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W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C OU N C I L
PC19 High DG - WECC Study Results
July 23, 2015
2
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C OU N C I L
Overview
Scope
• Scope• Key Questions
Assumptions
• E3 Assumptions• Geographic
Variations• Capacity Added
for Study
Results
• Generation Change
• Dump Energy• Path Flows
Production Cost Model
3
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C OU N C I L
PC19 High DG WECC• Study Requestor: SPSC
• Changes from 2024CC:– Increased DG generation throughout all of the Western Interconnection.
Noting impacts on west-wide energy dispatch and indicators of stress on the supply system; Increase in capacity by 22,648 MW
*Note in this study analysis DG refers to small scale solar PV or “rooftop solar” for individual retail customers
• Key Questions:– How does the system respond to the additional DG? (i.e. over-generation,
dump energy)– How does the DG “injection” impact transmission flow and path utilization
throughout the region and on the interties?
*No changes were made to transmission or load
4
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C OU N C I L
DG Starting Point (E3)*
• E3 analysis focuses on small scale solar PV installations by retail customers
– Does not include “wholesale DG” that a utility might procure to meet state DG targets
• Market-Driven DG Model Key Drivers:• Solar PV capital cost• Customer bill savings• Federal investment tax credit• State-specific incentive programs• State net energy metering caps• Utility system interconnection potential
Affect customer decisionto invest in solar PV
Limit total penetrationOn a utility’s system
*Source: E3
5
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C OU N C I L
DG Assumtions (E3)*
• Assumption Overview:• High DG projections are developed by relaxing existing Net Energy Metering
(NEM) caps and assuming achievement of aspirational solar PV cost reductions
• Key Assumptions:• Assumes Net Energy Metering (NEM) caps are removed, allowing installations
of DG in each utility’s service territory up to its “Interconnection Potential• No change in retail rate design
– California Exception: After 2017 exports are assumed to be compensated at avoided cost
• Retail rates escalate at 0.5% per year in real terms• Federal ITC sunsets in 2017
– Credit reduces to 10% of capital costs thereafter• Current state inventive programs sunset after current NEM cap is exceeded
*Source: E3
6
2024 High DG Projections
Total capacity: 22,648 MW
Load Area
Distributed PV Capacity
(MW)Peak Load
(MW)Capacity
(% of Peak)AESO - 16,370 0.0%APS 1,548 8,512 18.2%AVA 129 2,571 5.0%BCHA - 11,603 0.0%BPA 394 12,023 3.3%CFE - 2,753 0.0%CHPD 18 803 2.3%DOPD 13 500 2.6%EPE 70 2,346 3.0%FAR EAST 34 420 8.2%GCPD 14 1,029 1.4%IID 74 1,198 6.2%LDWP 1,032 5,826 17.7%MAGIC VLY 75 884 8.5%NEVP 747 4,937 15.1%NWMT 207 2,324 8.9%PACE_ID 49 878 5.5%PACE_UT 576 5,642 10.2%PACE_WY 141 1,829 7.7%PACW 263 4,387 6.0%
Load Area
Distributed PV Capacity
(MW)Peak Load
(MW)Capacity
(% of Peak)PG&E_BAY 2,234 12,792 17.5%PG&E_VLY 2,813 12,517 22.5%PGN 441 4,828 9.1%PNM 490 3,472 14.1%PSC 1,645 7,235 22.7%PSE 204 5,222 3.9%SCE 4,534 23,779 19.1%SCL 57 2,709 2.1%SDGE 933 4,520 20.6%SMUD 495 3,206 15.4%SPP 322 3,603 8.9%SRP 1,240 8,484 14.6%TEP 434 4,151 10.5%TIDC 117 603 19.5%TPWR 19 1,137 1.7%TREAS VLY 153 1,924 7.9%WACM 821 5,529 14.8%WALC 294 2,460 12.0%WAUW 19 152 12.2%
7
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C OU N C I L
Generation Change
Conventional Hydro
Energy Storage
Steam - Coal
Steam - Other
Nuclear
Combined Cycle
Combustion Turbine
IC
Other
DG/DR/EE - Incremental
Biomass RPS
Geothermal
Small Hydro RPS
Solar
Wind
0 50,000,000 100,000,000 150,000,000 200,000,000 250,000,000 300,000,000
Annual Generation by Category (MWh)2024 PC19 High DG WECC 2024 PC1 v1.5
8
Production Cost and CO2Category 2024 PC1 15-01-19 2024 PC 19 High DG WECC Difference
Conventional Hydro 238,955,786 238,935,910 -19,876Energy Storage 3,592,412 3,344,337 -248,076Steam 230,393,384 212,095,530 -18,298,043Nuclear 56,254,786 56,206,670 -48,116Combined Cycle 278,957,656 254,970,479 -23,987,178Combustion Turbine 51,794,128 48,872,363 -2,921,765IC 818,909 655,300 -163,609DG/DR/EE - Incremental 17,916,707 65,404,109 47,487,402Biomass RPS 19,581,287 19,034,598 -546,689Geothermal 31,937,139 31,523,705 -413,434Small Hydro RPS 4,360,054 4,351,069 -8,985Solar 38,182,163 35,734,009 -2,448,153Wind 74,232,546 73,783,251 -449,295== Total == 1,050,342,237 1,048,276,420 -2,065,817
Cost (M$) 22,843 21,477 (1,366)CO2 Cost (M$) 1,730 1,613 (116)CO2 Amount (MMetrTn) 363 336 (26)Dump Energy (MWh) 357,799 3,499,883 3,142,084 Pumping (PL+PS) (MWh) 15,426,008 15,104,430 (321,579)
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C O U N C I L
9
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C OU N C I L
Changes in Total Annual Generation
Conventional Hydro
Energy Storage
Steam - Coal
Steam - Other
Nuclear
Combined Cycle
Combustion Turbine
IC
Other
DG/DR/EE - Incremental
Biomass RPS
Geothermal
Small Hydro RPS
Solar
Wind
(30,000,000) (20,000,000) (10,000,000) 0 10,000,000 20,000,000 30,000,000 40,000,000 50,000,000 60,000,000
Annual Energy Difference (MWh): 2024 PC1 v1.5 vs 2024 PC19 High DG WECC
10
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C OU N C I L
Generation Change By State
AB AZ BC CA CO ID MT MX NE NM NV OR SD TX UT WA WY-10,000,000
-5,000,000
0
5,000,000
10,000,000
15,000,000
20,000,000
25,000,000
30,000,000
Annual Gen Change (GWh) 2024 PC1 v1.5 vs 2024 PC19 High DG WECC
Conventional HydroEnergy StorageSteam - CoalSteam - OtherNuclearCombined CycleCombustion TurbineICOtherBiomass RPSDG/DR/EE - IncrementalGeothermalSmall Hydro RPSSolarWind
IGS as-signed to
UT
11
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C OU N C I L
Generation Change by Subregion
Alberta
British Columbia
Basin
California
Desert Southwest
Northwest
Rocky Mountain
-10,000,000 -5,000,000 0 5,000,000 10,000,000 15,000,000 20,000,000 25,000,000 30,000,000
Change (GWh) by Subregion - 2024 PC1 v1.5 vs. 2024 PC19 High DG WECC
WindSolarSmall Hydro RPSGeothermalDG/DR/EE - IncrementalBiomass RPSOtherICCombustion TurbineCombined CycleNuclearSteam - OtherSteam - CoalEnergy StorageConventional Hydro
IGS assigned to CA
12
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C OU N C I L
Dump Energy
0 AB AZ BC CA CO ID MT MX NE NM NV OR SD TX UT WA WY (blank)
-500000
0
500000
1000000
1500000
2000000
2500000
171,852
2,185,696
0 228 090,328
0 0 0
Biomass RPS Combined Cycle Combustion Turbine Conventional Hydro DG/DR/EE - IncrementalEnergy Storage Geothermal IC Nuclear OtherPumping Load Small Hydro RPS Solar Steam - Coal Steam - Otherunknown Wind (blank)
13
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C OU N C I L
Modeling Constraints
Constraints Name TypeCosts (K$)
Duration(Hrs) CC
Duration (Hrs) PC19 FromBusName FromBusID ToBusName ToBusID
MAGUNDEN-OMAR 230 kV line #1 Branch 26,238 5,741 4,418 MAGUNDEN 24087 OMAR 24101
MAMMOTH-BIG CRK3 230 kV line #1 Branch 8,515 106 1,476 MAMMOTH 24316 BIG CRK3 24303
REDBUTTE-UTAH-NEV 345 kV line #1 Branch 7,706 965 2,500 REDBUTTE 66280 UTAH-NEV 67657
CAL SUB 120/120 kV transformer #1 Branch 2,181 964 1,072 CAL SUB 64025 CAL S PS 64023
BLKGLADW 115/115 kV transformer #1 Branch 2,083 2,252 2,807 BLKGLADW 72771 BLKDPSW 72773
P60 Inyo-Control 115 kV Tie Interface 1,111 2,602 1,019
PG&E Bay 25% LocalMinGen Nomogram 0 511 1,043
LDWP 25% LocalMinGen Nomogram 0 3,859 5,079
SCE 25% LocalMinGen Nomogram 30,401 5,127 5,566
14
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C OU N C I L
Nomograms• Nomogram: – Constraint (inequality) enforced by GV– When “at limit”, additional thermal generation is
dispatched to balance the inequality• 4 new nomograms to 2024 CC:– LDWP 25% LocalMinGen– PG&E Bay 25% LocalMinGen– SCE 25% LocalMinGen– SDGE 25% LocalMinGen
15
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C OU N C I L
Nomogram Constraint PC19 vs CC
9 369 729 1089 1449 1809 2169 2529 2889 3249 3609 3969 4329 4689 5049 5409 5769 6129 6489 6849 7209 7569 7929 8289 8649
-4000
-3500
-3000
-2500
-2000
-1500
-1000
-500
0
500
1000
PG&E Bay 25% LocalMinGenPG&E Bay 25% CCLDWP 25% LocalMinGenLDWP 25% CCSCE 25% LocalMinGenSCE 25% CC
16
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C OU N C I L
Difference in Duration (Hrs)Br
anch
Bran
ch
Bran
ch
Bran
ch
Bran
ch
Inte
rfac
e
Nom
ogra
m
Nom
ogra
m
Nom
ogra
m
MAGUNDEN-OMAR 230 kV
line #1
MAMMOTH-BIG CRK3 230 kV
line #1
REDBUTTE-UTAH-NEV 345
kV line #1
CAL SUB 120/120 kV
transformer #1
BLKGLADW 115/115 kV
transformer #1
P60 Inyo-Con-trol 115 kV Tie
PG&E Bay 25% LocalMinGen
LDWP 25% LocalMinGen
SCE 25% LocalMin-
Gen
-1500
-1000
-500
0
500
1000
1500
2000
Difference in Modeling Constraints PC19 vs CommonCase
Dura
tion
(Hrs
)
17
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C OU N C I L
Results – Most Heavily Utilized Paths• Congestion vs Utilization– Some lines are designed to be congested
• “Most Heavily Utilized” = A path that meets any one of the following criterion (10-year plan utilization screening):– U75 > 50%– U90 > 20%– U99 > 5%
• Uxx = % of year that flow is greater than xx% of the path limit
18
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C OU N C I L
Results – Changes in Transmission Utilization
P45 SDG&E-CFE
P83 Montana Alberta Tie Line
Most Heavily Utilized Paths
P08 Montana to Northwest
P60 Inyo-Control
P10 West of Colstrip
P01 Alberta-British Columbia
Most Heavily Utilized Paths U75 U90 U99
P10 West of Colstrip 50.50% 0% 0%
P45 SDG&E-CFE 13.31% 10.70% 9.3%
P83 Montana Alberta Tie Line 16.09% 8.67% 5.48%
19
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C OU N C I L
Results Common Case
0%
10%
20%
30%
40%
50%
60%
70%
80%
Most Heavily Utilized Paths - PC1_1_5 U75 U90 U99
Perc
ent o
f Hou
rs
20
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C OU N C I L
Results PC19
-P60 Inyo
-Control 1
15 kV Tie
-P52 Silve
r Peak-
Control 5
5 kV
-P45 SDG&E-C
FE
-P83 Montan
a Alberta
Tie Lin
e
xy WA-BC Ea
st
P26 Northern-So
uthern California
P32 Pavant-G
onder InterM
tn-Gonder 230 kV
-P61 Lugo
-Victorvi
lle 500 kV
Line
P66 COI
P18 Montan
a-Idah
o
P15 Midway-
LosBanos
P31 TOT 2
A
P48 Northern New M
exico (N
M2)
-P28 Interm
ountain-M
ona 345 kV
-xy AB-M
T0%
10%
20%
30%
40%
50%
60%
Most Heavily Utilized Paths - PC19 High DG - WECCU75 U90 U99
Perc
ent o
f Hou
rs
21
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C OU N C I L
Path Flows
-1000
-800
-600
-400
-200
0
200
400
600
WECC P45 SDG&E-CFE
2024CC-V1.5 2024-PC19 High DG 2012 2024 Max 2024 Min
Meg
awatt
s
N -> S
-3000
-2000
-1000
0
1000
2000
3000
WECC P10 West of Colstrip
2024CC-V1.5 2024 PC19 High DG 2012 2024 Max 2024 Min
Meg
awatt
s
N -> S
22
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C OU N C I L
Path Flows
-400-300-200-100
0100200300400500600
WECC P83 Montana Alberta Tie Line
2024CC-V1.5 2024 PC19 High DG 2012 2024 Max 2024 Min
Meg
awatt
s
N -> S
-6000
-4000
-2000
0
2000
4000
6000
WECC P66 COI
2024CC-V1.5 2024-PC19 High DG 2012 2024 Max 2024 Min
Meg
awatt
s
N -> S
23
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C OU N C I L
Findings• Generation and Energy Changes:– Increased DG availability results in a reduction in Coal (steam)
and Combined Cycle generation – Increased levels of dump energy (likely due to modeling
constraints – nomograms, transfer capacity)
• Transmission Changes:– Increased path over-utilization in Southern CA and in the
North-East regions
• Production Cost Changes:– Decrease in production cost– Decrease in CO2 production
24
W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C OU N C I L
Contact Info
Tyson [email protected]
801-819-7657
Distributed Generation Projections for High DG Case
October 10, 2014
Arne Olson, PartnerNick Schlag, Sr. Consultant
26
Background
In a number of past efforts, E3 has worked with LBNL and WECC to establish input assumptions regarding distributed generation in study cycles:• In 2011-12, E3 worked with LBNL and WECC to develop estimates of DG
potential for the SPSC’s 2022 and 2032 High DG/DSM cases• In 2014, E3 & LBNL developed an approach to project “market-driven”
distributed generation in the WECC, which was used to inform the 2024 Common Case
WECC has requested projections of distributed generation consistent with High DG futures for the Western Interconnection to use in the SPSC’s 2024 and 2034 High DG/DSM casesTo develop these projections, E3 has used logic from both prior efforts to assess future DG installations
27
Defining “Distributed Generation”
“Distributed” generation means different things to different people:• Behind-the-meter, e.g., customer-owned resource• Small utility or IPP owned resource that is connected at the distribution system and serves
load downstream• Small resource that is connected at the distribution system and does not serve load
downstream• Small resource that is connected to the sub-transmission system (i.e., low-voltage
transmission) near load• Small resource that is located remote from load• Large resource that is located in load pocket and helps defer or avoid transmission
investmentsThis analysis focuses on small scale solar PV installations that individual retail customers would install to avoid purchasing electricity from an electric utility
• Does not include “wholesale DG” that a utility might procure to meet state DG targets
28
Approaches to Developing High DG Assumptions
2022/2032 High DG Case assumptions developed in two steps:• Estimate interconnection potential for each state• Make state-specific adjustments to interconnection potential
to reflect differences in economic drivers of DG2024/2034 High DG Case assumptions derived by modeling customer decisions under a scenario favorable to distributed generation adoption• Use E3’s Market Driven DG Model to develop projections
of adoption• Rely on estimates of interconnection potential as an upper
bound
MODELING MARKET-DRIVEN DG
30
Channels for Distributed Solar PV Adoption
Background
In prior transmission planning study cycles, WECC has incorporated distributed solar PV assumptions consistent with state policy goalsThis framework ignores the potential for market-driven DG• With low PV costs, this could become a large amount of capacity
E3 and LBNL have developed a framework to incorporate market-driven DG into transmission planning studies
Program Goals(e.g. California Solar Initiative)
RPS Set-Asides(e.g. 30% DG set-aside in Arizona)
Market-Driven Adoption
Policy-driven DG, modeled in past WECC studies
New to WECC studies
31
E3’s Market Driven DG Model
To provide inputs for WECC’s transmission planning studies, E3 has developed a model of DG deployment throughout the WECC footprint between present day and 2040• Joint funding from WECC and LBNL through DOE’s ARRA grants
Input assumptions capture geographic variations in PV cost-effectiveness and state policy• State-specific PV costs• State-specific net metering policy• Capacity factors at a BA level• Utility-specific retail rates (and incentives where applicable)
The model also captures the changing cost-effectiveness of PV:• Continued declines in PV capital costs• Expiration of incentives & tax credits (e.g. ITC in 2017)• Escalation of retail rates• Expected changes to state net metering policies (e.g. California AB 327)
32
2024 Common Case Recommendations
The Market-Driven DG Model used to develop preliminary recommendations for customer-sited solar for the 2024 Common Case
2024Market Peak Market
Driven DG Load Driven DGState (MW) (MW) (% of Peak)
Arizona 1,751 23,227 7.5%California 5,742 68,908 8.3%Colorado 742 11,789 6.3%Idaho 51 5,664 0.9%Montana 35 2,483 1.4%New Mexico 170 5,139 3.3%Nevada 241 9,951 2.4%Oregon 191 10,392 1.8%Utah 106 5,537 1.9%Washington 90 20,950 0.4%Wyoming 47 3,464 1.4%
Total 9,166 167,505 5.5%
For the 2024 Common Case, TAS adjusted the recommended
values (shown at left) downward by 20%
HIGH DG CASE RECOMMENDATIONS
34
Key Drivers of Market Driven DG Model
The main drivers of the modeled customer adoption of solar PV are:
1. Solar PV capital cost2. Customer bill savings3. Federal investment tax credit4. State-specific incentive programs5. State net energy metering caps6. Utility system interconnection potential
Changing the assumptions for each of these parameters provides the basis for exploring alternative projections
Affect customer decision to invest in solar PV
Limit total penetration on a utility’s system
35
High DG projections are developed by relaxing existing NEM caps and assuming achievement of aspirational solar PV cost reductions
Overview of Assumptions
Assumption Reference Case High DG Case
Net Metering CapsCurrent Policy• Current NEM caps remain in
place• California cap lifted after 2016
NEM Caps Removed• All NEM caps lifted• Limits associated with
interconnection potential enforced
Solar PV Cost TrendsModerate Reductions• Cost trajectory derived by E3
for TEPPC planning studies
Aspirational Reductions• Sunshot goals achieved by
2020
36
Treatment of NEM Caps
In the Reference Case, each state’s NEM cap was enforced according to current policy
High DG case assumes current NEM caps are removed, allowing installations of DG in each utility’s service territory up to its ‘Interconnection Potential’
State Current NEM CapArizona n/a
CaliforniaLimits under current NEM rate design established by AB327 (approximately 5% of non-coincident peak); beyond 2017, alternative rate designs will be considered with no associated cap
Colorado n/aIdaho n/aNew Mexico n/aNevada 3% of utility peakOregon 0.5% of peak for munis, coops, & PUDs; no cap for IOUsUtah 0.1% of peak for munis; 20% of peak for IOUsWashington 0.5% of peakWyoming n/a
37
6,638
11,668
15,336
0
5,000
10,000
15,000
20,000
Rule 21 30% Rule Max w/oCurtailment
Incr
emen
tal P
V Po
tenti
al (M
W)
Residential Rooftop Commercial Rooftop
Ground Mounted
Interconnection Potential Background
To estimate interconnection potential across the WECC, E3 leveraged results from a 2012 analysis, Technical Potential for Local Distributed Photovoltaics in California
Study produced estimates of the amount of “local” distributed PV (LDPV) potential under different interconnection standards in California:
1. Rule 21 (Current Policy): sum of rated capacity of interconnections on a feeder may not exceed 15% of the feeder’s peak load
2. 30% Rule: same as (1), but with constraint relaxed to 30%
3. Max w/o Curtailment: the maximum capacity that can be installed on a feeder for which all generation will serve load on that feeder (e.g. no required backflow or curtailment)
In 2012 study cycle, E3 generalized these results to the WECC BAs; the same method is used to determine limits in this study cycle
• 30% Rule for 2024 High DG projections• Max w/o Curtailment for 2034 High DG
projections
38
Capital Cost Trajectories
Reference case cost reduction trajectory derived through application of learning curve approach• 20% learning rate on
modules; 15% on BOS• IEA medium-term
renewable energy outlook• Adopted by TEPPC
Aspirational case cost reduction trajectory assumes achievement of Sunshot goals by 2020• $1.50/W residential• $1.25/W commercial
$4.11$3.23 $2.83
$1.50 $1.50$0
$2
$4
$6
$8
2010 2014 2018 2022 2026 2030 2034
Residential Costs (2013 $/W-dc)
Reference
Aspirational
$3.54$2.80 $2.45
$1.25 $1.25$0
$2
$4
$6
$8
2010 2014 2018 2022 2026 2030 2034
Commercial Costs (2013 $/W-dc)
Reference
Aspirational
39
Other Key Assumptions
No changes in retail rate design• Surplus NEM generation is compensated at full retail rate• EXCEPTION: in California, after 2017, exports are assumed to be
compensated at avoided cost (see Slide 30)Retail rates escalate at 0.5% per year in real termsFederal ITC sunsets in 2017• Credit reduces to 10% of capital costs thereafter
Current state incentive programs sunset after current NEM cap is exceeded• e.g. Washington & Oregon (see Slide 31)
40
High DG Case projections
2024 Projections
Reference Case projections
0
5,000
10,000
15,000
20,000
25,000
2012 2014 2016 2018 2020 2022 2024
Inst
alle
d Ca
paci
ty (M
W)
WECC-US2012 - 2024
2024Market Peak Market
Driven DG Load Driven DGState (MW) (MW) (% of Peak)
Arizona 3,533 23,227 15.2%California 12,305 68,908 17.9%Colorado 2,301 11,789 19.5%Idaho 351 5,664 6.2%Montana 249 2,483 10.0%New Mexico 613 5,139 11.9%Nevada 1,023 9,951 10.3%Oregon 812 10,392 7.8%Utah 574 5,537 10.4%Washington 639 20,950 3.1%Wyoming 248 3,464 7.2%
Total 22,648 167,505 13.5%
0
5,000
10,000
15,000
20,000
25,000
2012 2014 2016 2018 2020 2022 2024
Inst
alle
d Ca
paci
ty (M
W)
WECC-US2012 - 2024
2024Market Peak Market
Driven DG Load Driven DGState (MW) (MW) (% of Peak)
Arizona 1,751 23,227 7.5%California 5,742 68,908 8.3%Colorado 742 11,789 6.3%Idaho 51 5,664 0.9%Montana 35 2,483 1.4%New Mexico 170 5,139 3.3%Nevada 241 9,951 2.4%Oregon 191 10,392 1.8%Utah 106 5,537 1.9%Washington 90 20,950 0.4%Wyoming 47 3,464 1.4%
Total 9,166 167,505 5.5%
Incremental Additions
Incremental Additions
41
Comparison to 2022 High DG Recommendations
2022 and 2024 High DG projections have similar quantities of distributed generation capacity, but show a regional shift• Relative increases in California, Colorado• Slight decreases in states in the Pacific Northwest
2022 2024High DG High DG Change
State (MW) (MW) (MW)Arizona 3,650 3,533 (117) California 11,670 12,305 635 Colorado 1,410 2,301 891 Idaho 550 351 (199) Montana 160 249 89 New Mexico 600 613 13 Nevada 1,090 1,023 (67) Oregon 1,240 812 (428) Utah 690 574 (116) Washington 1,090 639 (451) Wyoming 510 248 (262)
Total 22,660 22,648 (12)
Notable decreases from 2022
Notable increases from 2022
42
2034Market Peak Market
Driven DG Load Driven DGState (MW) (MW) (% of Peak)
Arizona 4,495 27,833 16.1%California 17,852 78,325 22.8%Colorado 3,426 12,749 26.9%Idaho 493 6,312 7.8%Montana 345 2,763 12.5%New Mexico 773 5,954 13.0%Nevada 1,274 11,489 11.1%Oregon 1,067 11,794 9.0%Utah 739 5,481 13.5%Washington 852 23,560 3.6%Wyoming 333 3,955 8.4%
Total 31,650 190,215 16.6%
2034Market Peak Market
Driven DG Load Driven DGState (MW) (MW) (% of Peak)
Arizona 2,314 27,833 8.3%California 6,816 78,325 8.7%Colorado 1,133 12,749 8.9%Idaho 93 6,312 1.5%Montana 65 2,763 2.3%New Mexico 251 5,954 4.2%Nevada 307 11,489 2.7%Oregon 234 11,794 2.0%Utah 181 5,481 3.3%Washington 95 23,560 0.4%Wyoming 82 3,955 2.1%
Total 11,570 190,215 6.1%0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034
Inst
alle
d Ca
paci
ty (M
W)
WECC-US2012 - 2034
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034
Inst
alle
d Ca
paci
ty (M
W)
WECC-US2012 - 2034
High DG Case projections
2034 Projections
Reference Case projections
DETAILED PROJECTIONS BY LOAD AREA
44
2024 High DG Projections
Total capacity: 22,648 MW
Load Area
Distributed PV Capacity
(MW)Peak Load
(MW)Capacity
(% of Peak)AESO - 16,370 0.0%APS 1,548 8,512 18.2%AVA 129 2,571 5.0%BCHA - 11,603 0.0%BPA 394 12,023 3.3%CFE - 2,753 0.0%CHPD 18 803 2.3%DOPD 13 500 2.6%EPE 70 2,346 3.0%FAR EAST 34 420 8.2%GCPD 14 1,029 1.4%IID 74 1,198 6.2%LDWP 1,032 5,826 17.7%MAGIC VLY 75 884 8.5%NEVP 747 4,937 15.1%NWMT 207 2,324 8.9%PACE_ID 49 878 5.5%PACE_UT 576 5,642 10.2%PACE_WY 141 1,829 7.7%PACW 263 4,387 6.0%
Load Area
Distributed PV Capacity
(MW)Peak Load
(MW)Capacity
(% of Peak)PG&E_BAY 2,234 12,792 17.5%PG&E_VLY 2,813 12,517 22.5%PGN 441 4,828 9.1%PNM 490 3,472 14.1%PSC 1,645 7,235 22.7%PSE 204 5,222 3.9%SCE 4,534 23,779 19.1%SCL 57 2,709 2.1%SDGE 933 4,520 20.6%SMUD 495 3,206 15.4%SPP 322 3,603 8.9%SRP 1,240 8,484 14.6%TEP 434 4,151 10.5%TIDC 117 603 19.5%TPWR 19 1,137 1.7%TREAS VLY 153 1,924 7.9%WACM 821 5,529 14.8%WALC 294 2,460 12.0%WAUW 19 152 12.2%
45
2034 High DG Projections
Total capacity: 31,650 MW
Load Area
Distributed PV Capacity
(MW)Peak Load
(MW)Capacity
(% of Peak)AESO - 22,683 0.0%APS 1,990 9,715 20.5%AVA 177 2,920 6.1%BCHA - 12,948 0.0%BPA 553 13,930 4.0%CFE - 3,513 0.0%CHPD 27 990 2.7%DOPD 18 638 2.8%EPE 87 2,891 3.0%FAR EAST 49 500 9.7%GCPD 20 1,199 1.6%IID 91 1,449 6.3%LDWP 1,327 6,550 20.3%MAGIC VLY 103 889 11.6%NEVP 925 5,548 16.7%NWMT 282 2,541 11.1%PACE_ID 67 988 6.8%PACE_UT 740 5,523 13.4%PACE_WY 181 1,891 9.5%PACW 347 4,633 7.5%
Load Area
Distributed PV Capacity
(MW)Peak Load
(MW)Capacity
(% of Peak)PG&E_BAY 3,237 14,225 22.8%PG&E_VLY 4,247 14,478 29.3%PGN 571 5,644 10.1%PNM 607 3,679 16.5%PSC 1,965 7,105 27.7%PSE 262 5,602 4.7%SCE 6,605 26,716 24.7%SCL 75 2,852 2.6%SDGE 1,437 5,331 27.0%SMUD 620 3,480 17.8%SPP 422 4,487 9.4%SRP 1,509 10,321 14.6%TEP 513 4,693 10.9%TIDC 174 710 24.5%TPWR 26 1,252 2.1%TREAS VLY 206 2,171 9.5%WACM 1,108 7,136 15.5%WALC 470 3,910 12.0%WAUW 26 172 15.4%
Thank You!Energy and Environmental Economics, Inc. (E3)101 Montgomery Street, Suite 1600San Francisco, CA 94104Tel 415-391-5100Web http://www.ethree.com
MARKET-DRIVEN DG: METHODOLOGY AND ASSUMPTIONS
48
General Model Logic
E3’s Market-Driven DG model combines a customer decision model with policy targets and NEM caps to provide a comprehensive assessment of behind-the-meter solar PV in the Western InterconnectModeling steps:1. Assess potential size of distributed solar PV market based
on economics2. Adjust forecast upward to meet any policy targets3. Limit total installations based on state net metering caps
49
Step 1: Market-Driven Adoption
1. Determine payback period
Payback
-$4,000
-$3,000
-$2,000
-$1,000
$0
$1,000
$2,000
$3,000
$4,000
0 5 10 15
Cum
ulati
ve N
et C
ost (
$)
Years Since Installation
2. Determine max market share
3. Fit logistic curve
t-1t
0%1%2%3%4%5%6%7%8%
0 5 10 15 20 25
Mar
ket P
enet
ratio
n (%
)
Years
4. Apply to technical potential
7%
0%
20%
40%
60%
80%
100%
0 5 10 15 20 25 30 35
Max
imum
Mar
ket S
hare
(%)
Payback Period
Technical potenial MW
x Market penetration at t %
= Installed capacity at t MW
50
Calculating the Payback Period
The payback period is the first year in which a customer who choose to install solar PV will have a net positive cash flowTo determine the payback period, E3 considers:• System capital costs: costs of purchasing & installing a PV system• Operating & maintenance costs: costs of year-to-year maintenance,
including inverter replacement• Federal tax credits: investment tax credit (30% until 2017; 10% thereafter)• State & local incentives: up-front & performance-based incentives, vary by
utility & state• Bill savings: reductions monthly energy bills, vary by utility• Green premium: a non-financial value that a customer derives from having
invested in solar PV (assumed to be 1 cent/kWh)
51
Solar PV Capital Costs by Installation Vintage
Installed PV cost assumptions based on draft recommendations for PV capital costs developed by E3• Presented to TAS on December 19
Future cost reductions primarily reflect lower balance-of-systems costs
Historical
$4.8
$3.6$4.0
$3.0
$0
$1
$2
$3
$4
$5
$6
$7
$8
$9
$10
2010 2012 2014 2016 2018 2020 2022 2024
Inst
alle
d Co
st (2
014
$/W
-dc)
Residential
Commercial
52
Solar PV Costs by State
System average costs are adjusted for each state to capture regional variations in costs• Regional adjustments based on LBNL’s Tracking the Sun VI
$5.1$4.8 $4.6
$4.3 $4.3
$3.7$3.5
$4.2$4.0 $3.9
$3.6 $3.6
$3.1$2.9
$4.8 $4.6 $4.6 $4.6 $4.5
$3.9 $3.8 $3.8 $3.8 $3.7
$0
$1
$2
$3
$4
$5
$6
CA NM WA OR MT ID UT WY NV AZ CO TX
2013
Inst
alle
d Co
sts (
2014
$/W
-dc)
Residential
Commercial
Where Tracking the Sun VI did not report PV costs, costs were interpolated based on the Army Corps of Engineer’s Construction Works Cost Index
53
All WECC states currently allow net metering, under which a customer is compensated for PV output based on its retail rate
• This is the primary economic benefit to a customer who chooses to install distributed PVMarket adoption model includes utility-specific rate information for 30 large utilities in the West (a subset are shown below)
• For other smaller utilities, a state-specific average retail rate is used
$0.00
$0.05
$0.10
$0.15
$0.20
$0.25
$0.30
$0.35
2013
Res
iden
tial R
etai
l Rat
e ($
/kW
h)
Avoided Energy Cost
California: IOUs’ high tiered rates provide strong incentive to
customers
Northwest: Low-cost hydropower keeps
rates lowSouthwest Rocky Mountains
General trend in retail rates
54
Changes to Avoided Energy Cost over Time
E3 assumes that utilities continue to compensate customers at their full retail rate throughout the analysis horizon with one exception• Real escalation of 0.5% per year is assumed
California’s AB 327 directs the CPUC to implement a standard NEM tariff beginning in July 2017As this tariff has not yet been defined, E3 has chosen to model it in the following manner:• All generation consumed on-site is compensated at the customer’s
retail rate• 50% for residential systems, 70% for commercial systems (based on
CPUC NEM study)• All generation exported to the grid is compensated at the utility’s
long-run avoided cost (based on a CCGT)
55
State-Specific Incentives
Payback period is also heavily influenced by state incentive programsE3’s model captures the impact of two large incentive programs:• Renewable Energy Cost Recovery Program (WA)
• Performance-based incentive capped at $5,000 per year• Program ends in 2020
• Residential Energy Tax Credit (OR)• Incentive of $2.1/W-dc, capped at $6,000• Program ends in 2018
Note: incentives linked to specific policy targets (e.g. set-asides, program goals) are not modeled explicitly and are instead accounted for by adjusting market-driven forecast upward to meet policy goals
56
Sample Payback Period Results, 2013 Residential Systems
Payback periods vary widely across the WECC geography as a function of:• System costs• Incentives
• Retail rates• Capacity factors
Utility StateCost
($/W-ac)ITC (%)
Incentive ($/W-ac)
Incentive ($/kWh)
Retail Rate ($/kWh)
Capacity Factor (%)
Payback(yrs)
Arizona Public Service Co AZ 5.06$ 30% -$ -$ 0.13$ 22% 12Pacific Gas & Electric Co CA 6.02$ 30% -$ -$ 0.31$ 20% 7Public Service Co of Colorado CO 4.39$ 30% -$ -$ 0.12$ 20% 13Idaho Power Co ID 5.39$ 30% -$ -$ 0.09$ 19% 20NorthWestern Energy LLC - (MT) MT 5.43$ 30% -$ -$ 0.11$ 17% 19Public Service Co of NM NM 5.66$ 30% -$ -$ 0.13$ 23% 13Nevada Power Co NV 5.06$ 30% -$ -$ 0.12$ 22% 13Portland General Electric Co OR 5.46$ 30% 1.25$ -$ 0.10$ 15% 17PacifiCorp UT 5.39$ 30% -$ -$ 0.11$ 19% 17Puget Sound Energy Inc WA 5.60$ 30% -$ 0.15$ 0.10$ 14% 11
57
Modeling Solar PV Adoption
NREL’s Solar Deployment System (SolarDS) model provides one of the more transparent forecasts of PV adoption:
• “…a geospatially rich, bottom-up, market-penetration model that simulates the potential adoption of photovoltaics (PV) on residential and commercial rooftops in the continental United States through 2030”
Much of the logic used in the Adoption Module has been adapted from SolarDS:
• Maximum market share as a function of payback period• Logistic curves for adoption
Documentation for SolarDS model: http://www.nrel.gov/docs/fy10osti/45832.pdf(Figures taken from this document)
58
Assumed Payback Curves
Payback curves are based on functional forms documented in SolarDS model
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
0 5 10 15 20 25 30
Max
imum
Mar
ket S
hare
(% o
f tec
hnic
al
pote
ntial
)
Payback Period
Res ExistingRes NewCom ExistingCom New
Utility StatePayback
(yrs)
Maximum Market
Share (%)Arizona Public Service Co AZ 12 2.7%Pacific Gas & Electric Co CA 7 12.2%Public Service Co of Colorado CO 13 2.0%Idaho Power Co ID 20 0.2%NorthWestern Energy LLC - (MT) MT 19 0.3%Public Service Co of NM NM 13 2.0%Nevada Power Co NV 13 2.0%Portland General Electric Co OR 15 1.1%PacifiCorp UT 17 0.6%Puget Sound Energy Inc WA 11 3.7%
59
Assumed Technical Potential
E3 calculates technical potential by specifying:1. The percentage of total customers that could feasibly install solar PV (50%
for residential and commercial)2. The representative system size for a typical install (4 kW for residential; 50
kW for commercial)Resulting assumed technical potential aligns well with NREL’s assessment of rooftop PV technical potential on a state level:
Total technical potential is approximately 150 GW in 20100
10
20
30
40
50
60
70
80
AZ CA CO ID MT NM NV OR UT WA WY
Rooft
op P
V Te
chni
cal P
oten
tial
(GW
)
E3 Assumed Technical Potential
NREL Modeled Technical Potential
Source: U.S. Renewable Energy
Technical Potentials: A GIS-
Based Analysis (NREL)
60
Step 2: Policy Adjustments
A large number of states have enacted policies to encourage the deployment of distributed solar PVIn cases where the market-based adoption forecast falls short of state policy targets, upward adjustments are made to reflect achievement of current policy• Assumes utilities will fund programs to reach targets
State PolicyArizona RPS DG Set-Aside (4.5% of IOU/coop retail sales by 2025)California California Solar Initiative (2,300 MW for IOUs; 700 MW for publics)
Colorado RPS DG set-aside (3% of IOU 2020 retail sales; 1% of public utility 2020 retail sales)
New Mexico RPS DG set-aside (0.6% of 2020 retail sales)Nevada Nevada Solar Incentives Program (36 MW among NVE and SPP)
Oregon Energy Trust (124 MW among PGE and PacifiCorp)Solar Volumetric Incentive and Payments Program (27.5 MW among PGE, PacifiCorp, and IPC)
61
Policy Adjustments
For each utility, initial market-driven DG forecast is adjusted upward in each year it is short of policy targetsIllustrative example shown for APS
0
100
200
300
400
500
600
700
800
900
2010 2012 2014 2016 2018 2020 2022 2024
Inst
alle
d Ca
paci
ty (M
W)
Market-Driven DG Policy Target
62
Step 3: Adjust for Net Metering Policy
Common Case projections assume all current NEM caps remain in place• Arizona, Colorado, Montana, New Mexico, Wyoming: no cap• Oregon & Washington: 0.5% of utility peak• Idaho: 0.1% of utility peak• Nevada: 3% of utility peak• California: 5% of noncoincident peak (currently)
Common Case projections assume these caps remain in place throughout the analysis• Exception: California’s AB 327 lifts the existing NEM cap beginning
in 2017 with the implementation of a standard NEM tariff
63
NEM Adjustments
For each utility whose installed capacity would be constrained by a NEM cap, installation forecast is adjusted downward to the limitIllustrative example shown for Puget Sound
0
50
100
150
200
250
300
2010 2012 2014 2016 2018 2020 2022 2024
Inst
alle
d Ca
paci
ty (M
W)
Market-Driven DG Policy Target