The Great Battery Race · by 2020 and utilities/IPPS such as SCE, EIX, NEE and AES are moving...

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Brian Lee, CFA (917) 343-3110 [email protected], Sachs & Co.

Patrick Archambault, CFA (212) 902-2817 [email protected], Sachs & Co.

Grid-scale power storage -- long a “holy grail” for renewable energy -- is gaining momentum as an investable theme. From Tesla’s ‘Gigafactory’ to investments by utilities and mandates from regulators, a confluence of drivers is accelerating efforts to cost effectively store power for the electric grid. Battery technology is at the center of this potentially seismic shift in how the grid operates, and in this report we attempt to pinpoint the applications, technologies and companies across our global coverage where we see the most opportunity.

Robert Koort, CFA (713) 654-8480 [email protected], Sachs & Co.

Michael Lapides (212) 357-6307 [email protected], Sachs & Co.

Ikuo Matsuhashi, CMA +81(3)6437-9860 [email protected] Sachs Japan Co., Ltd.

The Great Battery RaceFraming the next frontier in clean technology – Electrical Energy Storage

EQUITY RESEARCH October 18, 2015

Masaru Sugiyama +81(3)[email protected] Sachs Japan Co., Ltd.

October 18, 2015 Global: Clean Energy

Goldman Sachs Global Investment Research 2

Table of Contents

PM Summary: The Great Battery Race 3

Energy storage: Tapping into the next frontier for the electric grid 8

Industry evolution at-a-glance: From gadget to grid 9

Key applications: We estimate a long-term TAM of ~$100-$150bn 13 Backup Power: $1-$1.5bn 15 Peak shaving: $45-$71bn 15 Renewables integration: $20-$32bn 21 Ancillary services: $11-$17bn 22 T&D deferral: $16-$26bn 24 Bulk storage: $5-$7bn 25

Technology overview: No one size fits all – we expect multiple winners 27 Levelized cost of storage – a look at the economics 28 Lithium ion – the early horse in the race 30 Flow – the elephant in the room for Li-ion evangelicals 36 NaS (Sodium Sulfur) – Promising power but islanded due to supplier concentration 38

Stocks with exposure across the value chain 40 Albemarle Corp. (ALB, CL-Buy) 40 FMC (FMC, Neutral) 40 NEC (6701.T, CL-Buy) 41 NGK Insulators (5333.T, Neutral) 41 Panasonic (6752.T, Neutral) 42 Samsung SDI (006400.KS, Neutral) 42 Sungrow (300274.SZ, Neutral) 43 SolarEdge (SEDG, Buy) 43 Sumitomo Electric (5802.T, Neutral) 44 Tesla (TSLA, Neutral) 44 SolarCity (SCTY, CL-Buy) 45

Private companies to watch 46

Appendix 47 What is a battery: Tech mechanics 101 47 Glossary of terms 51

Disclosure Appendix 52



PM Summary: The Great Battery Race

The US electric grid is evolving. Renewables growth, coal-to-gas substitution, T&D-skewed capex budgets and the emergence of distributed generation are all key factors to consider in the electric grid of the future. At the same time, power is the one commodity, to date, that has not been stored at scale. We expect battery technology to begin changing that equation – and the way the grid operates – in a significant way in coming years, representing a potentially immense next frontier in clean technology: energy storage for the electrical grid (not for consumer electronics or autos). Like other clean technologies before it, we see energy storage implications as far-reaching across multiple sectors, including power/utilities, as well as technology, chemicals industries, and even oil/gas/commodities over time. With this report, we provide our analysis of the opportunity set in the US and attempt to pinpoint for investors the applications, technologies, and companies across our global coverage where we see most potential.

Key findings 1. The opportunity is massive… and virtually untapped. Demand for batteries is dominated by consumer electronics today.

That said, larger-scale formats are increasingly taking share and nowhere is this more evident than in the automotive space, where our global Autos research team forecasts electrification of the fleet to hit 25% of auto sales by 2025 vs. 5% in 2015. In battery terms, we estimate this would equate to a robust 42% volume CAGR over the next decade, with battery demand from autos reaching ~175GWh and far eclipsing the 40GWh of batteries consumed by consumer electronics today. For batteries on the grid, the opportunity may be even larger longer-term, though timing is likely more uncertain. We estimate a secular shift to an IoT-driven power grid could require as much as 750GWh of batteries, bigger than all markets combined and equal to a TAM of $100-$150bn. Within the power landscape, energy storage has seen nascent deployment of 600MW, to date – again, a tiny fraction of the over 1,000GWs of total US generation capacity on the grid today.

2. Several applications are “in the money” today. We identify six applications that we believe investors should focus on: Backup power, Peak shaving, Renewables integration, Ancillary services, T&D deferral, and Bulk storage. In the near-to-medium term, we see peak shaving and renewables integration as particularly noteworthy given scale of the opportunities (~2/3 of overall TAM combined), compelling economics, and potential timing of adoption. Longer-term, we note the ability for battery technologies to lower costs and extend storage duration will increasingly expand the opportunity set as more applications across the grid become monetizable.

3. No one size fits all winners for battery technologies. While we focus on Li-ion in this report given its maturity and early lead, we also highlight several other technologies which we believe hold medium-to-long term promise and/or have reached some level of commerciality in grid applications: Flow batteries, sodium-sulfur (NaS), among others. Targeted performance varies widely by application, creating a backdrop where we expect multiple technologies will likely penetrate the various parts of the market (e.g. Li-ion for short duration, flow for long-duration as an example).

4. The “game-changer” may still be undiscovered. We note hundreds of companies are pursuing grid-scale batteries across a number of different chemistries – in many cases, following years of R&D for consumer applications that are now increasingly finding cross-application usage. While Li-ion backed by a handful of larger-scale players from the traditional technology arena appears to be first in scaling up, we believe steady growth in private and VC funding also suggests a large breadth of potentially new technologies will impact the competitive landscape over time. We include a list of private companies in the space on page 46.



Exhibit 1: We estimate the TAM for EES could exceed that of all other end markets combined over the longer-term, though timing is less certain Market size by battery end market, in GWh

Exhibit 2: Our analysis suggests a $100-$150bn TAM for EES across a number of key applications in the US TAM analysis by application

Source: DOE, EPRI, Avicenne, Goldman Sachs Global Investment Research.

Source: Goldman Sachs Global Investment Research.

Why now? Grid scale storage is not necessarily new and has been considered a “holy grail” of sorts for the renewables and power markets for years. While investable opportunities still remain limited, we are encouraged by a landscape that we see as increasingly ripe for broader traction in this nascent, but potentially massive end market; (1) supply is emerging – Tesla is building purpose-built energy storage capacity at Gigafactory, (2) renewables, including distributed resources, continue to gain momentum – solar plus storage at SolarCity, renewables integration on the grid, and (3) even policy measures are brewing – California is mandating 1.3GW of storage by 2020 and utilities/IPPS such as SCE, EIX, NEE and AES are moving forward with initial forays into energy storage deployment. Specifically, SCE awarded the largest single energy storage procurement, to date, in late 2014 for 250MW, while NEE recently announced plans to spend $100mn on energy storage systems in the next year. All told, we believe 2015 will be a record year for US deployment of energy storage on the grid – though absolute volumes remain low.

A number of developments are positioned to further support this movement for grid-scale storage. These include the following.

Costs are set to come down meaningfully. Driven by increasing scale and manufacturing efficiencies, we believe battery prices are set to halve over the next decade.

Technology performance has improved. Industry startups suggest commercial batteries in Li-ion are now being configured for up to 50k cycles, well above current norms. We see 2017-18 as a turning point for the Li-ion battery industry – Nissan and LG Chem plan to substantially raise energy density.

0.6 5 840

176

789741

0

100

200

300

400

500

600

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800

900

EESbatteriesinstalled

base

EVs in theUS(current)

Total EESinstalled

base

Consumerelectronics

EVs(forecast by

2025)

EVs(at 100%

penetration)

Total EESTAM

(potential)

Low High

Total EES TAM ($bn)

Total EES TAM ($bn)

Backup power $1 $1Peak shaving $45 $71Renewables integration $20 $32Ancillary services $11 $17T&D deferral $16 $26Bulk storage $5 $7

TOTAL $97 $155



Applications are "in the money" today. Our discussions with various industry participants and cost analyses suggest several grid-scale opportunities are addressable even on today’s costs: voltage regulation in PJM markets (due to high pricing), T&D deferral, demand charge reduction / peak shaving in certain locales, among others.

Renewables are getting big on the grid. We forecast renewables – mostly wind and solar – to double as a percentage of the US electricity generation mix over the next decade, from 7% in 2014 to 14% by 2025. This higher proportion of intermittent resources on the grid will require smoothing, integration and dispatch-ability provided by storage.

Funding remains steady. Similar to other emerging clean technologies over the past decade-plus, energy storage is seeing steady growth of private and VC funding, albeit still at lower absolute dollar levels than solar.

Policy support is emerging. While still relatively selective, the US has been a leader following California’s energy storage mandate introduced in October 2013.

The ecosystem is getting built. In addition to the battery OEMs, system integrators and developers, as well as software providers, are increasingly emerging to focus on building comprehensive battery management solutions for various applications across the grid.

Exhibit 3: GS author list

Clean Energy Autos & Auto Parts Chemicals UtilitiesBrian Lee, CFA Patrick Archambault, CFA Robert Koort, CFA Michael Lapides(917) 343‐3110 (212) 902‐2817 (713) 654‐8480 (212) 357‐[email protected] [email protected] [email protected] [email protected], Sachs & Co. Goldman, Sachs & Co. Goldman, Sachs & Co. Goldman, Sachs & Co.

Hank Elder David Tamberrino, CFA Brian Maguire, CFA David Fishman(801) 884‐4681 (212) 357‐7617 (713) 654‐8483 (917) 343‐[email protected] [email protected] [email protected] [email protected], Sachs & Co. Goldman, Sachs & Co. Goldman, Sachs & Co. Goldman, Sachs & Co.

Ryan Berney(713) 654‐[email protected], Sachs & Co.

Asia Pacific Energy Autos & Auto Parts Electronic Components Japan Consumer Electronics Japan Integrated ElectricalsFrank He Kota Yuzawa Daiki Takayama Masaru Sugiyama Ikuo Matsuhashi, CMA+86(21)2401‐8925 +81(3)6437‐9863 +81(3)6437‐9870 +81(3)6437‐4691 +81(3)6437‐[email protected] [email protected] [email protected] [email protected] [email protected] Gao Hua Securities Company Limited Goldman Sachs Japan Co., Ltd. Goldman Sachs Japan Co., Ltd. Goldman Sachs Japan Co., Ltd. Goldman Sachs Japan Co., Ltd.

Yang Liu Yipeng Yang Takafumi Hara Yukiko Nonami Takehiro Akamatsu+86(21)2401‐8935 +86(10)6627‐3189 +81(3)6437‐9926 +81(3)6437‐9933 +81(3)6437‐[email protected] [email protected] [email protected] [email protected] [email protected] GBeijing Gao Hua Securities Company Limited Beijing Gao Hua Securities Company Limited Goldman Sachs Japan Co., Ltd. Goldman Sachs Japan Co., Ltd. Goldman Sachs Japan Co., Ltd.

Toshihide Kinoshita Hideaki Mitani+81(3)6437‐9934 +81(3)6437‐[email protected] [email protected] Sachs Japan Co., Ltd. Goldman Sachs Japan Co., Ltd.

Wataru Matsuzaki Marcus Shin+81(3)6437‐9877 +82(2)3788‐[email protected] [email protected] Sachs Japan Co., Ltd. Goldman Sachs (Asia) L.L.C.

Asia

Americas



11 global stocks with leverage to the theme We highlight 11 companies – material producers, manufacturers, and downstream customers – covered by GS which have exposure to the emerging electrical energy storage opportunity.

Exhibit 4: Across our global coverage, we highlight several stocks with exposure to the emerging energy storage opportunity GS covered companies exposed to the grid-scale battery market

Note: ALB, NEC and SCTY are on the respective regional Conviction Lists.

Source: FactSet, Goldman Sachs Global Investment Research.

Position in value chain Company Ticker

Market Cap(in $mn) Price

Price Target (12-mo) Analyst Rating

Technology Exposure

Energy storage sales exposure

Business description

Albemarle Corp.

ALB $5,796 $51.47 $63.00 Bob Koort Buy Lithium ionLithium

producer

FMC Corp. FMC $5,114 $38.05 $37.00Brian

MaguireNeutral Lithium ion

Lithium producer

NEC 6701.T $8,705 ¥397 ¥530Ikuo

MatsuhashiBuy

ICT, charging, energy

Battery manufacturer

NGK Insulators, Inc

5333.T $6,674 ¥2,422 ¥2,490Daiki

TakayamaNeutral

Sodium Sulfur


Panasonic 6752.T $25,430 ¥1,304 ¥1,300Masaru

Sugiyama Neutral Lithium ion


Samsung SDI 006400.KS $6,632 ₩106,500 ₩120,000 Marcus Shin Neutral Lithium ion Battery manufacturer

SolarEdge SEDG $1,054 $23.69 $37.00 Brian Lee BuyPrimarily

lithium ionInverter

manufacturerSumitomo

Electric5802.T $11,304 ¥1,689 ¥1,800

Ikuo Matsuhashi

Neutral FlowBattery

manufacturer

Sungrow 300274.SZ $2,904 Rmb 28.00 Rmb 23.70 Frank He Neutral Lithium ionInverter

manufacturer

Tesla* TSLA $31,591 $221.31 $234.00Pat

ArchambaultNeutral Lithium ion

EV, EES manufacturer

SolarCity SCTY $4,926 $46.65 $79.00 Brian Lee BuyPrimarily

lithium ionSolar installer

*6-month price target 5% or less 5% to 20% 20% to 50% 50% or greater

Materials

Downstream

OEMs/ manufacturers



Energy storage: Tapping into the next frontier for the electric grid

Generation (supply) equals load (demand). In the electricity markets, this has always been a fundamental principle. This owes to the electric grid being developed over time to provide just-in-time delivery of power. However, with demand for power varying throughout the day and also seasonally, the supply of power across the grid must be built to a sufficient level of capacity to not only satisfy baseline demand, but also peak demand incurred on what is likely only a few days of the year (e.g. hottest days of summer).

Herein lies the opportunity for energy storage on the grid. In the case of electrical energy storage (EES), electricity generated by coal, gas, renewables or other power-gen resources is stored and consumed at a later time, either when the sun is down, the grid is facing high demand, or fuel is not readily available. Without storage, meeting peak electricity demand requires enough generation capacity to be built out to produce exactly what is being consumed at any given time. Additionally, given the rapid start-up time of certain batteries, the ability to provide grid reliability and regulate frequency/voltage on a short-term basis also adds to the value of storage.

We expect batteries to play a big role in EES. Electric vehicles have begun to prove the scale, reliability, and cost potential of battery technology. By 2025, our Autos research team estimates ~25% of the global fleet will be electrified vs. 5% in 2015, consuming ~175GWh of batteries. This would equate to a 42% volume demand CAGR from just this segment alone over the next decade, far surpassing demand from consumer electronics. Longer-term, we estimate the total available market for EES could be just as big, if not bigger, at a $100-$150bn TAM. While market development remains early stage, and will likely require regulatory reform over time, we see energy storage’s vast potential as promising given growing policy, funding and R&D support – and see it poised as a major disruptive clean technology in the coming decade. Note, throughout this report, our focus is on the US market opportunity.

Exhibit 5: While commercialization and installed bases remain in their infancy, we see promise in (1) Li-ion, (2) NaS, and (3) Flow technologies for the emerging EES opportunity Energy storage technologies, size denotes installed base (not to scale)

Source: BNEF, Goldman Sachs Global Investment Research.

We refer to energy storage for power grid applications as EES throughout this report See the note from our global autos research team, Cars 2025: Vol. 2: Solving CO2 – Engines, Batteries and Fuel Cells; published on August 5, 2015



Industry evolution at-a-glance: From gadget to grid

A $25bn market…dominated by gadgets. While batteries have been prevalent for decades across a number of end markets, we note the dominant application, to date, has been consumer electronics since Sony first commercialized lithium-ion (Li-ion) technology in the 1990s. Demand in this segment accounts for over 40GWh. More recently, commercialization of electric vehicles has contributed to the 5% CAGR of the Li-ion battery market over the past decade and a half, expanding the total Li-ion battery market to $25bn collectively. In volume terms, increasing proliferation of electric vehicles (EVs) accounts for ~5-6GWh of demand with this figure estimated to grow to roughly ~175GWh by 2025 based on EV penetration forecasts from our Autos research team.

Batteries coming to a grid near you, though the grid-scale story is not totally new... Historically, energy storage in the electricity industry has typically taken the form of pumped hydro or compressed air energy storage (CAES), both of which are geographically constrained and where new funding appears limited. In recent years, the industry has seen a meaningful uptick in R&D into the use of batteries, particularly Li-ion, in larger-format applications including grid-scale. Compared to other verticals, batteries for the electric grid are in their extreme infancy, however. Roughly 600MW are installed on the global grid today.

…and are just reaching commercialization in many cases. That said, years of R&D for consumer applications are now increasingly finding cross-application usage, and in identifying the opportunity, we note hundreds of companies are pursuing grid-scale batteries across a number of different chemistries. We believe three in particular, show near-to-medium term promise of commercialization: (1) Li-ion, (2) sodium-sulfur (NaS), and (3) Flow. Our detailed analysis of these technologies begins on page 27 of this report, and we include a list of private companies in the space on page 46.

Exhibit 6: Batteries are gaining share in the still-nascent installed base of EESGlobal installed capacity of EES (excl. pumped hydro), 2000-2014

Exhibit 7: While NaS was an early mover, adoption of Li-ion has acceleratedGlobal installed capacity of EES batteries, 2000-2014

Source: BNEF.

Source: BNEF.

0

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800

1,000

1,200

1,400

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

Batteries Flywheels CAES

(MW)

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2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

Li ion

Flow

NaS

Other

Lead-based

(MW)



Why now? Energy storage goes large-scale Framing the next frontier in clean technology. In April 2015, Elon Musk thrust grid-scale storage into the limelight with the unveiling of Tesla Energy – a portfolio of battery products targeting the residential, commercial and utility segments. While the price points for the products, which are as low as $3,000-$3,500 for the smallest, residential configurations at the battery level, attracted significant attention, our industry discussions suggest these price points were largely being achieved by a number of manufacturers. Nevertheless, the Tesla release followed a rapidly emerging build-up in the battery industry that has been playing out somewhat under wraps over the past several years, as researchers and entrepreneurs have attempted to adapt Li-ion to larger scale applications. A number of developments are positioned to further support this movement for grid-scale storage. These include the following.

Costs are set to come down meaningfully. Driven by increasing scale and manufacturing efficiencies, we believe battery prices are set to halve over the next decade. Not unlike technology roadmaps in other sectors (Moore’s Law in semis, Haitz’s Law in LEDs), a key driver of cost reductions is through improved performance – in the case of batteries, increasing energy density or energy produced per unit volume. Higher energy density raises the performance of Li-ion batteries, resulting in an increase in the duration of storage available in one discharge cycle and a reduction in battery costs. The energy density of Li-ion batteries in the early 2010s was 100-150 Wh/kg, but recently some manufacturers have been able to achieve 200-300 Wh/kg. Considerable effort is also being made to improve the performance of anode materials, electrolytes, separators, and other core battery components to make energy density of 300-350 Wh/kg possible by mid 2020s.

Exhibit 8: We expect battery price per watt-hour to halve over the next decade Estimated price of automotive Li-ion batteries

Exhibit 9: Private and VC funding for energy storage continues to see momentum; solar funding appears to have peaked several years ago PE/VC funding for energy storage vs. solar, 2005-2014


Source: BNEF.

0

50

100

150

200

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$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

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$1.60

2009 2011 2013 2015E 2017E 2019E 2021E 2023E 2025E

Price per Wh ($/g, LHS)

Energy density (Wh/kg, RHS)

$0

$1,000

$2,000

$3,000

$4,000

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2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

Energy storage (LHS) Solar (RHS)



Technology performance has improved. Industry startups suggest commercial batteries in Li-ion are now being configured for up to 50k cycles, well above current norms. We believe 2017-18 as a turning point for the Li-ion battery industry – Nissan and LG Chem plan to substantially raise energy density.

Applications are "in the money" today. Our discussions with various industry participants and cost analyses suggest several grid-scale opportunities are addressable even on today’s costs: voltage regulation in PJM markets (due to high pricing), T&D deferral, demand charge reduction / peak shaving in certain locales, among others.

Renewables are getting big on the grid. We forecast renewables – mostly wind and solar – to double as a percentage of the US electricity generation mix over the next decade, from 7% in 2014 to 14% by 2025. This higher proportion of intermittent resources on the grid will require smoothing, integration and dispatch-abilty provided by storage.

Funding remains steady. Similar to other emerging clean technologies over the past decade-plus, energy storage is seeing steady growth of private and VC funding, albeit still at lower absolute dollar levels than solar.

Policy support is emerging. While still relatively selective, the US has been a leader following California’s energy storage mandate introduced in October 2013.

The ecosystem is getting built. In addition to the battery OEMs, system integrators and developers, as well as software providers, are increasingly emerging to focus on building comprehensive battery management solutions for a various set of applications across the grid.



Policy could open up the flood gates Encouragement by state utility regulators could drive an uptick in the deployment of electrical energy storage. In many states, utilities – the local, regulated companies – either have not received permission to invest or deploy energy storage technologies or have not petitioned their regulators to do so. State policies that encourage a gradual roll out of storage by utilities (similar to Renewable Portfolio Standards) could increase the pace of deployment. In this case, regulated utilities would invest in storage and add this to their regulated “rate base” – a driver of their earnings power.

Mandates for utilities to contract energy storage are cropping up across the US. Most notably, California issued a mandate to the state’s three largest IOU’s to procure 1.3GW of storage by 2020, which would more than double the global installed base. California became a leader in the energy storage industry in 2010 by issuing Assembly Bill 2514, calling for a mandate to be put in place that would spur market transformation. Regulations around how to implement this transformation are unfolding. Current legislation stipulates that utilities may own no more than half of the total storage used to meet the 1.3GW mandate, presenting a significant opportunity for merchant ownership. As commercialization continues, we believe this and other specifications could have a direct and profound effect on the market’s evolution. Additionally, in some states, especially those with competitive power markets (Texas, PJM, etc.), clarity does not exist on whether the traditional T&D utilities could invest in storage or not – as there is concern that this would encroach on the regulatory model there, as many deem storage just another form of generation and in these markets, T&D utilities do not provide generation – IPPs own and control power plant production of MWhs. This debate emerged in Texas in 2014 and clarity still does not exist there regarding whether distribution utilities could invest in energy storage.

Exhibit 10: CA has mandated 1.3GW of energy storage by 2020, representing the single biggest policy mechanism focused on energy storage, to date CA energy storage targets, in MW

Exhibit 11: The installed base for energy storage is nearly non-existent compared to the over 1,000GW generation capacity on the US grid Energy storage installs, 1Q/2Q/cumulative vs. total US generation capacity, in MW

Source: DOE.

Source: Company data, Goldman Sachs Global Investment Research.

Energy Storage Procurement Targets (in MW)2014 2016 2018 2020 Total

SCE 90 120 160 210 580Transmission 50 65 85 110 310Distribution 30 40 50 65 185Customer 10 15 25 35 85

PG&E 90 120 160 210 580Transmission 50 65 85 110 310Distribution 30 40 50 65 185Customer 10 15 25 35 85

SDG&E 20 30 45 70 165Transmission 10 15 22 33 80Distribution 7 10 15 23 55Customer 3 5 8 14 30

Total 200 270 365 490 1325

6

41

0

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400,000

600,000

800,000

1,000,000

1,200,000

0

5

10

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20

25

30

35

40

45

1Q15installs

2Q15installs

CumulativeUS energy

storagecapacity

Total USgeneration

capacity

Installed energy storage (ex-

hydro) is 0.0001% of US installed capacity base

152

1,071,000



Key applications: We estimate a long-term TAM of ~$100-$150bn

The US grid provides a multitude of opportunities for batteries. Batteries can address various functionalities across different applications in the electricity market, given the ability to design the technical parameters of the battery to fit particular needs. We note that not all of these solutions can be built to be cost-competitive with incumbent solutions, however, particularly given the relatively high cost of batteries today in these large-scale configurations. Thus, the ability to successfully monetize an investment in EES remains limited in many cases, and the longer-term opportunity is likely to only expand as costs come down.

We identify six applications with near-to-medium term potential. We believe investors should focus on six primary applications – for which we highlight our analysis for the potential TAM in this section. For the purpose of this analysis, we use GS forecasts for battery costs and load growth, while also utilizing assumptions from DOE data. These are outlined on page 49.

(1) Backup power: source of power in the event of the grid being down

(2) Peak shaving: reduction of (i) energy purchased from the grid at more expensive, peak hours, and (ii) peak demand charges

(3) Renewables integration: incorporating intermittent solar and wind generation while maintaining grid reliability/stability

(4) Ancillary services: providing continuous flow of electricity, maintaining grid stability and security

(5) T&D deferral: increase service life of existing T&D; defer upgrades; provide congestion relief at times of peak demand

(6) Bulk storage: wholesale storage to levelize load, add dispatch-ability to generation sources, and provide reserve margins.

Exhibit 12: We identify six key applications across which we expect batteries to achieve increasing penetration once costs and viability are proven EES adoption timeline


2015 2016 2017 2018 2019 2020 2021 2022+

Near-term Medium-term Long-term

Backup (UPS) in developing markets, microgrids

Renewables integration

Ancillary services

Adoption

Resi backup powerC&I peak shaving

manufacturing breakthroughs cut cost

market reform enables monetization

Driven by cost declines

Driven by subsidy & liquidity

T&D deferralBulk storage

T&D: transmission and distribution



Exhibit 13: Our analysis suggests a ~$100-$150bn TAM for EES across a number of key applications in the US TAM analysis by application


Exhibit 14: We summarize six key applications that we expect batteries to address in the electricity market in the near-to-medium term EES applications overview

Source: DOE, BatteryUniversity.com, Goldman Sachs Global Investment Research.

Low High

Total EES TAM ($bn)

Total EES TAM ($bn)

Backup power $1 $1Peak shaving $45 $71Renewables integration $20 $32Ancillary services $11 $17T&D deferral $16 $26Bulk storage $5 $7

TOTAL $97 $155

Bulk storage T&D deferralRenewables integration

Ancillary services Peak shaving Backup power

Customer Utilities, IPPs Utilities, IPPs Utilities, IPPsUtilities, Commercial &

Industrial, IPPsCommercial & Industrial

Residential and Commercial

Monetization scheme

Grid optimization - avoided investment

Deferred grid upgrade investment

Asset optimizationIncremental revenue

streamSavings Intrinsic value

Catalyst for adoption

Industry maturity, regulatory changes

Industry maturity, regulatory changes

Continued solar+wind development

Market revisions and maturity

Demand charges, TOU pricing rate structure

Resiliency concerns

Technologies deployed

NaS, Flow, Batteries NaS, Flow, Batteries NaS, Flow, Batteries NaS, Flow, Batteries Batteries Batteries

Notable deployments

Bosch Braderup ES Facility

Enel Chiaravalle Substation

Invenergy Grand Ridge Wind Farm

AES Angamos Storage Array

Giheung Samsung SDI Project

Drewag Reick

Scale of installation

Large / Centralized Small / Distributed



Backup Power: $1-$1.5bn The EES TAM: While likely one of the most near-term from a timing perspective given Tesla’s Powerwall product introduction and related competition that it is likely to spurn, we see backup power as the least impactful application from a revenue standpoint, given limited economic rationale for investment. For market sizing purposes, we assume the market to mirror the US residential backup generator market.

The EES opportunity: We see no economic case for installing backup power. Batteries can replace diesel generators, but based on cost alone, we find that diesel generators remain the low cost option. However, we note there may be a stronger business case for batteries replacing generators in remote applications where either fuel is unreliable or, in the case of the telecom industry in developing markets, where diesel generators are at high risk of being stolen. In the US specifically, we note backup generators have grown at a steady 15% growth rate historically in the US, and we forecast a long-term CAGR of 8% for market sizing purposes.

Exhibit 15: We estimate the backup generator market will grow at an 8% CAGR over the next several years, implying a battery market opportunity of roughly $1-$2bn Battery TAM for backup power

Exhibit 16: But, we see limited economic rationale for backup power, while costs of battery solutions vs. traditional diesel generators also favor the incumbent, in our view Tesla vs. Generac diesel generator

Source: Generac company data

Source: Company data.

Peak shaving: $45-$71bn The EES TAM: Based on electricity usage of the US commercial sector, we estimate that the total addressable market will range from $45bn-$71bn by 2020, the most significant of any one application.

The EES opportunity: We expect commercial and industrial buildings to be early adopters of large-scale storage, given the structure of a commercial customer’s electricity bill in the US, which is primarily comprised of three parts: a fixed charge (customer charge), a charge based on the maximum intensity of demand (demand charge), and variable consumption (energy charge). By being able to store, and then shift, energy from one time of the day to another, we expect the typical commercial customer to extract value from storage solutions in two main ways:

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8% CAGR

MWh $bn

Size DurationCapacity per unit (peak)

Cost per unit

Total system cost for 48 hrs of

backup

Tesla Powerwall

battery10 kWh 2 to 8 hrs 3.3 kW $3,500 $30,000

Generac Guardian

HSB generator

22 kW Unlimited 22 kW $4,799 $8,000



Energy arbitrage: Take advantage of the intra-day variation in electricity prices (e.g. time of use, or TOU) by purchasing and storing power when grid prices are cheap (e.g. late at night or over the weekends) and drawing down on the batteries when costs are higher.

Demand charge reduction: Smooth out the demand from the grid (e.g. load profile) in order to decrease the maximum demand intensity in a given month, thus decreasing the demand charge portion of the electricity bill. The demand charge represents compensation to the utility for maintaining a sufficient level of capacity for transmission and distribution and is generally calculated based on the highest average kW measured in a 15-minute interval during the billing period.

Below we illustrate the all-in value proposition of storage for a commercial customer and provide an example of a commercial or industrial site’s electricity bill. Depending on the regularity of a site’s electricity usage, we estimate demand charges can make up 30%-70% of a commercial customer’s bills, and peak shaving can dramatically reduce this charge.

Exhibit 17: Lower demand charges, energy arbitrage, and resiliency capability add value for commercial customers Buildup of value proposition for commercial EES

Exhibit 18: We estimate reducing demand charges can eliminate 30%, with upside to even 70% in some cases, of a commercial site’s electricity costs Illustrative composition of a typical commercial or industrial electricity bill



Reduced demand chargeIntraday energyarbitrage backup

capability

Costof so

lar+storage

Cost of electricity from the grid

All‐in value proposition of solar+storagefor commercial customers

Demand charge

Customer charge

Energy charge



Exhibit 19: Early morning hours currently present optimal charging time Hourly electricity cost per kWh throughout the day

Exhibit 20: Demand distribution shifts from peak demand hours to early AM Normal electricity demand distribution vs. altered battery demand distribution

Source: ConEdison, Goldman Sachs Global Investment Research.


A case study for commercial customers: In Exhibit 21, we show a hypothetical illustration of how energy arbitrage would work using a battery system (all-in, including installation) costing $250 per kWh – which we believe is a reasonable all-in cost to assume for Li-ion technology based on Tesla’s Gigafactory cost targets through 2020. Assuming California daily electricity rate patterns, we estimate that the customer would charge the battery during the hours of midnight to 6am, and draw down on the battery from 11am to 6pm when both its needs and the utility costs are highest. In this case, energy arbitrage alone would lead to savings of $3,000 per month, or roughly $22,000 per year assuming demand charges drop off in the winter. With the cost of the system at $100k, this would result in a payback period of roughly 5 years. We highlight that the savings a commercial/ industrial customer is able to achieve from demand charge reduction and TOU shifting is highly variable depending on the specific load characteristics and peak demand of the customer. Customers with more variability in their load profile – perhaps from large bursts of demand when firing up equipment or during elevator rush hour – stand to gain the most from demand charge reduction. However, if a customer is subject to real time pricing, then they can benefit from energy arbitrage to a degree, no matter how steady or flat their load profile.

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0 316091121152182213244274305335366397425456486517547578609639670700731762790821851882912943974

020406080100120140160180

0102030405060708090

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Charging

Draining

C&I: commercial and industrial



Exhibit 21: We estimate a 5-year payback period and $22,000 annual savings from demand charge reductions and time-of-use energy arbitrage; our estimates assume Li-ion technology and that Tesla’s Gigafactory cost reductions approach $100/kWh by 2020 Stationary storage example for a commercial customer in CA

Source: PG&E, Goldman Sachs Global Investment Research.

Total bundled kWh cost

Normal kWh demand

distribution

Hourly kWh

demand

Hourly energy cost

kWh demand distribution with

batteryDaily kWh

Battery usage

Hourly energy cost

12am-1am 0.070$ 1.0% 10 0.70$ 7.5% 75 65 5.25$ 1am-2am 0.070$ 1.0% 10 0.70$ 7.5% 75 65 5.25$ 2am-3am 0.070$ 1.0% 10 0.70$ 7.5% 75 65 5.25$ 3am-4am 0.070$ 1.0% 10 0.70$ 7.5% 75 65 5.25$ 4am-5am 0.070$ 1.0% 10 0.70$ 7.5% 75 65 5.25$ 5am-6am 0.070$ 2.0% 20 1.40$ 7.5% 75 55 5.25$ 6am-7am 0.070$ 3.0% 30 2.10$ 3.0% 30 0 2.10$ 7am-8am 0.070$ 5.0% 50 3.50$ 5.0% 50 0 3.50$ 8am-9am 0.095$ 8.0% 80 7.60$ 8.0% 80 0 7.60$ 9am-10am 0.095$ 8.0% 80 7.60$ 8.0% 80 0 7.60$ 10am-11am 0.095$ 8.0% 80 7.60$ 8.0% 80 0 7.60$ 11am-12am 0.095$ 8.0% 80 7.60$ 6.0% 60 -20 5.70$ 12pm-1pm 0.130$ 8.0% 80 10.40$ 1.5% 15 -65 1.95$ 1pm-2pm 0.130$ 8.0% 80 10.40$ 1.5% 15 -65 1.95$ 2pm-3pm 0.130$ 8.0% 80 10.40$ 1.5% 15 -65 1.95$ 3pm-4pm 0.130$ 8.0% 80 10.40$ 1.5% 15 -65 1.95$ 4pm-5pm 0.130$ 8.0% 80 10.40$ 1.5% 15 -65 1.95$ 5pm-6pm 0.130$ 5.0% 50 6.50$ 1.5% 15 -35 1.95$ 6pm-7pm 0.095$ 3.0% 30 2.85$ 3.0% 30 0 2.85$ 7pm-8pm 0.095$ 1.0% 10 0.95$ 1.0% 10 0 0.95$ 8pm-9pm 0.095$ 1.0% 10 0.95$ 1.0% 10 0 0.95$ 9pm-10pm 0.095$ 1.0% 10 0.95$ 1.0% 10 0 0.95$ 10pm-11pm 0.070$ 1.0% 10 0.70$ 1.0% 10 0 0.70$ 11pm-12am 0.070$ 1.0% 10 0.70$ 1.0% 10 0 0.70$

Total 1,000 106.50$ 1,000 0 84.40$ Daily savings 22.10$

Standard Monthly Bill 20.8%Charge/kw Storage Monthly Bill

Peak Demand kW 200 $15 2918 Battery capacity kW 200Partial Peak kW 175 $3 597 Peak reduction potential 160 Charge/kwMax Peak kW 200 $12 2370 Peak Demand kW 40 $15 584

Monthly demand charge $5,885 Partial Peak kW 175 $3 597Energy cost $3,195 Max Peak kW 200 $12 2370Total Monthly Bill $9,080 Monthly demand charge $3,550

Energy cost $2,532Battery capacity Kwh 400 Total Monthly Bill $6,082Cost/kwh 250$ Total cost 100,000$ Total Savings $2,997Annual savings 22,073$ Savings from shifting $663Payback period in years 5 Savings from demand charge $2,334



Exhibit 22: We see energy storage offering compelling economics for peak shaving in a broad array of states… Estimated IRRs based on TOU and demand rates; analysis assumes one major utility rate structure in each state and is not necessarily representative of all utilities in the state

Exhibit 23: …which opens large C&I electricity usage opportunities up to battery markets C&I electricity usage by state


Source: EIA.

Exhibit 24: C&I customers in the US receive time-of-use pricing; we believe residential could follow suit over time, albeit gradually Time of use differentials

Source: CPUC.

NV, 7%FL, 7%

WI, 12%MS, 13%

AL, 15%

PA, 16%GA, 17%

NY, 18% AZ, 18%

CA, 22%

NV, ‐1%FL, 0%

WI, 3%

MS, 4%

AL, 5%PA, 6%

GA, 6% NY, 7%AZ, 7%

CA, 9%

‐5%

0%

5%

10%

15%

20%

25%IRR at 2020 costs

IRR at today's costs

0

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NV MS AL WI AZ PA GA NY FL CA

MWhs

Study Off-peak ($) On-peak ($) Price ratiokW peak

reduction/ participant

Peak load reduction

Average usage

Opt-in/ Default

Enabling technology

Total customers

APS 2 21 10.5 0.2 5% 3.8 Opt-in no 1,200,000 EDF 4.6 5.8 1.3 1 45% 2.2 Opt-in no 5,700,000 OGE 4.2 23 5.5 1.5 11% 5 Opt-in yes 750,000 SRP 7.2 21.2 2.9 1.4 11%-13% 9.9 Opt-in no 970,000

ENEL 2.99 12.42 4.2 0 1% 0.6 Default no 25,000,000 Hydro One 5.3 10.2 1.9 0 3% 1.2 Default yes 4,500,000



The case is weaker for residential customers: Unlike C&I, the majority of residential utility bills are calculated at a flat rate, not real-time pricing, and do not include a significant demand charge component. Under these circumstances, we see no incremental value stream from storage. This owes to the fact that the levelized cost of storage is far above the cost of electricity today and also applies in the case of solar plus storage as the cost of storage is simply additive and detracts from the cost savings enabled by solar. We expect solar plus storage could become broadly cost-competitive across the US utility grid approaching 2025, with certain higher-cost states like Hawaii (already “in the money”), New York and California reaching parity several years earlier (Exhibit 25).

Additionally, for residential solar customers subject to net metering policy, the grid serves as a low-cost virtual battery, enabling customers to sell back excess energy to the grid and repurchase it at a later time, at the same price. However, we expect more and more utilities to introduce real-time pricing for residential customers, which would enable homeowners to take advantage of energy arbitrage similar to commercial customers. In the recent California residential rate redesign, the state regulator included a provision requiring investor owned utilities to introduce pilots for residential time-of-use pricing. New York currently offers opt-in TOU pricing and Massachusetts is in the process of finalizing a default time varying rate structure, while Tennessee Valley Authority is considering adding time variable rate options for their 9 million+ customers.

Exhibit 25: Solar plus storage in the residential market will reach breakeven in certain states earlier, but we see broad cost-competitiveness in 2025 Resi solar plus storage vs. projected grid cost per kWh

Exhibit 26: Our analysis suggests it could be 10+ years before solar plus storage becomes economically viable across the US grid in residential Summary of resi solar plus storage economics

Source: Company data, Goldman Sachs Global Investment Research, EIA.


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2015

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2031

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2033

Total USImplied cost per kWhCAHIAZNYNJ

HI

NY

CANJ

AZ

Solar + storage economics 2015E 2020E 2025E 2030E

Battery system (incl. BoS)

Size of system - KWh 10 10 10 10Price of system - $/Kwh $700 $311 $138 $61

Total battery system price $7,000 $3,106 $1,378 $611

Solar system

Total purchase price (ex-ITC) $24,973 $25,158 $19,712 $15,445

Total system cost $31,973 $28,264 $21,090 $16,056

Implied cost per kWh $0.23 $0.21 $0.15 $0.12

Average US electricity cost - $/kwh $0.13 $0.15 $0.17 $0.20 Annual grid cost increase 2.8% 2.8% 2.8% 2.8%



Renewables integration: $20-$32bn The EES TAM: Based on a more than doubling of renewable energy capacity in the US over the next decade – largely to meet state Renewable Portfolio Standards (RPS) – we estimate the total addressable market for renewables integration to be $20bn-$32bn.

The EES opportunity: Renewables are intermittent – the wind blows hardest during certain times of the day and the sun only shines during a finite window. For the grid, this adds uncertainty in scheduling which power plants to run and which to curtail at any given time and this can result in frequent curtailment as well as grid instability, if not managed. Similarly, overgeneration can occur in particularly sunny or windy hours, not necessarily when there is demand for the electricity. Wind and solar plant owners subject to curtailment during periods of overgeneration are able to use storage to smooth out when they deliver energy to the grid, and thus the business case for storage can be considered via the probable loss from curtailment that would occur in a business-as-usual scenario. Moreover, renewables can participate in price arbitrage if able to store energy to simply monetize at peak demand times.

Exhibit 27: Renewables (ex-hydro) are 7% of generation… US total generation mix in 2014

Exhibit 28: …going to at least 14% by 2025 to hit RPS US total generation mix in 2025

Source: Goldman Sachs Global Investment Research, EIA.


7%3%

3%

39%27%

19%

0%

2014

Renwables ex-Hydro

Qualifying Hydro

Nonqualifying Hydro

Coal

Natural Gas

Nuclear

Petroleum Liquids

14%

3%

3%

30%30%

19%

0%

2025

Renwables ex-Hydro

Qualifying Hydro

Nonqualifying Hydro

Coal

Natural Gas

Nuclear

Petroleum Liquids

See our note, Headed to 100 GW: How state policy will drive US renewables growth through 2025; published on March 26, 2015



Exhibit 29: As renewable penetration grows, storage has the opportunity to better align total load and renewables’ intermittent and varied generation profile 5/17/2015 CA load and renewable production, 12:00am – 12:00am

Exhibit 30: We forecast 65GW of renewables to be added in order to meet state RPS by 2020, implying $20bn-$32bn total TAM if storage were to be deployed at all new installations Incremental annual renewable GWh vs. implied battery capacity MWh vs. TAM ($ mn)

Source: CAISO.


Ancillary services: $11-$17bn The EES TAM: We expect storage to perform multiple ancillary services, such as load following, reserve capacity, and voltage regulation, among others. We estimate that the total addressable market for ancillary services will range from $11bn-$17bn.

The EES opportunity: In order for the grid to continue to operate without interruption, generation must equal load at all times and all disruptions must be corrected within seconds to avoid outages. Even then, line losses – wasted energy owing to T&D deficiencies – have approached nearly 10% annually based on EIA data. To ensure system stability, grid operators send signals to step up or step down generation on very short notice. Given that batteries are able to start up quickly and respond to these signals more promptly and accurately than generators, the opportunity for providing ancillary services is likely enhanced. Moreover, we note batteries can provide added value to the grid given their flexibility to cover a broad range of these services – not simply one – on an as-needed basis.

FERC classifies ancillary as “services that help support the reliable and safe transmission of power from producer to consumer.”

Frequency regulation: Balancing of electricity on the grid to maintain frequency with operational bounds, to enable delivery in a narrow frequency range (60 Hertz).

Voltage control: Similar to frequency regulation but relies on reactive power rather than real power to maintain proper voltage on the transmission grid.

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Wind production$20bn-$32bn

147,000 MWh

FERC: Federal Energy Regulatory Commission



Spinning reserve: Capacity that is not currently producing but is connected to the grid and therefore able to respond to signals within 10 minutes.

Non-spinning reserve: Capacity that can respond to signals only after a slight delay.

Black start: Ability to restore power after a grid outage occurs.

FERC Order 755: Before FERC Order 755 was implemented, most independent system operators (ISO) used capacity payments to compensate providers of frequency regulation services. Slow responders were compensated the same as fast responders which the FERC decided was unjust and inefficient. In 2011, Order 755 was issued, requiring compensation for regulation resources to be based on the actual amount of service provided – “pay-for-performance.” Each ISO is in the process of implementing this change.

Exhibit 31: Instability on the electric power grid can occur in a matter of seconds and frequency regulation needs can be immediate Illustration of frequency response services (in seconds)

Exhibit 32: Energy storage is called upon more often to perform frequency regulation, because of its quick response time. Now, it is compensated accordingly for this “mileage” in addition to standard capacity payments. Simplified PJM two-part payment mechanism for frequency regulation

Source: PJM, Goldman Sachs Global Investment Research.

Source: PJM.

1 2 3 4 5 6 7

Gen

erat

ion

(M

W)

Desired electrical frequencyEnergy storage following frequencyGeneration output

HISTORICAL MILEAGEActual MWh of service 4

CAPACITY BID

Maximum capability offered $12.00

MAXIMUM PERFORMANCE OFFER

(Capacity payments + adders)/Mileage $1.21

Performance* Mileage + Capability $16.82

PJM Two-part payment scheme

**Mileage refers to the amount an asset was called upon to perform grid services.



Exhibit 33: Line losses have averaged close to 10% historically, though this figure has trended lower in recent years Line losses as % of total US generation

Exhibit 34: In revenue terms, we estimate roughly $14-$18bn in lost revenue due to line losses annually for the power sector; for illustrative purposes, a 5% reduction in these line losses could save $700-$900mn annually or $7-$9bn over 10 years (typical energy storage lifetime) Revenue lost due to line losses and 5% reduction sensitivity analysis

Source: EIA, Goldman Sachs Global Investment Research.

Source: EIA, Goldman Sachs Global Investment Research.

T&D deferral: $16-$26bn The EES TAM: We consider T&D deferral to be an attractive opportunity, but believe commercial acceptance of EES technology and maturity of policy developments are required before the market truly opens up. We estimate that the total addressable market for T&D, including assets built for general congestion relief, will range from $16bn-$26bn.

The EES opportunity: Electric utilities plan to invest an estimated $50-$80bn on traditional grid infrastructure – generation, transmission, and distribution – annually for the next 15 years, largely in an attempt to correct years of underinvestment. Energy storage stands to disrupt traditional planning (spending) models. By co-locating a battery with aging transmission infrastructure, utilities will be able to delay making substantial investments, and by postponing investments, utilities can then gain better visibility into forecasted load growth. Moreover, as EES technologies become more commercially proven, utilities will likely be forced to increasingly consider storage as a potentially more cost-effective alternative to provide incremental capacity – particularly given the large investment that is typical of T&D. Another avenue for batteries to enable T&D deferral is by providing transmission congestion relief – which entails locating the storage resource downstream of a bottleneck to deliver electricity in times of congestion. The economic benefits of this are potentially twofold, as (1) a smaller capital investment in storage can provide congestion without upgrading a broad swath of T&D infrastructure owing to just one or two congested nodes on the grid, while also providing (2) avoidance of congestion charges which are assessed by certain ISOs.

10.4% 10.0% 10.7%

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Policy-wise, a number of regulatory developments have positioned energy storage to have a greater role in T&D deferral.

FERC Order 888: Established open, non-discriminatory access to utility-owned transmission infrastructure

FERC Order 890: Established “an open, transparent, and coordinated transmission planning process”

FERC Order 1000: Requires planners to give non-transmission alternatives (example: batteries) comparable consideration

Together, these have changed how utilities go about T&D planning and investments. Public utility transmission providers are now required to publicly post their evaluation criteria and rationale for opting for an investment in light of alternative options. Although this is not an inherent incentive to invest in new technologies, this might open up the opportunity for grid-scale batteries over time.

Exhibit 35: Grid-related capital expenditures have continued to increase steadily… Transmission spending vs. TLRs, 1997-2012

Exhibit 36: …and are forecasted to remain relatively high in coming years owing to a combination of expansion and upgrades Projected T&D spending by application, 2014E-2017E

Source: NERC, EEI, Goldman Sachs Global Investment Research.

Source: EEI.

Bulk storage: $5-$7bn The EES TAM: Bulk storage, which many stakeholders believe will represent the bulk of the EES opportunity in the long term, is the application with the least visibility today, in our view. Investment scale is likely to be greatest and thus visibility into how utilities will be compensated will require greater clarity (e.g. can energy storage be put into the rate base?). We estimate that the total addressable market for bulk storage will range from $5bn-$7bn by 2020.

The EES opportunity: While bulk storage applications could encompass a number of different options over time, we consider two categories in our analysis given visibility into economics and based on our discussions with industry participants: alternatives for natural gas peak capacity and large-scale transmission support.

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TLRs $bnHigh mix of renewables integration T&D

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Other Security Adv TechImprovements Replacement Expansion



Peaker replacement: As it stands, natural gas peaker plants are built with the expectation that they will only run less than 100 hours per year, when demand reaches its peak. As an alternative, batteries can discharge electricity during those peak times, making the additional gas capacity unnecessary. Recently, the CEO of NEE – one of the world’s largest utilities – offered this endorsement for storage vs. peakers at an analyst conference: “Post-2020, there may never be another peaker built in the United States – very likely you'll be just building energy storage instead."

Congestion relief: By co-locating a battery with aging transmission infrastructure, utilities are able to take stress off of existing equipment, extend its useful life, and delay making substantial investments. By postponing investments, utilities can then gain better visibility into forecasted load growth and how to best accommodate future demographic shifts and usage patterns. This application requires subsecond response time to compensate for anomalies and disturbances (voltage sag, unstable voltage, sub-synchronous resonance).

Exhibit 37: While not cost competitive at today’s prices, we expect energy storage to become the lowest cost option to address peak load by 2020 Levelized cost comparison

Exhibit 38: We estimate that on average 1.9GW of gas peaker plants have come online annually for the past decade Estimated gas peaker plant capacity additions, annually

Source: California Energy Commission, Goldman Sachs Global Investment Research.

Source: SNL, Goldman Sachs Global Investment Research.

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Li ion (today's cost) $212/MWh

Li ion (2020 cost)

$105/MWh

* Assumes 10% capacity

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Technology overview: No one size fits all – we expect multiple winners

Got energy? Or power? We believe there is no one size that fits all in terms of the optimal qualities for grid-scale storage. This means depending on the specific application in question, a short-duration battery that can start up quickly could be favored over a longer-duration technology or, in other cases, the need for higher energy density would trump the need for power density. Simply put, because optimal characteristics differ by application, we expect more than one battery technology to prove successful in the long term.

Li-ion is not the only horse in the race, but it does appear furthest in the lead. While we focus on Li-ion given its maturity, in this section we also highlight several other technologies which we believe hold medium-to-long term promise and/or have reached some level of commerciality in grid applications: Flow batteries, sodium-sulfur (NaS), among others.

Exhibit 39: We focus on Li-ion, Flow and NaS batteries as key technologies positioned to address grid-scale storage Overview of key battery technologies

Source: Company data, Battery University, Goldman Sachs Global Investment Research.

Lithium ion (Li ion) Flow Sodium Sulfur (NaS) Emerging

Installed base 150 MW+ 50 MW+ 450 MW+ N/A

Chemistries Li Nickel Cobalt Aluminum Oxide; Li Iron Phosphate; Li Nickel Maganese Cobalt Oxide; Li Manganese Oxide

Vanadium redox; Iron-Chromium; Zinc-bromine

NaS Liquid metal; metal air

Storage duration

Short (1-4 hours) Medium (4-10 hours) Medium (4-10 hours) Short - Long

Lifespan 5 - 15 years 10 - 20 years 10 - 15 years 2 - 10 years

Cycles 2,000 - 10,000 10,000 - 15,000 2,500 - 4,500 Varies

Efficiency 85%-98% 60%-85% 70%-90% Varies

Energy density High High High High-Low

Capital cost $350/kWh - $1000/kWh $600/kWh - $200/kWh ~$500/kWh $200/kWh-$1000/kWh

Levelized Cost of Storage

$0.15-$0.75 per kWh $0.11-$0.28 per kWh $0.23-$0.57 per kWh $2-$0.05 per kWh

Key limitations Safety - risk of igniting Size, costSafety, discharge rate, heat

requirement; monitoring neededSafety, low efficiency

Level of commercializationMature R&D

We define battery basics in the appendix of this report, starting on page 47



Levelized cost of storage – a look at the economics Similar to how the levelized cost of solar and wind electricity (LCOE) is used as a gauge of cost competiveness against incumbent generating technology, we look at the levelized cost of storage (LCOS) for storage applications. In simple terms, the LCOS is the total lifetime cost of a battery system divided by the kWhs discharged from the battery. We look at the cost for a utility-scale owner and a commercial owner, with an overview of the assumptions used by technology and owner below. Our assumptions are largely derived from publicly available specs from battery manufacturers, as well as our own separate industry discussions.

Exhibit 40: The wide host of operating assumptions and capital costs produces wide LCOS ranges for the three technologies LCOE by technology and ownership

Source: Company data, Goldman Sachs Global Investment Research, DOE.

Li-ion: Performance and cost of Li-ion batteries vary widely, reflected in a wide range for the LCOS where we use a battery with 2,000 cycles and $750/kWh capital cost and a 10,000 cycle, $250/kWh cost to bookend the range.

Flow: The long cycle life of flow batteries provide an LCOS advantage at the mid-point of assumptions, however longer life creates extra O&M costs in years 8-10 for components that need to be replaced, partially offsetting cycle number benefits. On the low end of the LCOS range we use a flow battery with 15,000 cycles and capital costs of $200/kWh and on the high end we use a 10,000 cycle, $600/kWh battery.

NaS: With only one producer of the technology (NGK), capital costs and cycle times vary less for NaS, providing a tighter LCOS range. For the low end we use a 2,500 cycle battery with capital costs of $600/kWh and on the high end we use a 4,500 cycle, $400/kWh cost battery.

Utility vs. Commercial: In order to illustrate the difference in ownership economics between a utility and a commercial customer we present the LCOS for each vertical, changing certain assumptions. These changes include a higher cost of capital for the commercial customer (12% vs. 8% for the utility), a higher cost of purchased energy to charge the battery

$0.00$0.10$0.20$0.30$0.40$0.50$0.60$0.70$0.80$0.90$1.00

Li-Ion - Utility Li-Ion -Commercial

Flow - Utility Flow-Commercial

NaS - Utility NaS-Commercial

$/kWh LCOS



($0.09/kWh vs. $0.045/kWh utility), and less annual cycles for the commercial battery as we assume no weekend use for a large office building.

LCOS progression depends on capital cost and cycle improvements. As manufacturing scales up and costs come down, a downward trajectory on the LCOS of storage is apparent. However, even with 10% annual cost declines built into the assumptions, storage options struggle to approach the incumbent price of power. We note the LCOS would be best compared to that of a competing technology such as a backup generator, a natural gas-peaker on the utility side and other applications that are not necessarily representative of the cost of baseload power.

Exhibit 41: Utility scale LCOS will still be above an average generation cost from baseload power such as coal or CCGT LCOS utility scale by technology, 2015E-2025E

Exhibit 42: Commercial LCOS will also still be higher than the grid, but the addition of solar is a unique combination LCOS commercial scale by technology, 2015E-2025E



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2015 2017 2019 2021 2023 2025

Incumbent price of power

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Flow

NaS

$/kWh LCOS

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$0.50

2015 2017 2019 2021 2023 2025

Incumbent price of powerLi-IonFlowNaSLi-Ion + Solar

$/kWh LCOS



Lithium ion – the early horse in the race A new growth driver for Li-ion. The market for Li-ion batteries has been dominated by consumer electronics, which have driven a 5% CAGR over the past decade and a half. EVs appear to be the key near-to-medium term incremental driver at 42% CAGR through the next decade based on EV penetration forecasts from our Autos research team. At the same time, we see volumes in EES adding up to a potentially larger opportunity over the long run, though timing remains much less certain given the nascence of the market today – though R&D from scaling up the technology to address larger applications like EVs appear to be accelerating the push toward the grid. We expect further cost reductions, improved performance and growing policy support to all be key drivers.

Exhibit 43: Li-ion has primarily been used for short-duration applications like frequency regulation to date Li-ion deployments by application

Exhibit 44: We expect the US to continue to lead in terms of Li-ion deployment, but expect the opportunity to be global Li-ion deployments by geography

Source: DOE.

Source: DOE.

Exhibit 45: Li-ion batteries have continued to see increasing deployment across a number of grid-scale applications Select Li-ion based EES projects

Source: DOE.

Renewables capacity

firming/time-shift22%

Frequency Regulation

73%

Electric Bill Management

5%United States

China

Japan

Italy

Germany

Korea, South

Canada

Canada

Australia

Netherlands

Project nameRated power in

MWDuration at rated

power (hrs) Service/use case

AES Laurel Mountain 32 0.2Frequency Regulation,

Ramping

Grand Ridge Energy Storage 31.5 MW 32 0.3 Frequency Regulation

Auwahi Wind Farm 11 0.4 Ramping

Southern California Edison Tehachapi Wind Energy Storage Project

8 4.0Voltage Support, Electric

Supply Capacity

WEMAG Younicos Battery Park 5 1.0Frequency Regulation,

Voltage Support, Black StartZhangbei National Wind and Solar Energy Storage and Transmission

4 4.0Electric Energy Time Shift, Capacity Firming, Ramping



Li-ion is not all created equal. Several variations of Li-ion batteries exist, each of which have a different performance profile based on the specific chemistry composition of the battery. Thus, while the aforementioned focus, to date, has been to deploy Li-ion batteries in shorter-duration grid applications, we see the opportunity for increasing commercialization on newer chemistries, as well as advancements on established recipes, to position Li-ion to increasingly target larger-scale and longer-duration applications.

Exhibit 46: Lithium ion is high on the energy density curve… Relative energy density of some common cell chemistries

Exhibit 47: …though different chemistries mean performance characteristics can vary from one variant to the next Comparison of Li-ion variants vs. other batteries

Source: MpowerUK; www.electropaedia.com.

Source: ESA.

Exhibit 48: Li-ion has many variants, with Tesla and others already making large scale commitments to certain chemistries Comparison of common lithium ion technologies


0

50

100

150

200

250

0 50 100 150 200 250 300 350 400 450

Watt

-ho

urs

/Kil

og

ram

Watt-hours/Litre

Lithium PolymerPrismatic

Nickel CadmiumCylindricalPrismatic

Nickel Metal HybridCylindricalPrismatic

Lithium IonCylindricalAluminium cansPrismatic

Lithium Phosphate

Lead Acid0

50

100

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En

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y d

ensi

ty W

h/k

g

Best specific power

Best safety

Best specific energy

Lithium TitanateLithium Nickel Cobalt

Aluminum Oxide Lithium Iron PhosphateLithium Nickel Maganese

Cobalt Oxide Lithium Manganese OxideSpecific energy

(capacity)70-80Wh/kg 200-260Wh/kg 90-120Wh/kg 150-220Wh/kg 100-150Wh/kg

Cycle life 3,000 - 7,000 500 1000-2000 1000-2000 300-700

Thermal runawayAmong the safest Li-ion

technologies150C (302F) typical, high charge

promotes thermal runaway270C (518F) Typically safe regardless of charge level

210C (410F) typical. High charge promotes thermal runaway

250C (482F) typical. High charge promotes thermal runaway

Applications Distributed storage, EVs Medical devices, industrial Portable and stationary EVs, industrial Medical, EV, industrial

NoteLong life, fast charge, wide temperature range but low

specific energy and expensiveSimilar to Ci cobalt High self discharge relative to others Market share is increasing

High power but less capacity; safer than Li-cobalt; commonly

mixed with NMC to improve performance

Industry participants TeslaAlees, Changs Ascending Enterprise Co, Phostech

Lithium, Johnson Matthey

Umicore, BASF, Targray, Tesla Energy

Umicore, BASF TODA Battery Materials



Costs are coming down rapidly. With continued scale and tweaking of chemistries, the Li-ion cost roadmap appears to be accelerating. Cost targets vary widely by manufacturer, with players like Tesla and BYD (which is now claiming $150/kWh) on pace to approach 15% annual cost declines through the end of the decade based on published forecasts. Given this wide disparity, we delineate in our projections between a low cost and high cost estimate, based on projections from our global Autos research team. This is illustrated in Exhibit 49, which shows a $125-$200/kWh range of cost estimates by 2020.

Today, most cost projections in Li-ion are derived from the automotive sector, but we believe it is reasonable to assume that batteries for the grid will directionally follow the cost declines of Li-ion batteries for EVs. This is especially true given R&D efforts in Li-ion roadmaps appear to cross into grid-scale storage even for many battery makers currently more levered to the autos vertical. Not unlike technology roadmaps in other sectors (Moore’s Law in semis, Haitz’s Law in LEDs), a key driver of cost reductions is through improved performance – in the case of batteries, increasing energy density or energy produced per unit volume.

Higher energy density raises the performance of Li-ion batteries, resulting in an increase in the duration of storage available in one discharge cycle and a reduction in battery costs. The energy density of Li-ion batteries in the early 2010s was 100-150 Wh/kg, but recently some manufacturers have been able to achieve 200-300 Wh/kg. Panasonic, in conjunction with Tesla, has achieved 267 Wh/kg in its NCR18650 series for PCs, and Korean company LG Chem is eyeing development of a battery with an energy density of 252 Wh/kg for automobiles (according to the June 2015 Nikkei Automotive). Automotive Energy Supply Corp., a joint venture between Nissan Motor and NEC, is aiming to increase energy density to 200-240 Wh/kg, from 157 Wh/kg at present, with a view to offering a commercial product in 2017-2018 for use in autos (June 2015 Nikkan Jidosha Shimbun).

Switching to cobalt, manganese, and nickel for positive electrodes is a method frequently used to increase energy density, with lithium nickel manganese cobalt oxide (NMC) and lithium nickel cobalt aluminum oxide (NCA) seeing increasing adoption. Considerable effort is also being made to improve the performance of anode materials, electrolytes, separators, and other core battery components to make possible energy density of 300-350 Wh/kg by mid 2020s.

Exhibit 49: We estimate Li-ion battery pack costs to approach $125-$200 per kWh by 2020 GS low-high estimates for Li-ion costs, $/kWh


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Low estimate (Tesla) High estimate



Is there enough Li-ion manufacturing capacity? There is an estimated 90-100GWh of Li-ion production capacity globally, the majority of which resides in Asia – primarily in Japan, Korea and China. This compares to global demand across all applications (consumer electronics, EVs, etc.) that approaches 50GWh, implying a significantly underutilized capacity. We note these figures do not include Tesla’s Gigafactory which is expected to add another 50GWh of total capacity, 15GWh of which are slated for EES.

Exhibit 50: We do not expect supply chain issues to be a bottleneck for market growth in the near-to-medium term Snapshot of Li-ion supply chain

Source: BNEF, Goldman Sachs Global Investment Research.

Exhibit 51: Li-ion battery capacity adds for EVs have continued to come online – including Tesla’s expected Gigafactory… Major Li-ion battery plants for EVs

Exhibit 52: …but nearly 50% of capacity is unutilized owing to overbuild for slower than expected demand for EVs, leaving plenty of capacity for new applications 2014 Li-ion production vs. total capacity (GWh)

Source: Company data, Avicenne.

Source: Avicenne.

GS CoveredLithium mining/

productionFMC Corp

Anode

Cathode 3M Co Kanto Denka Nippon Denko Nippon Chemical Umicore

Electrolyte Cheil Industrials

Seperator/membraneMitsubishi Chemical

Sumitomo Chemical

Asahi Kasei

Cell LG Chem Hitachi Ltd Samsung SDI Toshiba Corp Saft NEC Corp

Li-ion supply chain

Hitachi Chemical Mitsubishi Chemical

Evonik Industries AG

Toray Tonen Specialty Seperator Gk

Sociedad Quimica y Minera de Chile SA

Stella Chemifa Corp

Manufacturer DateCapacity (MWh)

Capex ($mn)

Capital intensity (Capex to

MWh)SAFT Jan 2008 60 $150 $2.50LG Chem Jul 2010 1,200 $300 $0.25A123 Sept 2010 1,400 $700 $0.50Liotech Dec 2011 1,500 $450 $0.30Nissan Dec 2012 5,000 $1,000 $0.20Tesla 2017 (initial) 50,000 (2020) $5,000 $0.10

0

20

40

60

80

100

120

2014 Production Excess Capacity

BYD

ATL

Lishen

Sony

Panasonic

LG Chem

Samsung

Others



And is there enough raw material? Despite frequently being grouped with rare earth metals, lithium is not particularly unusual in nature, with more than 30 million tonnes of developing or producing reserves compared against 2014 production of roughly 160 thousand tonnes (kt). Lithium deposits are found in brine and hardrock (also called spodumene) sources on nearly every continent. However, due to its high reactivity and solubility lithium is never found in a pure form naturally and must be extracted chemically. As a result, profitable lithium production is heavily based on geology, with concentration being one of the most important factors that also rely on concentration and homogeneity of impurities that must be removed to refine it into battery grade material.

Lithium can be produced and converted in a number of ways, and we therefore use lithium carbonate equivalent (LCE) as a proxy for all lithium production. Lithium carbonate is the most widely used lithium product, and is one of two compounds along with lithium hydroxide used in lithium ion battery production. We estimate that ALB is currently the largest producer of LCE in the world, with more than 35% of produced LCE in 2014 through its Chilean brine source and its Talison hardrock source, in which it owns a 49% stake. While brine production is cheaper today, the properties of mined hardrock lithium sources may ultimately make it more suitable for battery grade production should the lithium hydroxide material preferred by some battery makers gain wider adoption. ALB is the only lithium producer to have access to both brine and hardrock sources.

Exhibit 53: Global LCE cost curve SQM and ALB have the best operational costs for producing properties owing to their position in the Chilean Atacama Salar

Note: Orocobre is not yet producing commercially. Canada Lithium and Galaxy are no longer in production. Talison is not included. Source: Roskill, Orocobre, Goldman Sachs Global Investment Research.

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0 25,000 50,000 75,000 100,000 125,000 150,000 175,000 200,000 225,000 250,000

Operati

ng co

sts ($

/tonn

e)

Cumulative Capacity

Orocob

reArgentina

brine

Zabu

yeCh

ina br

ine

FMC

Argentina

brine

Cana

da Lithium

Canada

mine

ral

Othe

r Chin

a brin

es Tian

qi

China

mine

ral

Gangfen

g Ch

ina m

ineral

Galax

yCh

ina m

ineral

SQM

Atacam

abrin

e

ALB

Atacam

abrin

e

Othe

rCh

inami

neral



Once produced, lithium is converted to its end use material through a number of chemical processes. Presently both lithium carbonate and lithium hydroxide are used in lithium ion battery anodes, with different battery producers preferring different sources based on their battery production processes. Notably, TSLA and Panasonic prefer hydroxide material, but ALB believes that lithium carbonate is presently preferred for companies looking at grid storage applications.

Exhibit 54: Battery grade material can be lithium hydroxide or lithium carbonate Lithium production chain

Exhibit 55: ALB has the broadest upstream portfolio Lithium competitive landscape


Source: ALB presentation.

Importantly, not all lithium production is suitable for battery grade material, and is dependent on the resource mined. Material not fit for upgrading is sold as technical grade (TG) into glass and ceramics production, among others. For high purity battery grade material required in electric vehicles, lithium products must be purified to concentrations well above 99%. Purification of lit

The Great Battery Race · by 2020 and utilities/IPPS such as SCE, EIX, NEE and AES are moving...

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