress on the trajectory to 2050. The
following describes the differences between the Target and Accelerated Cases:
o A diverse portfolio of renewable energy (108 TWh) was added to the 2020 portfolio with
the goal of meeting the 2030 emissions target
o In addition to the bulk storage in the Target Case, 1200 MW of additional pumped hydro
storage was added in the Accelerated Case
Two sensitivities on the Target Case with fewer mitigation measures (i.e. less storage, no demand
response, less regional trading, etc) were run to analyze the effect of these measures on curtailment. The
details of these sensitivities are listed in Table 7.
18
Link to the CPUC rulemaking is here (link to ruling and link to update). See below for more detail.
9
VI.
Tables comparing portfolios in Baseline, Target, and Accelerated Cases
Table 3: Assumptions that differ between Baseline, Target, and Accelerated Cases
Baseline
Target
Accelerated
Incremental • “Mid” incremental EE case from
CEC 2014 demand forecast20 for
EE 19
IOU territories
• CPUC POU incremental EE
projection for POU territories21
• “High Mid” incremental EE case
from CEC 2014 demand forecast for
IOU territories
• CPUC POU incremental EE
projection for POU territories
• Same as Target Case
Renewables • Renewables added to maintain 33%
RPS in 2030 (110 TWh total). To
portfolio
continue current procurement
trends, added energy was wholesale
PV22
• Customer-sited PV generates total
of 6% of retail sales
• Added a diverse renewables portfolio • Same as Target Case, with a
to fill calculated renewable net short
larger portfolio of diverse
(177 TWh total)
renewables for deeper
emissions reduction (205 TWh
• Customer-sited PV generates total of
total)
10% of retail sales
• Customer-sited PV generates
total of 10% of retail sales
Demand
response
• Significant improvement in demand
response from today23
• Includes assumption that half of EV
load is schedulable
• Twice as much DR as Baseline Case
• Includes assumption that half of EV
load is schedulable
• Same as Target Case
Transmission
• Line connecting CAISO to LADWP
(in all cases)
• Line connecting Wyoming wind
resources to existing IntermountainLADWP DC line in Utah
• Line connecting New Mexico’s wind
to Four Corners
• Line connecting CAISO to LADWP
(in all cases)
• Same as Target Case
Thermal
fleet
• 600 MW CC replaces retired IPP24
to maintain 15% reserve margin
Storage
• 1325 MW CPUC storage
procurement target and 175 MW
additional small-scale energy
storage (in all cases)
• 1325 MW CPUC storage
• 1325 MW CPUC storage
procurement target and 175 MW
procurement target and 175
additional small-scale energy storage
MW additional small-scale
(in all cases)
energy storage (in all cases)
• 1000 MW PHS in California
• 3200 MW PHS in California
• 1200 MW CAES plant at
• 1200 MW CAES at
Intermountain, Utah25
Intermountain, Utah
“Incremental EE” is EE that had not been committed or paid for by 2014. This is subtracted from 379 TWh to find net load.
The CEC’s demand forecast includes forecasts for 5 scenarios for “additional achievable EE,” the incremental EE in IOU
territories: low, low mid, mid, high mid, and high. The mid case, assumed in the LCGS Baseline Case, was adopted for California
system-wide and flexibility planning by CPUC rulemaking R13-12-010 (link). This rulemaking also adopted use of the high mid
case, assumed in the Target and Accelerated Cases, for “Expanded Preferred Resources” scenarios.
21 Incremental EE in POU territories was taken from POU estimates from the 2011 and 2013 IEPRs. These are compiled in the
LTPP “Scenario Tool 2014 in Excel v2” spreadsheet from a May 14, 2014 workshop (link). As only one scenario was presented
in this tool, the POU incremental EE is assumed to be the same in all cases.
22 The wholesale renewables portfolio in the 2012 LTPP (used to construct the 2020 case) is about 25% solar PV. In CAISO’s
recent testimony into the LTPP, the wholesale renewables portfolio in their “40% RPS in 2024” scenario is ≈40% solar PV,
meaning that the expected procurement consists largely of wholesale solar PV.
23 DR assumptions based on NREL/LBNL’s Grid Integration of Aggregated DR, Parts 1 and 2 (link, link). CAISO, in the 2014
Summer Loads & Resources Assessment, estimated the DR available on their system during summer 2014 would be 2 GW (link).
24 Replacement of IPP with 600 MW CC plant is described on p. 129 of LADWP’s 2013 Power Integrated Resource Plan.
25 Submission to TEPPC by Burbank Water and Power describes a scenario that includes a CAES plant in Utah (link)
19
20
10
Table 4: Quantitative comparison between Baseline, Target, and Accelerated Case portfolios
Baseline
Biomass
Geothermal
Wind
CSP26
Wholesale PV
Customer-sited PV
Small Hydro
Total renewable generation
Large hydro
Gas CC
Gas CT
CHP-QF
Total other generation
Total storage27
Total EE
Total DR28
Transmission additions
Target
Accelerated
GW
TWh
GW
TWh
GW
TWh
1.3
10
1.6
12
1.6
12
2.7
22
4.2
34
5.3
43
10
25
20
59
23
69
1.4
3.4
3.1
8.1
3.8
10
14
30
15
35
18
42
8.9
14
14
22
15
23
1.4
6.1
1.4
6.1
1.4
6.1
40 GW
110 TWh
60 GW
177 TWh
67 GW
205 TWh
7.1
31
7.1
31
7.1
31
20.2
115
19.6
71
19.6
62
9.3
18
9.3
9.3
9.3
8.3
3.2
24
3.3
23
3.2
23
40 GW
188 TWh
39 GW
135 TWh
39 GW
125 TWh
5.0
7.2
9.4
8.7
38
13.3
58
13.3
58
3.7
8.7
7.3
17.3
7.3
17.3
800 MW CAISO-LADWP 800 MW CAISO-LADWP 800 MW CAISOintertie
AC-DC:DC-AC flow
LADWP AC-DC:DC-AC
controller at generic
flow controller at a
location in LA Basin; 500 generic location in LA
kV AC line from WY wind Basin; 500 kV AC line
to Intermountain, UT; 500 from WY wind to
kV AC line from NM wind Intermountain, UT; 500
to Four Corners
kV AC line from NM
wind to Four Corners
Table 5: Portfolio breakdown of California’s renewables portfolio in each case by energy and capacity and geographic region.
Most incremental out-of-state renewables are wind in Wyoming and New Mexico.
CA total
Alberta
AZ and NM (APS & PNM)
Northwest (BPA & PACW)
Nevada (SPP & NEVP)
Utah / Wyoming
SCE, SDGE, PGE
TIDC, IID, SMUD, LDWP
Baseline (TWh)
110
1.2
0.0
10
6.3
0
81
11
Target (TWh)
177
1.2
8.4
11
8.3
12
100
36
Accelerated (TWh)
205
1.2
8.6
12
16
20
110
37
26
All CSP in Baseline, except for 150 MW, assumed without thermal energy storage. All incremental CSP in Target and
Accelerated Cases assumed to include thermal energy storage
27 2020 storage assumed to be 4.8 GW
28 DR is reported as schedulable/shiftable capacity during peak hours and total shiftable/schedulable energy
11
Table 6: Comparison between 2020, 2020-2030 incremental, and total 2030 portfolios, with average capacity factors (note:
includes out of state renewables, but no unspecified or nuclear imports)
2020 portfolio
Roughly 2012 LTPP
GW
Avg CF
TWh
Renewables:
Biomass
Geothermal
Solar PV
Solar Thermal
Wind
Small hydro
Customer-sited PV
Total renewable
Large hydro
Total zero-carbon
Conventional:
CC
CT
CHP
Total
Storage
1.3
2.7
10
1.4
10
1.4
6.1
33
7.1
40
0.85
0.89
0.24
0.28
0.28
0.51
0.18
GW
10
22
21
3.4
25
6.1
10
97
31
128
0.50
20
9.3
3.2
32
4.8
Total generation
TWh
2020-2030 incremental portfolio
Target
GW
Avg CF
TWh
4.1
0.25
9.1
0.27
1.5
5.4
1.7
9.5
2.8
6.9
0.18
4.5
14
7.9
26
Accelerated
Avg CF
GW
0.18
Baseline
Avg CF
1.3
2.7
14
1.4
10
1.4
8.9
40
7.1
47
0.85
0.92
0.25
0.28
0.28
0.51
0.18
2.0
12
14
4.7
34
0.3
2.6
8.1
2.4
12
0.85
0.92
0.29
0.32
0.41
2.0
21
21
6.8
44
0.18
12
79
8.5
34
0.18
13
108
20.2
9.3
3.2
33
5.0
80
0.65
0.22
0.84
0.55
0.50
2.4
4.6
Total (2020 portfolio + incremental portfolio)
Target
TWh
GW
Avg CF
TWh
GW
10
22
30
3.4
25
6.1
14
110
31
141
1.6
4.2
15
3.1
20
1.4
14
60
7.1
67
0.85
0.92
0.26
0.30
0.34
0.51
0.18
115
18
24
157
19.6
9.3
3.2
32
7.2
99
0.41
0.11
0.83
0.37
298
0.50
Accelerated
Avg CF
12
34
35
8.1
59
6.1
22
177
31
208
1.6
5.3
18
3.8
23
1.4
15
67
7.1
75
0.85
0.92
0.27
0.31
0.35
0.51
0.18
71
9.3
23
104
19.6
9.3
3.2
32
9.4
107
0.36
0.10
0.82
0.33
311
TWh
0.85
0.92
0.29
0.32
0.41
0.60
GW
Renewables:
Biomass
Geothermal
Solar PV
Solar Thermal
Wind
Small hydro
Customer-sited PV
Total renewable
Large hydro
Total zero-carbon
Conventional:
CC
CT
CHP
Total
Baseline
Avg CF
0.50
TWh
12
43
42
10
69
6.1
23
205
31
236
62
8.3
23
94
330
12
Assumptions for sensitivities on Target Case
Two sensitivities were run on the Target Case to test the effectiveness of the mitigation measures included
in the Target and Accelerated Case portfolios. All assumptions in the two sensitivities are the same as
Target Case unless noted in this table.
Table 7: Assumptions that differ between Target Case and two sensitivities on Target Case
Target, sensitivity 1
Target, sensitivity 2
Diablo Canyon
Not retired
Not retired
Electric vehicle load
No schedulable EV demand
No schedulable EV demand
Demand response
No DR
No DR
Imports and exports
No exports
• 1500 MW exports
• Import constraint: California required to
import at least as much as the sum of
California’s procured out-of-state
renewables and CA’s share of Palo Verde
each hour
Storage
• 1500 MW CPUC small storage only (no
new pumped hydro or CAES)
• 1500 MW CPUC small storage only (no
new pumped hydro or CAES)
Local generation
constraints
• SCIT nomogram29
• 60/40 and 75/25 SoCal local generation
rules30
• SCIT nomogram
• Former 60/40 and 75/25 SoCal local
generation rules
29
A nomogram is currently used to determine allowable imports into southern California over the Southern California Import
Transmission (SCIT). This is based on levels of in-basin inertia and required to maintain import capability, as described on page
15 of Assessment of Electrical System Reliability Needs in South Coast Air Basin and Recommendations on Meeting those Needs
(Interagency AB 1318 Technical Team, 2011, link)
30 Until late 2013, CAISO enforced an import limit of 40% and 25% of generation in SCE and SDG&E territories, respectively.
These were enforced in E3’s model and were included here both to demonstrate modeling results under a less flexible system and
to act as a placeholder for any other rule that might replace the 60/40 and 75/25 rules.
13
VII. Assumptions for revenue requirement analysis
The economic analysis to find the net revenue requirement associated with the Target Case was carried
out as follows. All costs and savings were calculated relative to the Baseline Case (this study’s “business
as usual” case) and only took into account the difference in costs and savings that affect utility revenue
requirement.
1) The net cost of implementing the Target Case was calculated (see Workpapers Supplements 2 and
3 for details).
 To calculate the net cost:
1. Total capital investment in the infrastructure added in the Target Case was
identified. An annual cost to fund these investments, or “levelized fixed cost”
(LFC), was calculated using a spreadsheet tool developed by E3 for WECC
(Workpapers Supplement 2).
2. This annualized cost was added to other annual costs associated with the Target
Case, such as fixed O&M costs for additional infrastructure, increased annual
utility costs for EE and DR programs, and the difference in capacity payments
for DR programs and the gas fleet.
3. Savings in the Target Case were calculated by summing the savings in fuel,
variable O&M, and carbon credit costs in the Target Case.
4. The net revenue requirement associated with the Target Case was calculated as
the Target Case savings subtracted from the Target Case costs.
 Utility ratepayer-funded programs and expenditures for EE and DR, but no customerfunded direct expenditures, were considered.
2) This net utility revenue requirement was divided by the number of delivered wholesale MWh in
2030 to find the approximate rate impact of implementing the Target Case, in $/MWh.
3) The net cost of emissions reductions ($/MT) in the Target Case was found by dividing the total
revenue requirement by the metric tons (MT) of carbon reduced between the Baseline and Target
Cases. The total cost of carbon emissions was calculated as the sum of the projected price of
carbon emissions and the cost of emissions reductions.
The following assumptions were used for these calculations:
Capital cost of generators, bulk energy storage, and transmission
 Capital and fixed O&M costs were based on E3’s recommendations to WECC’s 2014 studies31
o Assumed weighted average installation year for capital cost estimation was 2025
o Some modifications were made to these assumptions where appropriate32
Levelized fixed cost (LFC)
 The LFC associated with the Target Case investments was calculated using a spreadsheet tool
developed for WECC by E3.33
o Most default assumptions in this tool were used. Exceptions are listed below.
Capital Cost Review of Power Generation Technologies Recommendations for WECC’s 10- and 20-Year Studies includes
recommendation for capital costs and fixed O&M costs for each technology, state multipliers to account for labor and material
costs in each state, and learning curves for emerging technologies (E3, 2014, link)
32 See LCGS Workpapers Supplement 3 for all capital cost assumptions
33 E3’s Electric Generation Costing Tool (link, also Workpapers Supplement 2) was used to annualize capital costs of Target and
Baseline Cases. This tool calculated an LFC rate for each technology, which was applied to the total capital cost of that
technology to find the annual cost of buildout. See LCGS Workpapers Supplement 2 and 3 for further detail.
31
14

The weighted average cost of capital (WACC) was changed. E3’s default varies by technology
and averages to 7.3%. The CEC’s assumptions vary by technology and averages to about 6.6%.34
In this analysis, assumptions were selected such that the WACC was 7.0% for all technologies.
 Other important assumptions include:
o The production tax credit (PTC) and investment tax credit (ITC) were implemented as
currently in statute. By 2030, the PTC is set to expire and the ITC is set to be at 10%.35
o All generation was contracted under independent power producer PPAs; all incremental
pumped hydro storage was financed with an IOU ratebase; the CAES project and the
Baseline Case CC were financed with a POU ratebase; all transmission was financed with
a FERC rate recovery.
o State tax rate (under “Assumptions” tab) was updated to current value.
Other assumptions36
 There has been discussion related to potential net costs or savings related to the expansion of
customer-sited PV. These costs or savings would be associated with a cost to upgrade the
distribution system or a benefit manifested in deferred upgrades, etc. This analysis assumed that,
if there is a net cost or savings associated with the expansion of customer-sited PV, it is recovered
or distributed via a fixed charge to PV customers and does not affect the general ratebase. No
attempt was made to determine or attribute net costs of any distribution system expenditures to
other customer-side investments.
 Financing of EE and DR programs was calculated using costs similar to those of today’s
programs.37
 Capacity payments assumed to be $40/kW-yr,38 which is above estimated current market value,
but substantially below cost of new entry
 Natural gas price assumed to be ~$6.15/MMBtu,39 based on the Energy Information
Administration’s (EIA) Annual Energy Outlook reference case, adjusted to California using
TEPPC methodology
 Carbon price assumed to be ~$31.41/MMT40from CEC’s 2013 Natural Gas Issues, Trends, and
Outlook low case
See Table 7 in Chapter 2 of the CEC’s Estimated Cost of New Renewable and Fossil Generation in California (2014, link),
which provides estimates for technology-specific WACC for projects built over the next 10 years.
35 The PTC expired at the end of 2013 (DSIRE, link) and the ITC is set to decrease to 10% at the end of 2016 (DSIRE, link).
36 Other calculations relevant to the revenue requirement impact analysis can be found in APPENDIX C: Calculations associated
with revenue requirement impact analysis.
37 For calculation of EE program costs, see “Energy efficiency programs” tab of LCGS Workpapers Supplement 3. These are
based on current reported program costs (link and link).
38 In 2011, the average RA/capacity only price was $26.40/kW-yr, according to a 2013 CPUC analysis (p. 16, link). CPUC
estimates of the cost of new entry are $136/kW-yr (p. 20, link).
39 The natural gas price forecast used EIA’s Henry Hub reference case (link), with TEPPC methodology applied to adjust for the
gas moving from Henry Hub to California cities. TEPPC’s methodology is described on p.71 of WECC’s 2013 Interconnectionwide Plan Data and Assumptions (link) and implemented in a spreadsheet tool (link), with latest EIA and SEDS data.
40 Extrapolated low energy consumption scenario of Appendix E of CEC’s 2013 Natural Gas Issues, Trends, and Outlook (link).
34
15
VIII. APPENDIX A: Load forecast calculations
Load
Load forecast in the LCGS was based off of the CEC’s California Energy Demand 2014-2024 Final
Forecast,41 extrapolated to 2030 and with some adjustment, listed below. The “mid” baseline demand
scenario has been jointly adopted42 for use in the CPUC’s 2014 Long Term Procurement Plan and the
CAISO’s 2014-2015 Transmission Planning Process, and this case was used in all LCGS cases.
Steps taken to modify the CEC’s forecast are listed here. See Workpapers Supplement 1 for
details of the projections (section numbers in spreadsheet correspond to list item numbers here).
1) Find total projected "mid" case load: CEC projection for “mid” baseline demand scenario
including demand served by self-generation and losses was found.
2) Remove load due to EVs and HSR: EV and high speed rail load43 from the “mid” case
projections were subtracted from the demand forecast and the load less EV and HSR was
extrapolated to 2030. This was necessary to project more aggressive electrification than assumed
in the “mid” case and allowed for the insertion of load from accelerated vehicle electrification
and the 2029 HSR segment into the load projection.44
3) Calculate load due to aggressive vehicle electrification and the HSR segment scheduled to
come online in 2029: EV load from “high” baseline was extrapolated to implement aggressive
vehicle implementation. This gave about 12.6 TWh of EV load in 2030, which is approximately
equivalent to 4.25 million EVs on the road and exceeds the Governor’s goal for zero emission
vehicles in California.45 The segment of the HSR scheduled to come online in 2029 was estimated
to be 5,380 GWh.46
4) Find total projected load: The result of step 2 was added to the aggressive EV load and 2029
HSR segment to find total load in 2030.
Incremental energy efficiency
To find a net load projection, incremental EE is subtracted from total projected load. Energy efficiency
projections were found by summing projections of EE in IOU service territories and POU service
territories.
 IOU energy efficiency: The CEC’s energy demand forecasts include both baseline load
forecasts, which include all committed and paid for energy efficiency, and forecasts of additional
achievable energy efficiency (AAEE), which are projections of energy efficiency that has not yet
been committed or paid for, but is “reasonably likely to occur” in the CAISO footprint. Five
AAEE scenarios are projected in the CEC’s Energy Demand Forecast. In the jointly adopted
planning assumptions referred to above, the “mid” AAEE scenario was selected for use in the
jointly adopted “Trajectory” scenario in CPUC, CEC, and CAISO planning. The “high mid”
AAEE scenario was selected for use in the “Expanded preferred resources” scenario.
o For the LCGS, the “mid” AAEE scenario was used in the Baseline Case and the “high
mid” AAEE scenario was used in the Target and Accelerated Cases; both were
extrapolated to 2030.
See CEC’s documentation on the forecast (link).
The attachment to Picker’s ruling Planning Assumptions and Scenarios for use in the CPUC Rulemaking R.13-12-010 (The
2014 Long-Term Procurement Plan Proceeding), and the CAISO 2014-15 Transmission Planning Process contains details of the
jointly adopted planning scenarios (link).
43 Projections for HSR load on p. 47 of California Energy Demand 2014-2024 Final Forecast Volume 1: Statewide Electricity
Demand, End-User Natural Gas Demand, and Energy Efficiency.
44 EV load was distributed geographically based on work done by NREL for the CEC (link).
45 The Governor’s executive order EO B-6-2012 calls for 1.5 million zero emission vehicles to be on the roads in California by
2025, with market share expanding (link).
46 See p. 3.6-45 of “Public Utilities and Energy” section of the Environmental Impact Report (EIR) for the Merced-Fresno section
of the HSR, which includes electric load estimates for the entire system (link). The full EIR can be found here (link).
41
42
16

POU energy efficiency: Incremental EE in POU service territories is forecast in a CPUC
spreadsheet tool, 47 based on projections of POU incremental EE reported to the CEC.48 As only
one incremental EE scenario was given for POU territories, the same level of EE in POU service
territories was assumed for all LCGS cases.
Table 8: Net load projections in 2030 and growth rate, 2014-2030
Total load
(2030)
379.8 TWh
Baseline
Target/Accelerated 379.8 TWh
Incremental EE
(2030)
38 TWh
58 TWh
Net load
(2030)
341 TWh
321 TWh
Load growth rate
(2014-2030)
0.74% per year
0.36% per year
Figure 3: Net load in Baseline and Target/Accelerated Cases
47
48
See Scenario Tool 2014 in Excel v2 (link).
A description of this is on p.13 of attachment describing jointly adopted planning assumptions, referred to above (link).
17
IX.
APPENDIX B: Renewable net short for portfolio construction
In order to construct portfolios that would meet the LCGS emissions target of 47 MMT in 2030, it was
necessary to estimate the total energy that needed to come from zero-emissions sources. This was done
using the following steps. Note: the values of energy generation from various sources listed here are not
the values used in the production cost modeling, but were used for purposes of estimating the size of the
renewables portfolio necessary to meet the LCGS’s carbon targets in 2030.
1) Estimate energy that will come from hydro and nuclear sources in 2030: Hydro and nuclear
power are two sources of energy that could be assumed to stay on the system to 2030.
 Hydro: It was assumed that hydropower will continue at approximately historical levels.
Based on total system power data from the CEC’s Energy Almanac,49 about 37 TWh
have been produced from small and large hydro to serve load in California.
 Nuclear: The LCGS modeling assumes that Diablo Canyon Power Plant is retired when
up for license renewal in 2024. The remaining source of nuclear power committed for
California load comes from California utilities’ share of the generation of Pale Verde
Nuclear Generating Station in Arizona, about 8.7 TWh annually.50
2) Based on emissions target, estimate maximum gas burn in 2030: All coal plants specifically
serving California load are assumed to be retired by 2030. To achieve the emissions target of 47
MMT in 2030, only a limited amount of energy from gas-fired facilities could be allowed to serve
load in California. Assuming an emissions rate of 0.45 MT/MWh51 for natural gas, the total gas
burn could not exceed:
(47 MMT)/(0.45 MT/MWh) = 104 TWh
3) Estimate renewable net short: The net load in the Target/Accelerated Cases was 321 TWh. To
find the total zero carbon energy that needed in 2030, expected energy from hydropower, nuclear
power, and gas burn was subtracted from net load:
321 TWh(net load) – 37 TWh(hydro) – 8.7 TWh(nuclear) – 104 TWh(gas) = 171 TWh(zero carbon)
This study assumed that current policies and procurement trends would dictate renewables
procurement until 2020. Therefore, the 2020 renewables portfolio was assumed to be set by the
2012 LTPP, which includes about 89 TWh of renewable energy.52 Current trends in rooftop solar
procurement set rooftop solar numbers around 10 TWh in 2020.53 This leaves:
171 TWh(zero carbon energy needed, 2030) – 89 TWh(renewable energy, 2020) – 10 TWh(rooftop solar, 2020) ≈70 TWh
of renewable energy to be procured between 2020 and 2030 to meet the LCGS’s 2030 emissions
goal. This “renewable net short” of 70 TWh was the basis for developing the Target Case, which
was constructed to meet the emissions reduction target of 50% below 2012 levels in 2030. Both
to ensure that options were available if this case did not meet the target and to test whether
emissions could be reduced further, the Accelerated Case (~50% more incremental renewable
energy than in the Target Case) was developed to provide a snapshot of the system with even
deeper reductions.
\
CEC Energy Almanac’s data on total system power (link). Estimates for the purpose of this calculated are based on data from
years 2007-2012, because 2013 data was not available at the time of this calculation.
50 California utilities own 27.4% of Palo Verde’s generation (link), broken down as follows: SCE: 15.8%, Southern California
Public Power Authority: 5.9%, LADWP: 5.7%.
51 Based on 2007 CPUC documentation for greenhouse gas reporting protocol (link).
52 Energy and capacity numbers from the 2012 LTPP portfolio can be found in Tables 2 and 3 of Estimating the Value to UtilityScale Solar Technologies in California Under a 40% Renewable Portfolio Standard (NREL, 2014 link).
53 See Figure 5 of E3’s Net Energy Metering Ratepayer Impacts analysis for the CPUC (link).
49
18
X.
APPENDIX C: Calculations associated with revenue requirement
impact analysis
Table 9: Production Cost Savings in billions of $ (corresponds to Slide 22 of NREL’s deck)
Annual Cost
($Millions)
Baseline
Target
Accelerated
CA Emissions
Cost
1,967
1,297
1,177
CA Imp
Emissions
371
95
5
Fuel Cost
17,641
13,407
12,522
Startup/
Shutdown Cost
1,726
1,392
1,307
VO&M Cost
1,320
1,283
1,272
Based on Table 9: Savings in Target Case relative to Baseline Case:
Fuel: 17,641 – 13,407 = 4,234 $M/yr
VOM + startup/shutdown: (1,320 – 1,283) + (1,726 – 1,392) = 611 $M/yr
Emissions: CA: (1,967 – 1,297) = 611 $M/yr
OOS: (371 – 95) = 276 $M/yr
Gas capacity payments based on data in Slide 31
The difference between capacity payments in each case was estimated as the difference between
payments at the hour of maximum gas dispatch each year. Because less power is used from the gas fleet
in the Target Case, this results in a savings when compared to the Baseline Case:
Max gas dispatch in Target Case = 26.8 GW (Aug 12)
Max gas dispatch in Baseline Case = 29.9 GW (Aug 12)
Difference in max. gas dispatch between cases, converted to kW and multiplied by $40/kW-yr to
find difference in capacity payments to gas fleet:
(29.9 – 26.8)GW x (1000)2 kW/GW x $40/kw-yr = $124 M
Demand response customer payments based on data in Slide 20
Similarly, demand response capacity payments were estimated as payment for the maximum utilization in
each year. Because more demand response is used in the Target Case, this results in an additional cost
when compared to the Baseline Case.
$40/kw-yr x 1000 x 7300 MW x 0.5 = -$192 M
Savings associated with carbon reductions in the Target Case, based on data from Slide 37 (NREL)
and Slide 2 (Rev. Requ. Slides):
The savings associated with carbon reductions are equal to the total savings associated with the Target
Case divided by the total emissions reductions in the Target Case (relative to the Baseline):
Savings: (5,300 – 5,600)$M/(78.4 – 39.5)MMT = ~ $5/T
19