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Storage Futures Study: Four Phases Framework and Modeling
June 22, 2021
Speakers: Paul Denholm, Four Phases Lead AuthorWill Frazier, ReEDS Diurnal Storage Lead Author
NREL | 2
Storage Futures Study
NREL is analyzing the rapidly increasing role of energy storage in the electrical grid through 2050.
https://www.nrel.gov/analysis/storage-futures.html
• “Four Phases” - theoretical framework driving storage deployment• Techno-Economic Analysis of Storage Technologies• Deep dive on future costs of distributed and grid batteries• Various cost-driven grid scenarios to 2050• Distributed PV + storage adoption analysis• Grid operational modeling of high-levels of storage
One Key Conclusion: Under all scenarios, dramatic growth in grid energy storage is the least cost option.
SFS: Planned reports and discussed reports today
The Four Phases of Storage Deployment: This report examines the framework developed around energy storage deployment and value in the electrical grid.
Storage Technology Modeling Input Data Report : A report on a broad set of storage technologies along with current and future costs for all modeled storage technologies including batteries, CSP, and pumped hydropower storage.
Grid-Scale Diurnal Storage Scenarios : A report on the various future capacity expansion scenarios and results developed through this project. These scenarios are modeled in the ReEDS model.
Distributed Storage Adoption Scenarios (Technical Report): A report on the various future distributed storage capacity adoption scenarios and results and implications. These scenarios reflect significant model development and analysis in the dGen model.
Grid Operational Impacts of Storage (Technical Report): A report on the operational characteristics of energy storage, validation of ReEDS scenarioson capturing value streams for energy storage as well as impacts of seasonal storage on grid operations. Released late 2021
Key Learnings Summary: A final summary report that draws on the prior reports and related literature, generates key conclusions and summarizes the entire activity. Released late 2021
= discussed today
All reports are or will be linked to the SFS website: https://www.nrel.gov/analysis/storage-futures.html
Four Phases: A Visionary Framework
• The Four Phases report synthesizes a large body of work into a straightforward narrative framework we anticipate will be helpful to stakeholders.
• The important conclusions are the trends and the drivers of deployment rather than the specific quantities and timing.
The Four Phases of Storage Deployment
Phase Primary Service National Potential in Each Phase
Duration Response Speed
Deployment prior to 2010
Peaking capacity, energy time shifting and operating reserves
23 GW of pumped hydro storage
Mostly 8–12 hr
Varies
1 Operating reserves <30 GW <1 hr Milliseconds to seconds
2 Peaking capacity 30–100 GW, strongly linked to PV deployment
2–6 hr Minutes
3 Diurnal capacity and energy time shifting
100+ GW. Depends on both on Phase 2 and deployment of variable generation resources
4–12 hr Minutes
4 Multiday to seasonal capacity and energy time shifting
Zero to more than 250 GW
Days to months
Minutes
While the Phases are roughly sequential there is considerable overlap and uncertainty!
US Historical Deployment
Pumped storage continues to play an important role, and there are likely new opportunities for additional deployments
0
5,000
10,000
15,000
20,000
25,000
1950 1960 1970 1980 1990 2000 2010
Inst
alle
d Ca
pacit
y (M
W)
Year
Pumped Hydro Storage
All Other Technologies
NREL | 7
Framework: Power vs EnergyPower-related components are annotated in red and
energy components in yellow. Images are not to scale
Valuation Framework: Costs
Simplified relationship between capital cost of energy storage and duration using 2020 cost estimates
Valuation Framework: Marginal Cost
0
200
400
600
800
1000
1200
1400
1600
1 2 3 4 5 6
Mar
gina
l Sys
tem
Cap
ital C
ost (
$/kW
h of
st
orag
e ca
paci
ty)
Hours of Storage
H2 with Underground Storage
Pumped Storage
Li-Ion Battery
Li-Ion Battery (2024 estimate)
First hour of H2 storage is $3100/kWh
Simplified relationship between capital cost of energy storage and duration using 2020 cost estimates - incremental
Services
Service DescriptionCapacity Firm capacity Energy Energy shifting/dispatch
efficiency/avoided curtailment
Transmission Avoided capacity, congestion relief
Ancillary services Operating reserves, voltage support
Four Major Categories of Bulk Power System Storage Services
Phase 1: Short-Duration Storage for Operating
Reserves
Reserve Types
Regulating Reserves
Spinning Reserves
Non-spinning Reserves
Primary Frequency Response
mS S Min Hr Day
Inertial Response
Economic Dispatch
Replacement Reserves
Ramping Reserves
1. FrequencyResponsiveReserves
3. ContingencyReserves
5. Normal operationprovided by “energyand capacity”
2. RegulatingReserves
4. RampingReserves
Services currentlynot procured via markets
Proposed or early adoption market services
Currently procured via markets
Fast Frequency Response
Option 3mS S Min Hr Day
Timescale
Example Value
0
10
20
30
40
50
60
70
80
0 10 20 30 40 50 60
Annu
al O
pera
ting
Rese
rves
Val
ue
($/k
W-y
r)
Storage Duration (Minutes)
Total Value
MarginalValue Example of the total and
marginal value of spinning reserves assuming tariff value of
$75/kW-yr
Example Benefit/Cost Ratio
0
0.5
1
1.5
2
2.5
3
3.5
0 10 20 30 40 50 60
Bene
fit -
Cost
Rat
io fo
r Pro
visio
n of
O
pera
ting
Rese
rves
Storage Duration (Minutes)
Total
Marginal
Example of total and marginal B/C ratio assuming 90% battery availability and 2020 Li-Ion cost estimates
Phase 1: Short-Duration Storage for Operating
Reserves
Region Deployment (MW)Alaska & Hawaii 27 California 139 Non-CAISO Western Interconnection 29Texas 108 PJM 182 New York & New England 66 Other Regions in the Eastern Interconnection 171 Total 721
Capacity includes 656 MW of Li-ion batteries, 47 MW of flywheels, and 18 MW of other battery types.
Phase 1 Utility-Scale (>0.5 MW) Storage Deployment with 1 hour or less capacity, 2011–2019
Limits to Phase 1
0
5,000
10,000
15,000
20,000
25,000
30,000
CAISO ERCOT ISO-NE MISO NYISO PJM SPP FRCC SERC WECC Total
Nat
iona
l Cap
acity
Pro
cure
d (M
W)
SpinningContingencyReserves
RegulatingReserves
FrequencyResponse
Market Regions Non-Market Regions
0
1,000
2,000
3,000
4,000
5,000
6,000
Regi
onal
Cap
acity
Req
uire
d (M
W)
0
1,000
2,000
3,000
4,000
5,000
6,000
Regi
onal
Cap
acity
Pro
cure
d (M
W)
Current U.S. grid requirements for high-value operating reserve products potentially served by energy
storage in Phase 1
Phase 2: The Rise of Battery Peaking Plants
Installation dates of U.S. peaking capacity (non-combined Heat and Power, Combustion Turbines, Internal Combustion, oil/gas steam) (EIA 860)
02468
1012141618202224
Peak
ing
Capa
city
Inst
alle
d (G
W)
Over the next 20 years, we would expect about 150 GW of peaking capacity to retire
Key Issue: Duration Required to Reliably Decrease Net Peak
NYISO = New York Independent System Operator FRCC= Florida Reliability Coordinating Council
Duration Requirements
MarketOperator
Duration Minimum(hours)
ISO-NE 2CAISO 4NYISO 4SPP 4MISO 4PJM 10
Regional Energy Storage Duration Requirements in response to FERC 841
[1] PJM is in the process of updating this value based on an effective load carrying capability calculation. (“PJM Interconnection L.L.C., Docket No. ER21-278-000 Effective Load Carrying Capability Construct,” PJM, October 30, 2020, https://www.pjm.com/directory/etariff/FercDockets/5832/20201030-er21-278-000.pdf.)FERC 841 https://www.ferc.gov/media/order-no-841
Capacity Value as a Function of Duration
0
10
20
30
40
50
60
70
80
90
100
0 1 2 3 4 5 6 7 8
Annu
alize
d Ca
paci
ty V
alue
($/k
W-y
r)
Storage Duration (Hours)
Total Value
Marginal Value
Value of storage providing capacity, assuming a 4-hour duration requirement and a $90/kW-yr capacity payment
Energy Shifting Value
0
10
20
30
40
50
60
70
80
90
0 1 2 3 4 5 6 7 8 9 10 11 12
Tota
l Ann
ual V
alue
of E
nerg
y Ti
me
Shift
ing
($/k
W-y
r)
Storage Duration (Hours)
CAISO
PJM
0
5
10
15
20
25
0 1 2 3 4 5 6 7 8 9 10 11 12
Mar
gina
l Ann
ual V
alue
of E
nerg
y Ti
me
Shift
ing
($/k
W-y
r)
Storage Duration (Hours)
CAISO
PJM
(a) Total value (b) Marginal value Example of the total and marginal value of energy time-shifting using
2019 energy market values
Total Value
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
0
20
40
60
80
100
120
140
160
0 1 2 3 4 5 6 7 8 9 10
Frac
tion
of T
otal
Val
ue fr
om C
apac
ity
Annu
al T
otal
(Ene
rgy
and
Capa
city
) Va
lue
($/k
W-y
r)
Storage Duration (Hours)
Total Value
Marginal Value
Fraction of total value from capacity
Example of the total and marginal value and of a battery storage system providing peaking capacity
Example Benefit/Cost Ratio
0
0.2
0.4
0.6
0.8
1
1.2
1.4
0 1 2 3 4 5 6 7 8 9 10
Bene
fit -
Cost
Rat
io fo
r Pro
visio
n of
En
ergy
and
Cap
acity
Storage Duration (Hours)
2024 Cost Estimates
2020 Cost Estimates
Example of the Benefit/Cost ratio of a battery storage system providing peaking capacity
Limits – Widening Peaks
20,000
25,000
30,000
35,000
40,000
45,000
50,000
55,000
0 6 12 18 24
Net
Dem
and
(MW
)
Hour of Day
No Storage
With Storage
With storage peak demand period is
now > 4 hours
Simulated impact of increased 4-hour storage
deployment on net load shape
But Peak Narrows with PV Deployment
0
10,000
20,000
30,000
40,000
50,000
60,000
0 6 12 18 24
Net
Dem
and
(MW
)
Hour of Day
0% PV
5% PV
10% PV
15% PV
20% PV
PV increases opportunities for storage
as peaking capacity –California Example
Potential for Phase 2
0
20
40
60
80
100
120
140
160
0% 5% 10% 15% 20% 25% 30% 35% 40% 45%6-Ho
ur o
r Sho
rter
Bat
tery
Dur
atio
ns w
ith
High
Cap
acity
Cre
dit
Annual Percentage of Electricity from PV (Conterminous U.S.)
Trend of 20,000 scenarios
The potential opportunity of Phase 2: National potential of 4–6 hour
batteries with high capacity credit
Phase 3: The Era of Ubiquitous Storage?
0
10,000
20,000
30,000
40,000
50,000
8/29 0:00 8/29 12:00 8/30 0:00 8/30 12:00 8/31 0:00
Dem
and
(MW
)
Load Net Load with 4- and 6-Hr Storage (Phase 2)
Net Load w/VG Net Load with 8-Hr Storage
Net load peak is about 7 hours wide after Phase 2
Net load peak is about 10 hours wide with example Phase 3 deployments
Example of Phase 2: 9,000 MW with 4.5-hour average duration
Example of Phase 3: 7,000 MW with 8-hour average duration
Longer peaks with greater storage deployment
NREL | 28
Storage Costs Are Projected to Decline Beyond 2020
Cost declines (from 2018) range from 21% to 67% by 2030
Source: Augustine, Chad, and Nate Blair. Energy Storage Futures Study: Storage Technology Modeling Input Data Report. Golden, CO: National Renewable Energy Laboratory. NREL/TP-5700-78694. https://www.nrel.gov/docs/fy21osti/78694.pdf.
Phase 3: Continued Deployment of <8 Hr
storage?
-10,000
-5,000
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
4/13 0:00 4/13 12:00 4/14 0:00 4/14 12:00 4/15 0:00
Pow
er (M
W)
Load Net Load w/VG VG Supply
Supply of VG exceeds electricity demand
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
4/9/24 0:001
4/9/24 6:007
4/9/24 12:0013
4/9/24 18:0019
4/10/24 0:0025
4/10/24 6:0031
4/10/24 12:0037
4/10/24 18:0043
PV G
ener
atio
n (M
W)
PV Stored PV Used Directly PV Curtailed
Curtailment lasts 6 hours
10,0004/13 0:00 4/13 12:00 4/14 0:00 4/14 12:00 4/15 0:00
Stored with Phase 2 deployments
VRE supply and net load during two spring days
Availability of curtailed energy during a spring period showing length of curtailment events
Residual curtailment after Phase 2 storage deployments
Phase 3: Ultimate Limits Due to Seasonal
Mismatch
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
9/2 0:00 9/2 12:00 9/3 0:00 9/3 12:00 9/4 0:00
Dem
and
(MW
)Load Net Load w/80% RE Net Load with 80% RE and Dirunal Storage 80%
Charging raises net load
Discharging reduces net peak load
Decline in capacity value due to a flattened net load
Simulated flattened loads in ERCOT at 80% RE
Phase 3: Ultimate Limits Due to Seasonal
Mismatch
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
0
10
20
30
40
50
60
70
3/11 3/12 3/13 3/14 3/15 3/16
Stor
age
Stat
e of
Cha
rge
(%)
Gen
erat
ion
(GW
)
RE Curtailed RE Stored Discharge from Storage
RE Used Directly Normal Load Total VG Potential
Storage SOC
Residual load is not shown and is zero or negativeduring this entire period
3/17
Simulated flattened loads in ERCOT at 80% RE
Decline in time-shifting value due to zero net load.
Phase 3 Opportunities
0
20
40
60
80
100
120
140
160
180
200
0% 5% 10% 15% 20% 25% 30% 35% 40% 45%
Stor
age
with
Hig
h Ca
paci
ty C
redi
t (GW
)
Annual Percentage of Electricity from PV (Conterminous U.S.)
Up to 12 Hours
Up to 6 Hours
National opportunities for long-duration (up to 12-hour) storage providing capacity services in Phase 3
Phase 4: The Need for Residual Capacity
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
0 2000 4000 6000 8000
Net
Loa
d (M
W)
Hours at Load
Base
VG Only
VG with diurnal storage
Firm capacity needed to meet net peak demand and serve remaining 10%
0
10,000
20,000
30,000
40,000
50,000
60,000
0 2000 4000 6000 8000
Net
Loa
d (M
W)
Hours at Load
Base
VG Only
VG with diurnal storage
ERCOT
Residual load duration curves at 90% RE showing the need for significant
firm capacity California
Seasonal Storage Operation at 98% RE
Phase 4 Opportunities
0
50
100
150
200
250
300
350
80 82 84 86 88 90
Rem
aini
ng C
apac
ity R
equi
red
Pote
ntia
lly
Met
by
Seas
onal
Sto
rage
(GW
)
% of Demand Met By RE and Diurnal Storage
Low RE Capacity Credit Scenario
High RE Capacity Credit Scenario
Bounding the size of Phase 4 by estimating the national residual capacity requirements under 80%–90% RE scenarios
The Four Phases of Storage Deployment
Phase Primary Service National Potential in Each Phase
Duration Response Speed
Deployment prior to 2010
Peaking capacity, energy time shifting and operating reserves
23 GW of pumped hydro storage
Mostly 8–12 hr
Varies
1 Operating reserves <30 GW <1 hr Milliseconds to seconds
2 Peaking capacity 30–100 GW, strongly linked to PV deployment
2–6 hr Minutes
3 Diurnal capacity and energy time shifting
100+ GW. Depends on both on Phase 2 and deployment of variable generation resources
4–12 hr Minutes
4 Multiday to seasonal capacity and energy time shifting
Zero to more than 250 GW
Days to months
Minutes
While the Phases are roughly sequential there is considerable overlap and uncertainty!
Grid-Scale Diurnal Storage Scenarios
Variable Renewable Energy
CostStorage Cost Natural Gas Price
• Reference Cost• Low Wind Cost• High Wind Cost• Low PV Cost• High PV Cost
• Reference Cost• Low Battery
Cost• High Battery
Cost
• Reference NG price
• High NG price• Low NG price
Transmission cost
• Reference transmission cost
• High transmission cost
Combinations of these sensitivities are used to create a total of 19 scenarios
Improvements to Storage Representation in ReEDS 7 years of weather and
load data for analyzing system reliability
Storage resources are split out by duration to capture the relationship between duration, capacity provision, energy arbitrage, and cost
Dispatch of generation, storage, and transmission simulated for each hour of year to inform investment decisions
Modelled storage deployment in ReEDS
Interaction of Storage and Net Load (2050 in California)
Net load profiles inform capacity value of storageEnergy price profiles inform energy time-shifting value of storage
Storage Correlates with PV More than Wind
Peaking capacity potential (GW) (determined by net load shape)
Energy time-shifting potential (TWh) (determined by energy price profiles)
Amount of Generation that Goes through Storage
Transmission Correlates More with Wind
Relative Value of Storage Services
Economic Deployment versus Peaking Capacity Potential
29% PV 43%
PV 22% PV
31% PV
41% PV
Storage is optimized based on the relationship between:
- capacity value- energy value- storage duration- storage cost & performance
Grid-Scale Diurnal Storage Scenarios Key Takeaways
Questions and Discussion
Encouraging everyone to share/forward NREL outreach on social media• https://www.nrel.gov/news/program/2021/nrel-
launches-storage-futures-study-with-visionary-framework-for-dramatic-increase-in-deployment.html
• NREL also posted items on Linkedin, Twitter, etc.
https://www.nrel.gov/analysis/storage-futures.html
NREL/PR-5C00-80366
NREL | 48
Future Battery Costs by Cost Scenario - Moderate
• Use same cost projections for 4-hour BESS as in Cole & Frazier 2020*– Projections based on
literature review of 16 projections
• Adjusted cost projections for other durations to account for reductions at component– BNEF data for component-
level reductions– LIB pack costs reduce faster
than rest of component costs
– Long-duration BESS costs reduce faster (LIB make up greater share of costs
• Compared here to EPRI, BNEF and Schmidt
*https://atb.nrel.gov/
NREL | 49
Current Battery Costs – Residential
• Stand-Alone Battery Energy Storage System (BESS)– Based on methodology
used in NREL PV and BESS cost benchmarking study*
– Assumes $176/kWh battery pack (BNEF 2020)
– Installation, overhead and profit margin assumptions aligned with NREL Residential PV model
– Costs converted to linear equation based on battery power and energy capacity for use in dGen *Feldman et al. 2020 (forthcoming) U.S. Solar Photovoltaic System and Energy
Storage Cost Benchmark: Q1 2019, NREL/TP-6A20-75161
NREL | 50
Future Battery Costs by Component
• Battery pack costs decline much faster than other cost components
• Must account for this or will skew BESS costs as a function of duration
• Determined current year cost breakout by component for all durations and then applied cost reductions by component