Research Presentation

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A World Full of Possibilities:
Integrating DERs into Wholesale Markets
Daniel Finn-Foley
Principal Analyst, Energy Storage
@DanFinnFoley

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Building blocks
Literally

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A “world full of possibilities” also taken literally
208 BC
8-12th century AD
100 - 450 AD
2560 BC
Diverse ecosystems independently converge to similar efficient solutions!

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Sand
• Grid analogue:
1831 - 1882
• Unstable
combination of
smaller materials
• Completely
distributed, early
generators
providing on-site
need but nothing
further
Pyramid
• Grid analogue:
1882 - 1900
• Larger building
blocks used to
supplement and
reinforce each
other
• The first DC electric
grids, bottom
heavy, inflexible
design
Vertical construction
• Grid analogue:
1900 - 1992
• Complexities,
design, planning,
and further use of
materials and
engineering
• Transition to AC
grids, transmission
vs. distribution,
scale and
complexity
Bricks
• Grid analogue:
1992 - present
• Designed and
standardized, focus
on efficiency
• “Modern” grids,
further
automation,
interconnection,
software and a
focus on efficiency
through
competitive design
Concrete
• Grid analogue: ? - ?
• Aggregate, cement,
and water, hardens
into customizable
structures
• The “transitional”
grid – DER-based,
software and
markets enable
resiliency, DERs
support each other
through advanced
platforms
Reinforced concrete
• Grid analogue: ???
• Rebar used to
complement
concrete’s
strengths
• The
“transformational”
grid – DER-based
with transmission
and adaptive
software for
resiliency and
efficiency
Building a structure and building a grid – more in common than not

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Recognizing distributed energy’s value
Case study - NYISO

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Source: NYISO, 24 April 20 Management Committee Meeting ‘DER Energy & Capacity Market Design’ presentation and 17 April Business Issues Committee 'DER Energy & Capacity Market Design’ presentation
Dispatchable
Aggregations of DER
An aggregation under the responsibility of an
aggregator and consists of resources:
• Can qualify to participate in all markets
• Capable of responding in real-time to NYISO’s
direction
Generator Resource
Model
Consisting of only generators
Energy Storage
Resource Model
Consisting of only energy storage resources (ESR)
Dispatchable DER
Model
Consisting of only Demand Side Resources (DSR, no
injection)
Mix of Generators, Energy Storage Resources, and
Demand Side Resources
Individual Resources
• Can qualify to participate in all markets
• Capable of injection, responding in real time
Generator Model
or Energy Storage
Resource Model
Individual Generator or Energy Storage Resource
Non-dispatchable
Non-dispatchable aggregation or individual
demand side resources
• Capable of load reduction
• Not capable of responding in real-time to
NYISO’s direction
Special Case Resources (SCR)
Individual Demand Side Resources or Small Customer Aggregation under the
responsibility of a Responsible Interface Party (RIP) and are resources qualified to
participate in Capacity Market
Emergency Demand Response Program
Individual Demand Side Resources under the responsibility of a Curtailment service
Provider (CSP) and are resources qualified to provide Energy during reliability
events
NYISO outlines DER market participation models

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NYISO aggregations participation options
Resource type As aggregations of: As an individual ESR As an individual ELR
As an individual
Generator
As an individual IPR
Demand Side
Resource
DER, SCR, EDRP No No No No
Storage ESR Yes Yes Yes No
Wind IPR (wind only) No No No Yes
Solar IPR (solar only) No No No Yes
GTs Gen (GTs only) No Yes Yes No
Other Generators Generators No Yes Yes No
Mixed DER No No No No
• All resources must individually qualify to be eligible
to aggregate as an Aggregation of LESR, CLR, ELR
• Generators with PURPA contracts, Limited Control
Run of River Resources, Behind-the-Meter Net
Generation Resources, Municipally-owned
Generation, System Resources, and Control Area
System Resources are not eligible to aggregate as an
Aggregation
Source: 17 April Business Issues Committee 'DER Energy & Capacity Market Design’ presentation
Key
CLR: Capacity Limited Resources
DSR: Demand Side Resource
EDRP: Emergency Demand Response Program
ELR: Energy Limited Resource
ESR: Energy Storage Resource
GT: Gas Turbine
IPR: Intermittent Power Resource
SCR: Special Case Resource
LESR: Limited Energy Storage Resource

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Source: Wood Mackenzie Power & Renewables ‘U.S. energy storage monitor: Q2 2019’
VDER revisions provide a boon for solar-plus-storage
Greater certainty of value stack revenues good news for financiers and developers
• In April 2019, NYSERDA announced changes to the Value of Distributed Energy Resources (VDER) value stack. Overall, these changes create
greater certainty around the payment from different aspects of the value stack. Highlighted changes to the value stack include:
• Capacity (ICAP): Windows for alternative narrowed, fewer hours each summer but potential revenue remains.
• Demand Reduction Value (DRV): now paid on performance over a known peak window, varying by utility, which provides greater revenue
certainty. Each utility includes five-hour window during summer weekdays, aligning with ICAP model. DRV rates and time periods are locked in for
10 years, providing further certainty.
• Locational System Relief Value (LSRV): shifts to a call system where utility will now have at least 10 call events per year with 21 hours prior
notice and occur during the DRV window. Calls will last 1-4 hours with compensation based on lowest net kW output during the call window. A
project that fails to respond to a call shall not be subject to any penalty. LSRV value and time period will be locked in for 10 years.
• Lining up windows for ICAP Alternative 2 and the DRV creates a significant opportunity for solar-plus-storage
• Extending LSRV and DRV values to 10 years will allow that portion of the value stack to become more financeable thanks to greater revenue certainty
over project lifetime.
• Movement towards “smart” targeting of hourly needs incentivizes storage by recognizing its value.

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Recognizing distributed energy’s value
Case study - PJM

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Source: : PJM, 2018, 2017 & 2016 Distributed Energy Resources in PJM Demand Response Markets
2018 distributed energy resources in PJM DR markets
Demand response economic energy settled, MWh trendDay-ahead and real-time market settlements, 2013-2018
$0
$2
$4
$6
$8
$10
$12
$14
$16
$18
$20
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
2013 2014 2015 2016 2017 2018
MillionUSD
MWh
Day Ahead (MWh) Real Time (MWh)
Total CSP Credits (mil USD)
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
2013 2014 2015 2016 2017 2018
MWh
Day-ahead and Real-time Economic Energy Settled (MWh)
DER Economic Energy Settled (MWh)*
• Economic demand response has seen a decline in both volume and credits awarded since 2014, reaching its lowest levels of settlements in 2018;
settlements declined by more than 15% while revenue notches a 6% increase year-over-year.
• The figure on the right illustrates that the majority of economic DR activity in the PJM energy market in 2018 came from DERs (65%+)
*WoodMac estimate based on 2016, 2017 &
2018 Distributed Energy Resources in PJM
Demand Response Markets reports

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2018 distributed energy resources in PJM DR markets
PJM DR synchronized reserves settled, MWh trendPJM DR regulation settled, MWh trend for DERs
$0
$1
$1
$2
$2
$3
$3
$4
0
20,000
40,000
60,000
80,000
100,000
120,000
2013 2014 2015 2016 2017 2018
CSPCredits(millionUSD)
MWh
Battery Generator
Electric water heaters CSP Credits (million USD)
• Settled regulation demand response volume (MWh) has steadily increased
year-over-year since 2013.
• When compared to 2017, market revenue increased by 66%, while volume
cleared increased by approximately 59%.
• PJM reports that behind-the-meter battery storage was the primary resource
providing regulation, making up 65% of the volume (MWh) in the market in
2018.
• Since 2015, settled MWh of demand response synchronized reserves have
seen a steady increase year-over-year.
• CSP revenue declined from 2015 to 2017, but in 2018 revenue nearly doubled
year-over-year as prices increased.
• Over the years, demand response synchronous reserves have been dominated
by manufacturing, which make up 76% of 2018 CSP-reported load reduction in
megawatts, followed by behind-the-meter generators at 12%.
$0
$1
$2
$3
$4
$5
$6
$7
0
200,000
400,000
600,000
800,000
1,000,000
1,200,000
2013 2014 2015 2016 2017 2018
CSPCredits(millionUSD)
MWh
MWh CSP Credits (million USD)
Source: : PJM, 2018, 2017 & 2016 Distributed Energy Resources in PJM Demand Response Markets

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Recognizing distributed energy’s value
Case study - CAISO

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Source: CAISO, CPUC, SCE, PG&E, SDG&E
Demand response capacity from utility operated programs continues to decline
DRAM resources comprise 23% of total demand response capacity in 2019
• Price-responsive programs are transitioning to Proxy Demand
Resources (PDRs) in day-ahead and day-of markets.
• Reliability-based programs are only triggered when CAISO declares an
emergency; these utility programs are transitioning to Reliability
Demand Response Resources (RDRRs) in the CAISO.
• RDRRs can only enter the bid stack when an emergency condition is
declared, at prices between $950/MWh to $1,000/MWh. RDRRs were
implemented in 2014.
• Decline in utility programs can be attributed to:
o The CPUC has mandate that the three investor owned utilities
switch customers to time-of-use rates starting in 2019, hence the
heavy decline in utility price-based program capacity.
o The demand response auction mechanism (DRAM) pilot total 203
MW in 2019. DRAM has taken customers away from utility
programs and into those of third parties since customers cannot
participate in both utility and DRAM demand response.
Demand response from utility operated programs, 2012-
2019*
2,431
2,188
2,315
2,160
2,036
1,885
1,435 1,412
0
500
1,000
1,500
2,000
2,500
3,000
2012 2013 2014 2015 2016 2017 2018 2019
MW
DRAM SDG&E DRAM PG&E
DRAM SCE Reliability-Based DR Programs SDG&E
Reliability-Based DR Programs PG&E Reliability-Based DR Programs SCE
Price-Response DR Programs SDG&E Price-Response DR Programs PG&E
Price-Response DR Programs SCE DRAM SDG&E
*CAISO did not report utility data for 2018 in the annual report; WoodMac added the data from 2019 and 2018 from
the monthly Interruptible Load Programs and Demand Response Programs to the CPUC

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For the first time CAISO devotes a section to energy storage resources in the annual report
• As illustrated on the left, battery energy storage
capacity has been steadily increasing since 2015,
totaling 136 MW by the end of 2018.
• CAISO points out that “the majority of batteries
participating in ISO markets are located in locally
constrained areas.”
• Batteries are primarily receiving awards in ancillary
services providing including regulation (up and down)
and spin reserves.
• When providing energy, schedules are concentrated
during the ramping hours (evenings and mornings);
batteries are often charging at night and in the middle
of the day when production from renewables is the
highest.
Battery storage as non-generator resources 2015-2018
Source: CAISO 2018 Annual Report on Market Issues and Performance
-480
-320
-160
0
160
320
480
-150
-100
-50
0
50
100
150
2015 2016 2017 2018
Continuousenergy(MWh)
Positive capacity Negative capacity Max continuous energy (MWh)

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Behind-the-Meter Resources Are Getting Entrenched in Real-Time Operations
Source: CAISO Docket No. ER06-615-000
2016-2018 non-spinning reserve and real-time energy
payments
• In January 2018 the Annual Report Evaluating Demand Response
Participation in the CAISO for 2017 was released, covering the
period from January 1 through November 30, 2018.
• The report summarizes the payments made for the provision of
nonspinning reserves capacity and real-time energy. Year-over-year
there is an observed significant uptick in demand response activity. In
2016 demand response providers earned just under $0.5 million while
in 2017 payments increased nearly nine-fold to $4.2 million; in 2018
payments increased to $5.05 million.
*See California Independent System Operator Corp. 119 FERC ¶ 61,313, at P 226 (2007). The CAISO has filed annual reports on
demand response participation each January since that order was issued.
$0
$1
$2
$3
$4
$5
$6
2016 2017 2018
USDmillion
Real-time energy Non-spinning reserves

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Recognizing distributed energy’s value
ISO-NE

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• In February 2017 Sunrun announced that it had won a contract for 20 MW of
solar-plus-storage capacity through ISO-NE’s capacity market, competing directly
against conventional generation for the 2022 delivery year.
• The most critical takeaway here is that aggregation is happening today*.
• Success begets success, and DER and hybrid participation models will continue
to grow and evolve as cheap solar, storage, and other distributed assets explore
every avenue to provide value.
*The actual announcement was 5 months ago and the capacity will not be due until 2022 but these details make this statement much less impactful so using my analyst
discretion I have chosen to confine them to this footnote.
Sunrun’s bid in ISO-NE’s forward capacity market
yields groundbreaking results

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The future of DERs in wholesale markets
FERC Order 841 provides a signpost for how FERC
may set the bar for DER aggregation

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Source: Wood Mackenzie Power & Renewables
FERC Order 841: Timeline from NOPR to implementation
 In November 2016, FERC released a
notice of proposed rulemaking
(NOPR) on integration of energy
storage and aggregation of distributed
energy resources into wholesale
electricity markets.
 In February 2018 FERC unanimously
approved Order 841, which had few
substantive changes from the
proposed rules issued under the
earlier NOPR, with the exception that
the second part of the order, involving
aggregation of distributed energy
storage resources, was tabled for
future discussion.
 In May 2019 FERC denied rehearing
requests and upheld the December
2019 time frame.

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FERC Order 841 compliance requirements
The foundational elements of the order were designed to ensure a level playing field for storage
FERC Order 841 requires ISOs and regional transmission organizations (RTOs) to modify their participation rules to ensure
energy storage is eligible to participate in all organized electricity markets. The new rules, comprising the four key areas
highlighted below, ensure that storage will be competing without a market handicap, as was identified by FERC.

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Strategies for resource definitions, the pathway to participation, vary dramatically
Multiple participation models remain the norm, creating a complicated and varied array of rules
Approaches vary in creating, changing, combining or splitting resource types to accommodate energy storage
Single resource definition:
• NYISO: Created Energy Storage Resource as a participation model, but some resources may be forced
to use the existing Energy Limited Resource (ELR) model, which is not directly in compliance with 841.
• MISO: Electric Storage Resource (ESR) will be created.
Multiple resource types:
• CAISO: Made a handful of compliance changes to its existing models
• PJM: Expanded on its Energy Storage Resource (ESR) and Capacity Storage Resource (CSR)
participation models.
• SPP: Created Energy Storage Resource (ESR) and Market Storage Resource (MSR)
On the fence:
• ISO-NE: Use cases are split into Binary and Continuous storage types, along with the existing Alternative
Technology Regulation Resource (ATRR), but the newly defined Electric Storage Facility is designed to
be able to participate as both.

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Eligibility for aggregated resources
• FERC’s initial notice of proposed rulemaking included aggregation, but tabled
• Initial interest suggests eligibility and “level playing field” a priority.
A technology agnostic approach
• FERC has repeatedly shown a desire to not “pick winners”
• Diversity of offerings may make this difficult
Hard pressure on ISOs for complete and timely implementation
A range of approaches varying by ISO
• FERC is comfortably with top-down mandates but bottom-up implementation
• Regulatory variety will be the name of the DER aggregation game
What lessons can we learn from FERC order 841?
If the aggregation question plays out similarly to storage it will be good news for DERs

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Economics of market participation
“Level playing field” doesn’t mean guaranteed success

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Even in the Favorable Case, Capacity Revenue Alone Likely Cannot Sustain a Project
Source: Wood Mackenzie Power & Renewables
Capacity Market Internal Rate of Return by Installation
Year, High Case
-6%
-4%
-2%
0%
2%
4%
6%
8%
10%
12%
2017 2019 2021 2023 2025 2027
InternalRateofReturn
Year of First Capacity Payment
MISO High ISO-NE High NYISO High PJM High CAISO High
Source: Wood Mackenzie Power & Renewables
Capacity Market Internal Rate of Return by Installation Year,
Low Case
-16%
-14%
-12%
-10%
-8%
-6%
-4%
-2%
0%
2017 2019 2021 2023 2025 2027
InternalRateofReturn
Year of First Capacity Payment
MISO Low ISO-NE Low NYISO Low PJM Low CAISO Low

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$0
$2
$4
$6
$8
$10
$12
$14
$16
$18
CAISO 2016 CAISO 2017 ERCOT 2016 ERCOT 2017 SPP 2016 SPP 2017
ClearingPrice($/MWh)
Reg Up RegDown
Single-revenue systems are unlikely to pencil out, which means full participation is the key barrier
Source: Wood Mackenzie Power & Renewables, ISO Data
Average Regulation Clearing Price – ISOs with Up/Down
Signals, 2016 and 2017
$0
$5
$10
$15
$20
$25
$30
ISO-NE MISO NYISO PJM
ClearingPrice($/MWh)
Regulation 2016 Regulation 2017
Source: Wood Mackenzie Power & Renewables, ISO Data
Average Regulation Clearing Prices, Combined Signal ISOs,
2016 and 2017
IRRs range from 10%+
(ISO-NE) to -2% (MISO)
If participants can capture up and down revenue
IRRs fall in the 4-6% range

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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: Wood Mackenzie Power & Renewables, ISO data
Average Hourly LMP by ISO – 2017
Peak hours range from 4 p.m. in ERCOT to 8 p.m. in
CAISO.
Early morning hours (2 a.m. to 5 a.m.) 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

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• CAISO’s unique price curve presents an opportunity for multiple
arbitrage charge/discharge cycles per day.
• CAISO’s morning peak is significantly smaller than its evening
peak, but the additional peak and trough can be captured by
systems up to 4 hours in size.
• Capturing both peaks raises potential daily arbitrage revenue for a
4-hour system to $150.84/MW, up from $131.53/MW when
discharging to meet only the afternoon peak, a difference of
$19.31/MW.
• If the cost of the additional cycle – which would vary based on the
system’s lifetime and degradation rate – is below this $19.31/MW
value, then it may make economic sense for systems already
participating in CAISO’s market to attempt to capture this
secondary peak
Unique system needs may drive DER participation in unexpected ways
CAISO LMP Curve, 2017 Prices, and 4-Hour Arbitrage
Dispatch Pattern
0
10
20
30
40
50
60
70
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
AverageHourlyLMP($/MWh),CAISO,2017Prices
Hour Ending
Charging
Discharging

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“Building” the future of DERs in wholesale markets
Will diverse ecosystems and environments once again
converge to a global efficient solution?

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DER implementation will continue to vary dramatically by region
Source: CAISO, ERCOT, ISO NE, MISO, NYISO, PJM, SPP
9%
3%
14%
5%
6%
15%
48%
40%
31%
3%
20%
2%
4%
54%
0%
3%
27%
16%
24%
48%
16%
8% 2%
2%
45%
3%14%
5%
23%
10%
51%
22%
6%
21%
36%
34%
19%
6%
5%
Natural gas
Coal
Nuclear
Renewables
Oil
Hydro
Other
Dual Fuel

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Demand side resources clear 3% to 10% of the market
…and this is just what participates in organized wholesale markets
Source: Wood Mackenzie Power & Renewables “US Wholesale DER Aggregation”
41%
35%
8%
5%
5% 4%
2%
32 GW
Manufacturing
Batteries
HVAC
Water
Heaters
Lighting
Misc. Loads
Generator
Growth opportunities
EV charging A lot of batteries
Connected home
Microgrids
Resource mix today

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Scale
State-level
programs and
mandates
Increasing cost
competitiveness
ISO-level eligibility design
FERC-mandated DER aggregation eligibility
Drivers for DER participation in wholesale markets moving forward
Getting on the
field
Competing, learning,
adapting, proving success
“Winning” and the transition and
eventual transformation of the grid

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Aggregate
• Distributed generation
• Energy Storage
• Demand-side
resources
Cement
• Software
• Competitive markets
• Physical and virtual
grid services
Water
• Incentives and
mandates
• Ensured eligibility
• Ease of operations
Making concrete – moving towards the “transitional” DER-heavy grid
Three main components needed to make concrete:

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Aggregate
• Distributed generation
• Energy Storage
• Demand-side resources
• New “generation”
technology – i.e. longer
duration storage
Cement
• Software
• Competitive markets
• Physical and virtual grid
services
• Bottom-up user
behavior adaptation
Water
• Incentives and
mandates
• Ensured eligibility
• Ease of operations
• “Next-level” state-level
resiliency and clean-
energy goals
Rebar
• Machine learning
optimization
• High-voltage
transmission
• Mobile energy
• ???
Reinforcing concrete – the “transformational” grid will build off the lessons learned
from the “transitional”
The fourth component reinforces concrete’s strength and compensates for its weaknesses

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Thank You!
Daniel Finn-Foley
Principal Analyst, Energy Storage
daniel.finn-foley@woodmac.com