Wind-Plus-Storage Presentation

The Potential Wind-plus-Storage Roadmap
Measuring Paths from Pilot to Scale for Wind-Paired Storage
Daniel Finn-Foley
Senior Analyst
finn-foley@gtmresearch.com
July 2018

1The Potential Wind-plus-Storage Roadmap
Contents
1. Introduction 2
2. Co-Siting Cost Savings 5
3. Arbitrage and Curtailment Opportunity 9
4. Potential for Firming Wind Power 13

Introduction1

Co-Sited Wind-plus-Storage has Historically been Limited to Pilot Projects
XCEL MinnWind - 1MW, 7.2 MWh
NaS battery paired with an
11.5MW wind farm
Kaheawa Hawaii BESS 1&2 -
11MW, 4.4 MWh Li-Ion battery
and 10MW 7.5 MWh lead-acid
battery paired with a 21MW wind
farm for ramp control
Notrees – 36MW, 24 MWh re-
powered system paired with a
153MW wind farm
Tehachapi Wind-Storage –
8MW, 32 MWh
Texas Waves 1&2 – 10MW, 5 MWh
twin projects paired with two
portions of the 781.5MW Roscoe
Wind Farm
Revolution Wind – Proposed 40
MWh storage system paired with a
144MW offshore wind project,
targeted online date 2023
Total U.S. Wind-Charged Storage
Deployments:
73.8MW, 82.4 MWh Operational
45MW, 125 MWh Pipeline
• The U.S. wind-charged energy storage pipeline is small and highly speculative – it will likely be five years or more before
true scale for wind + storage is achieved.
• Historical projects have provided a variety of services but so far have not appeared to demonstrate bankability at scale.

Where Will the Opportunity Emerge for Wind-plus-Storage?
• The northeast is rich
in energy storage
mandates and
incentives, but low in
installed wind
capacity
• Offshore wind
targets will provide
more raw wind MW
to potentially pair
with storage
• California and the
southwestern U.S. are
investing heavily in
storage, but solar will
likely be the preferred
resource to pair with
storage in the short
term due to the ITC
and generally
favorable economics
• The Midwest boasts some of the best wind resource in the world, but few
states incentivize storage, and no organized markets yield favorable returns
• Texas represents the largest
opportunity, but for now lacks
clear business models
Source: American Wind Energy Association | U.S. Wind Industry First Quarter 2018 Market Report

Co-Siting Cost Savings

ITC vs. PTC – Wind-plus-Storage Favors PTC
0% 25% 50% 75% 100% 125% 150%
70% $103 $94 $85 $76 $67 $58 $49
65% $94 $85 $76 $67 $58 $49 $40
60% $84 $75 $66 $57 $48 $39 $30
55% $75 $66 $57 $48 $39 $30 $21
50% $66 $57 $48 $39 $30 $21 $11
45% $56 $47 $38 $29 $20 $11 $2
40% $47 $38 $29 $20 $11 $2 -$7
35% $37 $28 $19 $10 $1 -$8 -$17
30% $28 $19 $10 $1 -$8 -$17 -$26
25% $19 $10 $1 -$8 -$17 -$26 -$35
20% $9 $0 -$9 -$18 -$27 -$36 -$45
15% $0 -$9 -$18 -$27 -$36 -$45 -$54
10% -$10 -$19 -$28 -$37 -$46 -$55 -$64
5% -$19 -$28 -$37 -$46 -$55 -$64 -$73
0% -$28 -$37 -$46 -$55 -$64 -$73 -$82
Energy storage system size (% wind farm nameplate MW capacity, 4-hours duration)
Sitecapacityfactor(%)
Note: Negative values indicate favorable project ITC economics vs. PTC economics, hypothetical 100MW wind farm.

Power Conversion System
• Central Inverter: $/kW
• String Inverter: $/kW
Containerization
• AC Main Panel: $/kW
• HVAC: $/kWh
• Meter: $/kW
• Isolation Transformer:
$/kW
• Switchgear: $/kW
• Uninterruptible Power
Supply: $/kW
• Aux. Power: $/kW
• Fire Detection: $/kWh
• Fire Suppression: $/kWh
• LAN or Communication
Device: $/kW
• Electrical Conduit or
Raceway: $/kW - $/kWh
• Metal Enclosure or
Concrete Enclosure:
$/kWh
• Offsite Labor for Metal
Enclosure Integration:
$/kW - $/kWh
Software and Controls
• Energy Storage Management
Software: $/kW
• SCADA: $/kW
• Controller: $/kW
EPC
• Site Inspection and
Preparation: $/kWh
• Stamped Drawings: $/kWh
• Container Install for Metal
Enclosure: $/kWh
• Rigging and Shipping:
$/kWh
• General Electrical
Contracting: $/kWh
• Commissioning: $/kWh
• Civil Work for Concrete
Enclosure: $/kWh
• Electrical Work for
Concrete Enclosure: $/kWh
• Field Supervision and Site
Security for Concrete
Enclosure: $/kWh
Interconnection
• Interconnection Study: $/kW
• Interconnection
Inspection: $/kW
• Interconnection Fee: $/kW
• Permits and Other Fees:
$/kW
• High-Voltage
Interconnection: $/kW
Co-Siting Storage with Wind Creates a Handful of Cost Saving Opportunities
Source: GTM Research – U.S. Front of the Meter Energy Storage System Prices
Hardware & Controls
Medium potential savings
Low potential savings
High potential savings •Interconnection costs
•High Voltage Interconnect
•Existing site infrastructure
•Existing software or controls systems
Cost saving opportunities
for storage installed at
new or existing wind farm

Cost Savings are Critical for Energy Storage’s Competitiveness
52%
45% 43%
13%
32% 40%
35%
23%
17%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
30-minute 2-hour 4-hour
Hardware & Controls Cost EPC Cost Interconnection Cost
Source: GTM Research – U.S. Front of the Meter Energy Storage System Prices
2018 System BOS Cost Stack
• Software and controls represent ~20% of hardware and
controls costs, providing a small but not insignificant
opportunity to leverage scale across projects.
• Co-siting reduces costs for site preparation, but is
generally not a significant driver of storage system costs.
• Interconnection costs vary dramatically but can exceed
$140/kW, with as much as $80/kW added for high
voltage connections.
• Using an existing interconnection can reduce the cost of
a project by as much as 5-15%, depending on regional
interconnection rules.

Arbitrage and Curtailment Opportunity

Negative Energy Market Signals in 2017
Source: GTM Research, CAISO
Total Negative Price Hours (CAISO, 2017 Data)
0%
2%
4%
6%
8%
01:00 03:00 05:00 07:00 09:00 11:00 13:00 15:00 17:00 19:00 21:00 23:00
Percentageof1-hourIntervals
Zone - Wyoming Zone - Utah
Zone - Palo Verde Zone - Nevada Power South
Zone - Nevada Power North Zone - Mead
Zone - Jim Bridger Zone - California-Oregon Border (COB)
Zone - CAISO ZP26 Zone - CAISO SP15
Zone - CAISO SDG&E Zone - CAISO SCE
Zone - CAISO PG&E Zone - CAISO NP15
Source: GTM Research, SPP
Total Negative Price Hours (SPP, 2017 Data)
0.0%
2.0%
4.0%
6.0%
8.0%
10.0%
01:00 03:00 05:00 07:00 09:00 11:00 13:00 15:00 17:00 19:00 21:00 23:00
Percentageof1-HourIntervals
Zone - SPP--WAPA Upper Great Plains Missouri East Zone - SPP Western Farmers Electric Cooperative
Zone - SPP Westar Energy Zone - SPP Sunflower Electric Power Corporation
Zone - SPP Springfield Missouri Zone - SPP Southwestern Public Service
Zone - SPP Omaha Public Power District Zone - SPP Oklahoma Gas & Electric
Zone - SPP Nebraska Public Power District Zone - SPP Missouri Public Service
Zone - SPP Lincoln Electric System Zone - SPP Kansas City Power & Light
Zone - SPP Independence Missouri Zone - SPP Grand River Dam Authority
Zone - SPP Empire District Electric Zone - SPP Board of Public Utilities Kansas City

0
10
20
30
40
50
60
70
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
AverageHourlyLMP($/MWh)
Hour Ending
CAISO
ERCOT
ISO-NE
MISO
NYISO
PJM
SPP
Energy Arbitrage Opportunities Vary by ISO – CAISO Stands Out
0
10
20
30
40
50
60
70
AverageHourlyLMP($/MWh)
Source: GTM Research, ISO data
Average Hourly LMP by ISO – 2017
• Peak hours range from 4 PM in ERCOT to 8 PM in CAISO.
• Early morning hours (2 AM to 5 AM) provide most daily
lows for effective charging.
• CAISO’s curve is unique – including midday price lows
and a second peak in the early morning, both partially
driven by abundant midday solar.
Average peak and trough LMP spread by ISO – 2017

• FERC Order 841 has set the stage for most ISOs (ERCOT is not under FERC jurisdiction) to ensure energy storage can
participate in all wholesale markets, including the energy market for arbitrage, potentially giving wind farms the ability
to store electricity when it is cheap and sell it when prices spike.
• Potential arbitrage revenue varies dramatically by ISO. California ISO has by far the most potential, with an
$40.56/MWh difference between average daily peaks and troughs in pricing (including efficiency losses), while MISO
has the least appealing price curve with a spread of only $13.26/MWh.
• A 1-hour system, optimized for the best hourly peaks and troughs, will obtain better revenue per hour of capacity than
a multiple-hour system, which will operate across longer and less significant peak and trough periods.
• Arbitrage spreads and potential revenue are still far too low to justify pure-play arbitrage as a storage business model.
• Even if arbitrage becomes feasible, is co-siting necessary? Stand alone storage may have a clearer path to market
participation.
• Is seasonal arbitrage an option?
Curtailment and Arbitrage: Market Volatility will need to Increase to Create a Business Case

Potential for Firming Wind Power

Sample Sites Chosen for Wind Firming Opportunity

Wind Profile – ISO-NE Offshore Wind Speeds and Output – January 2010
0
1
2
3
4
5
6
7
8
9
10
WindFarmOutput(MW)
0
5
10
15
20
25
30
AverageHourlyWind
Speed(m/s)
Rated Power – 10 MW
Source: NREL Wind Prospector, GTM Research
Cut-off
speed
reached

Variability is a Consistent Challenge, Regardless of Geography
0
2
4
6
8
10
WindOutput(MW)
0
2
4
6
8
10
WindOutput(MW)
0
2
4
6
8
10
WindOutput(MW)
0
2
4
6
8
10
WindOutput(MW)
January 2010 Hourly Wind Output – ISO-NE Onshore (Western Massachusetts)
January 2010 Hourly Wind Output – PJM Offshore (Off New Jersey)
January 2010 Hourly Wind Output – PJM Onshore (West Virginia)
January 2010 Hourly Wind Output – SPP (Oklahoma)

Tracking the “Firmed Energy Deficit” – How Much Storage is Needed to Firm Wind?
Source: NREL Wind Prospector, ISO-NE Offshore Data, GTM Research
Firming 50% of Nameplate Capacity with Storage – January 1st 2010
Firming 20% of Nameplate Capacity with Storage – January 1st 2010
-2
-1
0
1
2
3
4
5
6
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Wind+StorageOutput(MW)
-2
-1
0
1
2
3
4
5
6
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Wind+StorageOutput(MW)
Target
Capacity
• 63 MWh Max Contiguous Energy Requirement
• 3.7 MW Maximum Power Requirement
• 2.5 MWh Max Contiguous Energy Requirement
• 0.7 MW Maximum Power Requirement
Any firmed capacity above the system’s average capacity
is unfeasible. (ISO-NE Offshore Average Output 4.7 MW
out of 10 MW)
Less than four-hours,
feasible system size!
But this is only one, relatively steady, day…
How bad can it get over a three year
period?
21.7 MWH “excess”
generation available
Wind Farm Output Storage Discharging Storage Charging

100% Firming may not be Needed – What if a System is only Needed During Peak Hours?
0
2
4
6
8
10
12
1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 0:00
CombinedWindplusStorageSystemOutput
Wind Power Available During Peak Energy Storage Deficit Needed Wind Power Available for Charging
Catching peak hours – ISO-NE sample with four hour peak requirement from 5:00 PM to 9:00 PM, sample day, assumes only charging from wind farm
• Some wind power is available during peak hours, reducing the
need for storage
• The light blue represents the deficit needed to cover the peak
obligation
• The storage system can meet the peak if the sum of the previous
20 hours exceeds the system deficit during peak hours
Peak hours with
nameplate capacity
obligation
• In this case, the deficit is 31.6 MWh, while the wind farm
generated 48.9 MWh over the previous 20 hours

The Percent of Peaks Successfully Captured Depends on the Peak Obligation Duration
Percent of peak periods where there is not enough wind energy during the run-up hours to meet full nameplate capacity (6:00 PM peak start time)
0.0%
10.0%
20.0%
30.0%
40.0%
50.0%
60.0%
70.0%
80.0%
90.0%
1 2 3 4 5 6 7 8 9 10
PercentofPeaksMissed
Capacity Run-Time Obligation (Hours)
ISO-NE Offshore (MA)
ISO-NE Onshore (MA)
PJM Offshore (NJ)
PJM Onshore (WV)
SPP Onshore (OK)
For a typical 4 hour capacity system effectiveness
varies from 90% of peaks captured (SPP) to 57%
of peaks captured (PJM Onshore)
Effectiveness for longer durations is reduced as
the systems have fewer hours to charge assuming
consecutive daily capacity requirements

Firming a Smaller Percentage of Nameplate Capacity during Peak Hours is Feasible
Source: <Insert source>
Percent of peak periods where there is not enough wind energy during the run-up hours to meet 50% nameplate capacity (6:00 PM peak start time)
0.0%
10.0%
20.0%
30.0%
40.0%
50.0%
60.0%
70.0%
1 2 3 4 5 6 7 8 9 10
PercentofPeaksMissed
Capacity Run-Time Obligation (Hours)
ISO-NE Offshore (MA)
ISO-NE Onshore (MA)
PJM Offshore (NJ)
PJM Onshore (WV)
SPP Onshore (OK)
For a typical 4 hour capacity system
effectiveness varies from 94% of peaks captured
(SPP) to 73% of peaks captured (PJM Onshore)

Conclusions and Next Steps

• Wind-plus-storage remains in the pilot phase and is still 3-5 years out from aligning with a revenue
stream to truly incentivize it
• In the interim, using existing sites and interconnections for energy storage projects that would be
deployed regardless will drive most “hybrid” installations
• Firming wind to provide peak capacity is feasible in some markets even given wind’s intermittency
• Potential upsides for wind-plus-storage
◦ Clean peak standards
◦ Increased wind energy penetration / offshore wind development
◦ Wholesale energy market volatility
◦ Energy storage mandates / incentives in states with existing wind deployments
Key Takeaways and Potential Upside for Hybrid Wind and Storage Systems

Interested in other GTM Research products and services? Please visit www.gtmresearch.com or contact sales@greentechmedia.com
Thank you!
July 2018

Interested in other GTM Research products and services? Please visit www.gtmresearch.com or contact sales@greentechmedia.com
Appendix / Storage Specific Slides
July 2018

California’s Pipeline Shrinks, While SPP and MISO Interconnection Requests Surge
U.S. Front-of-the-Meter Energy Storage Pipeline by Market, Q3 2015-Q4 2017 (MW)
Source: GTM Research
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
Q3 2015 Q4 2015 Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018
TotalFTMEnergyStoragePipeline(MW)
Arizona California Colorado Hawaii Massachusetts Nevada New Jersey New York PJM (Exc. NJ) Texas All Others

215
3,688
-
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
2012 2013 2014 2015 2016 2017 2018E 2019E 2020E 2021E 2022E 2023E
EnergyStorageDeploymentsbySegment(MW)
Residential Non-Residential Front-of-the-Meter
U.S. Energy Storage Annual Deployments Will Reach 3.7 GW by 2023
U.S. Annual Energy Storage Deployment Forecast, 2012-2023E (MW)

$302
$4,334
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
$3,500
$4,000
$4,500
2012 2013 2014 2015 2016 2017 2018E 2019E 2020E 2021E 2022E 2023E
AnnualEnergyStorageMarketSize(Million$)
Residential Non-Residential Front-of-the-Meter
Energy Storage Will Be a $4.3 Billion Market by 2023
U.S. Annual Energy Storage Market Size, 2012-2023E (Million $)

* “Other” includes flywheel and unidentified energy storage technologies.
Quarterly Energy Storage Deployment Share by Technology (MW %)
Lithium-Ion Technology Continues the Trend of More Than 94% Share
Li-ion held 98.7% of the
market in Q1 2018, leading
the market for the 14th
straight quarter
Lead-acid came in second,
with 1.2% of market share.
One very small FTM
flywheel project made up
the remaining share.
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Q1
2013
Q2
2013
Q3
2013
Q4
2013
Q1
2014
Q2
2014
Q3
2014
Q4
2014
Q1
2015
Q2
2015
Q3
2015
Q4
2015
Q1
2016
Q2
2016
Q3
2016
Q4
2016
Q1
2017
Q2
2017
Q3
2017
Q4
2017
Q1
2018
EnergyStorageDeploymentsbyTechnology(MW)
Lithium Ion Lead Acid Sodium Chemistries Flow - Vanadium Flow - Zinc Other

Median Prices for 2-Hour FTM Systems Declined by 8% QOQ; Other Prices Remained Flat
Historical System Price Trends: Utility-Scale (2-Hour, $/kW)
Historical System Price Trends: Utility-Scale (30-Minute, $/kW)
Median Value
$0
$1,000
$2,000
$3,000
Q2 2015 Q2 2016 Q2 2017 Q2 2018
$400
$600
$800
$1,000
$1,200
Q2 2016 Q2 2017 Q2 2018

Historical System Price Trends: Residential ($/kW)
Median Prices for Non-Residential Systems Declined by 3%, While Residential Systems Remained Flat QOQ
Historical System Price Trends: Non-Residential ($/kW)
Median Value
$0
$1,000
$2,000
$3,000
$4,000
$5,000
Q2 2015 Q2 2016 Q2 2017 Q2 2018
$0
$1,000
$2,000
$3,000
$4,000
Q2 2015 Q2 2016 Q2 2017 Q2 2018

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