the long, winding road to a renewable energy...

On a sentimental journey, some of the images you recall seeing were real, some were based in reality but weren’t exactly what you thought they were, and others existed only in the realm of your imagination. This year’s topics include a status report on renewable energy penetration compared to some prior forecasts, a look at New York’s ambitious conservation and renewable energy plan, the latest on electric cars, the potential for more hydropower in the US, the commodity super-cycle and oil prices in 2017, and how utilities in sunny US states are changing their customer billing as distributed solar power grows.

EYE ON THE MARKET • ENERGY OUTLOOK 2016

Sentimental Journey

J.P. MORGAN PRIVATE BANK

The long, winding road to a renewable energy future

EYE ON THE MARKET • MICHAEL CEMBALEST • J.P. MORGAN

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Sentimental Journey: the long, winding road to a renewable energy future June 2016

The journey to a renewable energy future is taking longer than many analysts and agencies expected. How so? The solid line in the first chart shows the percentage of US primary energy1 derived from renewable sources, alongside some over-optimistic prior forecasts2. Similarly, most forecasts for electric vehicles (EVs and plug-in hybrid vehicles) have been too high as well, as shown in the 2nd chart.

Now that learning curves have contributed to declines in solar and wind capital costs3, renewable energy is finally showing up on the global electricity radar screen. In 2015, global investment in renewable energy reached a new all-time high at $286 billion, despite sharp falls in oil, coal and gas prices. Almost all of the recent growth is wind and solar, with the largest regional increases in China/Asia. Renewables ex-hydro made up 54% of all capacity installed around the world in 2015 (the first time they represented a majority), and accounted for 7% of global electricity generation in 2015. Wind has been growing steadily, while solar remains at just 1% of total generation.

1 US primary energy use by sector: electricity 39%, transportation 28%, industrial 22%, residential/commercial 11%.

2 Rather than focusing just on the US, Jacobson and Delucchi (2009) proposed a global plan for 2030 in which 100% of world energy would come from renewables. Parts list: 3.8 million 5 MW wind turbines; 40,000 300 MW PV plants; 1.7 billion 3 kW rooftop solar installations; 5,350 100 MW geothermal plants; 270 1.3 GW hydropower stations; 720,000 wave devices; 490,000 1 MW tidal turbines; and unprecedented extensions of high-voltage transmission. Assembly required.

3 Since 1976, solar module costs have declined steadily from $100 per watt to $1 per watt as production volumes increased. Wind costs also declined from 1984 to 2004, after which prices stopped falling due to rising component and labor costs. For more information, see our learning curve exhibit from last year’s energy paper.

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1960 1970 1980 1990 2000 2010 2020 2030Source: EIA, listed authors, Vaclav Smil, JPMAM. 2015. Renewables include wind, solar, hydropower, geothermal, biomass, wood and waste.

The share of US primary energy coming from renewable sources, and some notable forecasts

Actual renewable share of primary energy

Amory Lovins (RMI)

Carter Admin (solar only)

Physicist Bent Sorensen

Nat'l Renew. Energy

Lab

Google 2030 Clean Energy Plan

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'09 '10 '11 '12 '13 '14 '15 '16 '17 '18 '19 '20Source: DOE, BEA and listed organizations. 2015. Note: global EV+PHEV sales in 2015 were also around 0.6%.

Another generation of electric car projections out of sync with reality, EV+PHEV sales as % of total car sales

Deutsche BankPwCFrost & SullivanBloomberg NEFIEARoland Berger

BCG

Deloitte

Actual US EV+PHEV sales

● US● Global

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'04 '05 '06 '07 '08 '09 '10 '11 '12 '13 '14 '15Source: UNEP, Bloomberg New Energy Finance. 2015.

Annual global investment in renewable energyUSD billions

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USAmericas ex. US

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'85 '87 '89 '91 '93 '95 '97 '99 '01 '03 '05 '07 '09 '11 '13 '15Source: BP Statistical Review of World Energy. 2015

Global renewable electricity generation: still mostly a hydro-electric story, but wind rising, % of total generation

Hydro

Geothermal, biomass, & otherSolar

Wind


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Will renewable energy continue its recent rapid expansion? If so, wind and solar intermittency costs will have to be absorbed or eliminated. In last year’s energy paper, we analyzed Germany’s Energiewende plan to meet 80% of electricity demand from renewable sources by 2050. One notable finding about Energiewende: Germany’s thermal (coal and natural gas) capacity needs would be almost unchanged from current levels, given the need to meet electricity demand in winter months when German wind and solar irradiance levels are low. As an indication that our estimates may be on the right track, consider the next chart. Despite a lot of renewable capacity added since 2001, Germany’s coal and natural gas capacity has not declined at all. In other words, grids with high wind and solar penetration can still be heavily reliant on back-up thermal capacity. This dynamic is not incorporated into levelized costs per kWh for renewable energy, and may also explain why Germany’s electricity costs are the highest in Europe. We get into more details in the New York section on pages 14-15.

For investors, the journey to a more renewable and cleaner energy future has translated into substantial risk. Since 2003 and 2009, two notable renewable and alternative energy indices have trailed both the S&P energy sector (comprised mostly of oil & gas stocks), and the broad equity market as well4.

4 The Wilderhill Clean Energy Index includes US-listed companies focused on renewable energy production, energy conversion (DC-AC, fuel cells, LED screen manufacturers), pollution prevention, conservation and power delivery. The FTSE Environmental Opportunities Renewable and Alternative Energy Index, launched in 2008, includes global companies involved in renewable & alternative energy, energy efficiency and waste and pollution control.

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Source: German Federal Ministry for Economic Affairs and Energy. 2014.

Despite a large renewable energy build-out in Germany, almost no reduction in natural gas and coal capacity

Solar and wind capacity, GW

Thermal capacity (coal & gas), GW

Electricity consumption, TWh

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Source: Bloomberg. Date range: December 31, 2002 to June 14, 2016.

Renewable/clean energy stocks, traditional energy stocks and the broad market: 2003-2016, Cumulative return

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Source: Bloomberg. Date range: December 31, 2008 to June 14, 2016.

Renewable/clean energy stocks, traditional energy stocks and the broad market: 2009-2016, Cumulative return


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Renewable and clean tech investments have been made by venture capital and private equity investors as well. Private investment is by definition harder to track, but there are sources to look at. Cambridge Associates compiles data on venture capital and private equity investments in clean tech companies5. As with publicly tradable equities, the Cambridge private investment renewable energy and clean tech universe has generated substantial risk and low returns to-date:

• Through September 2015, the gross internal rate of return (before fees) on the Cambridge renewable/clean tech universe of private companies is 3.4%

• US companies, which comprise around ¾ of the universe, generated a gross internal rate of return before fees of 1.7%

• Cambridge notes that when measured across their entire dataset, such company-level returns are typically 4.4% higher than net fund-level returns earned by limited partner investors

Bankruptcies and 70%+ stock price declines in the renewable, alternative and clean energy sectors

5 The Cambridge Clean Tech universe includes renewable power manufacturing and development, energy optimization and conservation, energy storage, recycling and pollution control. As of Q3 2015, the universe was comprised of 810 companies in which 480 venture capital and private equity funds invested. Over 90% of the investments were made after 2005. Cambridge estimates that their sample represents 20%-40% of all clean tech private investment. I consider the returns to be informative since 45% of the investments have been realized.

A closer look at renewable energy and clean tech bankruptcies and large stock price declines

The following companies are reminders of the risks and exaggerated hype often associated with renewable energy and clean tech stocks. Each stock shown went bankrupt, or suffered a price decline of 70%+ from its peak. The list is primarily drawn from our analysis of concentrated stock risk in the history of the Russell 3000 Index (“The Agony & The Ecstasy”). The list includes public companies only, and excludes failed private companies such as Solyndra (solar panels); Better Place (electric car charging stations); Range Fuels, Qteros, Coskata and Terrabon (biofuels); etc.

Biofuels Fuel Cells, Engines Geothermal Solar Wind

Amyris and Batteries Alternative Earth Resources Akeena Solar Broadwind Energy

Aventine A123 Systems Geothermal Resources Intl American Solar King China Ming Yang Wind

Bioamber Advanced Battery Technologies Applied Solar Energy Cleantech Solutions

Gevo Aura Systems Pollution control Ascent Solar Technologies

KiOR Azure Dynamics Earthshell Corp AstroPower

TerraVia Ballard Power Systems Environmental Elements Energy Conversion Devices Misc. services

VeraSun ECOtality Fuel Tech Enphase Energy Intermolecular

Ener1 Wahlco Systems Equinox Lime Energy

Energy conservation FuelCell Energy Evergreen Solar

Blue Earth H Power Power generation, conversion First Solar

Comverge Impco/Fuel Systems Sol. and storage Hoku Scientific

Magnetek Medis Technologies Aixtron Real Goods Solar

Orion Energy Systems Millennium Cell American Superconductor Sky Solar Group

SemiLEDs Plug Power Amtech STR Holdings

Power Solutions Int. Beacon Power SunEdison

Rare earth minerals Quantum Fuel Systems Capstone Turbine SunPower

5N Plus Sonex Research Proton Energy Suntech Power

Daqo New Energy Unique Mobility/UQM Satcon Technology Trendsetter Solar Products

Molycorp Valence Technology TerraForm Yingli Green Energy

Rare Element Resources Westport Innovations

Source: JPMAM, Bloomberg. May 31, 2016. The companies above are shown for illustrative purposes only. Their inclusion should not be interpreted as a recommendation to buy or sell. The use of the above company logos is in no way an endorsement for JPMIM investment management services.


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This year’s paper continues our research into the promise, potential and constraints of renewable energy, after a brief section on the commodity super-cycle and oil. Click on the page links for each section.

[I] How far along in the commodity super-cycle, and is the oil bounce sustainable? Pages 5-6 Prior super-cycles have taken 15-30 years to play out. However, given price declines that have already taken place, we are probably much closer to the end of the current one. And on oil, by mid-2017, the world may be looking at a deficit of supply relative to demand.

[II] The tortoise, the hare and the electric car: the quiet progress of hybrids over EVs Pages 7-9 Electric cars generate excitement, but EV projections have been too high for generations. The more impactful energy-reducing trends are taking place in the hybrid market.

[III] A New York State of Mind: Thoughts on an ambitious new energy plan Pages 10-15 By 2030, New York aims to generate 50% of electricity from renewable energy, and decrease energy consumption in buildings by 23%. Parts of the plan are achievable while others are aspirational, particularly since New York is not a very sunny or windy place.

[IV] The Utility Empire Strikes Back: Distributed solar power and billing changes Pages 16-18 US utilities are changing their approach to customer billing, which could slow the future growth of distributed residential and commercial solar power.

[V] Dam it: A look at the modest potential for more hydropower in the US Pages 19-20 Despite its large stock of streams and rivers, the US gets a lot less electricity from hydropower than Norway, Switzerland, Canada, Austria and Brazil where its share of generation is over 50%. We take a closer look at US hydropower potential.

Sources and acronyms Page 21 As always, our energy piece is overseen by Vaclav Smil, Distinguished Professor Emeritus in the Faculty of Environment at the University of Manitoba and a Fellow of the Royal Society of Canada. His inter-disciplinary research includes studies of energy systems (resources, conversions, and impacts), environ-mental change (particularly global biogeochemical cycles), and the history of technical advances and interactions among energy, environment, food, economy, and population. He is the author of 39 books and more than 400 papers on these subjects and has lectured widely in North America, Europe, and Asia. In 2010, Foreign Policy magazine listed him among the 100 most influential global thinkers. In 2015, he received the biennial OPEC award for research, and is described by Bill Gates as his favorite author.

Michael Cembalest J.P. Morgan Asset Management

This year’s cover. The picture of Jinshui Road in Taiwan at night shows light trails and light bursts which seem to be happening in real time, but which are actually the result of changes to the camera’s shutter speed and aperture settings. With its mixture of the real and the unreal, it captures some of the themes of this year’s energy piece. On a sentimental journey, some of the images you recall seeing were real, while others existed only in the realm of your imagination.

Credit: ©katoh123/dreamstime.com


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[I] How far along in the commodity super-cycle, and is the oil bounce sustainable?

Mary Erdoes (head of our Asset Management business) showed me data from Paul Tudor Jones dating back to the 1700s. Tudor’s data shows how commodity super-cycles generally took from 15 to 30 years to bottom after the peak. The implication: there’s a long way to go before the current commodity super-cycle ends, since we are only 4-5 years into the process. But as we first wrote in February, commodity prices generally declined by 50%-70% in prior super-cycles. In that regard, a lot of damage has already been done: by February 2016, commodity prices had already declined by 55% from their peak. For investors, I think “price” is more important than “time” when thinking about where we are in this cycle.

To be clear, this commodity super-cycle was a huge one. The 3rd chart shows the $3.6 trillion spent on oil exploration and mining since 2004 when the super-cycle began. The latest reports suggest that the copper market may be oversupplied for another 5 years. But as usual, producers of copper, nickel, zinc and aluminum have responded with 35%-65% cuts to capital spending. Given long lead times, the impact of these capex cuts will likely be felt in supply terms in a few years. Typically, price responses happen sooner. As a sign that investment consequences of the commodity unwind are in their later stages, consider the YTD performance of global equity markets. Emerging markets commodity exporters are leading, followed by commodity-rich Canada and Australia. All things considered, the period from 2011-2014 was the time to position for the commodity super-cycle collapse; now, we believe it’s more about sifting through rubble for long-term opportunities.

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The collapse in commodity super-cycles since 1779

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Source: Tudor Investment Corporation, Bloomberg. February 29, 2016.

Through Feb 2016

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Source: S&P, MSCI, Bloomberg. June 14, 2016.

EM commodity producer equities and commodity spot prices, Index level (Dec. 1999 = 100)

EM commodity producer equity price index

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Source: World Bank. June 2015.

Global crude oil exploration & production and mining: capital expenditures, USD billions (both axes)

Crude oil exploration & production spending

Metal companies' capital expenditures

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Source: Bloomberg. June 14, 2016.

YTD total returns in USD on major equity markets/regionsPercent


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Is the oil bounce sustainable? Oil prices have risen sharply in 2016, particularly at the short end of the curve. Is the bounce for real? We think it is. While the world is still awash in supply (2nd chart), there has been an abrupt 35%-40% decline in global oil capital spending (3rd chart) which will likely affect future supply. The 75%+ drop in the US rig count is another sign of this phenomenon. Capex declines are primarily taking place outside OPEC, where average field decline rates are expected to rise back to 5% per year6. Furthermore, oil investors were positioned very bearishly in early 2016, setting the stage for rumors about OPEC production freezes, even when unsubstantiated, to impact oil prices (4th chart).

On oil demand7, we expect consumption to grow at its recent pace of ~1.3% per year. While consumption has declined by 10% in the OECD since 2005, it has risen by 37% outside the non-OECD8, primarily due to demand related to transportation. In barrel terms, the non-OECD finally overtook the OECD in 2013.

Bottom line: extrapolating oil demand growth and future supply in an environment of sharply reduced non-OPEC capital spending, the current oil glut could turn into an oil supply deficit sometime in 2017-2018, in which case the oil price rally makes sense to us.

6 As per Wood Mackenzie, non-OPEC field decline rates averaged 5%-6% per year from 2006 to 2011. Non-OPEC decline rates dropped to 3%-4% in 2013-2014 as higher oil prices made some expensive recovery techniques more economically viable. However, Wood Mackenzie now expects field decline rates to rise back to 5% by 2017.

7 Is renewable energy growth affecting oil demand? We doubt it. A research firm we subscribe to wrote in 2015 that reasons for lower oil prices include “technological advances that are rapidly improving the economics of solar, wind and battery power.” Really? If so, there would need to be a lot of oil used for electricity generation that could be displaced by renewable energy, or rapid electric car growth. However, oil used for electricity is just 5%-6% of global oil production (having declined sharply in the 1980s and 1990s), and EV growth is very slow (see page 7).

8 While Chinese demand for coal and other commodities declined in 2015, Chinese oil demand grew at 5.7% in 2015 and rose 3% y/y in Q1 2016. While heavy industry and construction activity have fallen, car sales are rising.

$36$38$40$42$44$46$48$50$52$54$56$58

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Source: Bloomberg. June 14, 2016.

The wild ride in oil prices in 2016WTI crude oil futures curve as of date shown, USD per barrel

Months until delivery

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Source: IEA, Bloomberg. Q1 2016.

World oil supply-demand balanceMillion barrels per day

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Source: Barclays, IMF. December 2015. Estimates for 2015 & 2016.

World oil capexUpstream capital spending as a share of global GDP, %

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Source: Bloomberg, CFTC, JPMAM. June 14, 2016.

Oil prices, production freeze rumors & positioningUSD per barrel Oil short contracts, thousands

First production freezerumors in the press

Spot oil price

Oil short contracts


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[II] The tortoise, the hare and the electric car: the quiet progress of hybrids over EVs

There’s a lot of excitement about Tesla´s Model 3, the Chevy Bolt and other electric cars coming to market. However, auto analysts have generally been way too optimistic about adoption of electric vehicles (EVs), as shown in the chart on 2020 projections vs. reality. This isn’t the first time; over-optimism on electric cars began in the 1960s with Ford Motor’s announcement of an imminent breakthrough on electric car production.

With respect to innovation in the car industry, the more impactful developments involve the use of electricity in hybrid vehicles (the tortoise), rather than in EVs (the hare).

What’s a hybrid vehicle? Well, it depends… • Micro hybrid: internal combustion engine (ICE) cars with stop-start systems drawing power from

regenerative braking; the engine shuts off when drivers idle and restarts when the gas is re-engaged • Mild hybrid: ICE cars with more powerful batteries (e.g., 48V or 110V instead of 12V), also powered by

regenerative braking, which provide engine stop-start functionality while stopping, coasting and decelerating; and which can boost the engine during acceleration

• Full hybrid: ICE cars with larger electric motors that can power the car for short periods; battery packs are charged both by regenerative braking and by the ICE itself

• Plug-in hybrid (PHEV): primary engine is usually the electric motor, recharged with an external electricity supply; ICE mostly used to recharge the electric battery rather than to power the car

The next chart shows sales for US full hybrids, plug-in hybrids and EVs. Despite the excitement, PHEVs + EVs are still just 0.7% of US light vehicle sales. Full hybrids, on the other hand, have reached 3% of sales. According to the International Council on Clean Transportation (ICCT), full hybrids are an important part of the climate picture since they can reduce fuel consumption and CO2 emissions by up to 35%9. In its analysis, ICCT cites automotive research firm Vincentric which compared 31 full hybrids to the closest non-hybrid vehicle from the same maker. The 2nd chart shows the fuel consumption reduction for some of these vehicles alongside their incremental cost. The tradeoff can be an expensive one: in only ~60% of full hybrids analyzed, the car’s extra cost is recouped through lower fuel expense over its life. This suggests that full hybrid costs need to come down further.

9 The 2014 EIA fuel economy report reached a similar conclusion in terms of potential hybrid fuel and GHG savings.

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Source: US Department of Energy. December 2015.

US full hybrid, plug-in hybrid & electric vehicle salesThousand units sold, with examples of each

Plug-in hybrids: Chevy Volt, Ford Fusion Energi, Ford C-MAX Energi, Toyota Prius Plug-in, BMW i8

Full hybrids: Toyota Prius, Toyota Camry, Ford Fusion, Hyundai Sonata, Lexus CT 200h

Electric vehicles:Tesla Model S, Nissan

LEAF, BMW i3, VW eGolf, Fiat 500e

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Full hybrids: fuel savings and cost vs. non-hybridFuel consumption reduction Price premium

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'09 '10 '11 '12 '13 '14 '15 '16 '17 '18 '19 '20Source: DOE, BEA and listed organizations. 2015. Note: global EV+PHEV sales in 2015 were also around 0.6%.

Another generation of electric car projections out of sync with reality, EV+PHEV sales as % of total car sales

Deutsche BankPwCFrost & SullivanBloomberg NEFIEARoland Berger

BCG

Deloitte

Actual US EV+PHEV sales

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The potential for lower hybrid costs and greater market share

“High-power electronics” is a relatively new field, and costs are coming down rapidly. ICCT expects hybrid system component costs to fall in half by 2025. Manufacturers and suppliers are sorting out advantages and costs of the different configurations, such as voltage level (from 12V all the way up to 330V), power density, energy storage (lead-acid, NiMH, Li-ion) and drive type. New 48V mild hybrid systems may turn out to be the most promising, achieving 1/2 to 2/3 of the benefits of a full hybrid at less than half the cost. Barclays projects greater acceptance and penetration of mild and full hybrids; the table below shows actual 2015 data and their projections for 2020 and 2025.

The big picture:

• Port fuel injection technology is expected to give way to gasoline direct injection in many ICE cars.

• 48V mild hybrid and full hybrid cars are projected to increase market share. The EPA has a similar outlook, expecting mild and full hybrids to capture 31% market share in the US by 2025 (mostly through mild hybrids).

• Combined plug-in hybrid and EV shares are projected to hit just 5% in 2025, way below most of the 2020 forecasts shown on the prior page.

• What about Tesla? In 2015, Tesla delivered 50k units and is projected to deliver 75k in 2016. The company mentioned 500k as annual capacity for its new US gigafactory by 2020, and mentioned one million units as its global target by 2020. This seems ambitious, but even if these levels are reached, Tesla’s EVs would still represent just 1.2% of global vehicle production.

Bottom line: compared to EVs, hybrids are making more impactful but less glamorous use of electricity, and can be similar to EVs in terms of GHG emissions as well (see next page).

Powertrain 2015 2020 2025ICE port fuel injection 50.9% 36.8% 20.8%ICE gasoline direct injection 24.0% 31.2% 29.4%ICE diesel 19.7% 19.9% 17.0%Compressed natural gas 1.9% 1.9% 1.8%48 Volt (mild) hybrid 0.0% 3.6% 15.5%Full hybrid 2.8% 4.4% 10.4%Plug-in hybrid (PHEV) 0.4% 1.5% 2.0%Electric vehicle (EV) 0.2% 0.7% 3.0%Source: Barclays, IHS. August 2015.

A 2015 projection of future global light vehicle production by powertrain type

Where does hybrid car energy conservation come from? As per the ICCT:

• Using energy normally lost during braking • Maintaining performance while using a smaller,

more efficient engine • Shutting the engine off at idle and at low load

conditions • Enabling the engine to be run at lower speeds,

where it is more efficient • Replacing the alternator as a means of generating

power with more efficient motor/generator systems • Replacing less-efficient mechanical water and oil

pumps with electrical pumps that only operate when needed

• Supplying power required by safety features, heated seats, dynamic chassis control and other power-hungry components


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Sparse penetration aside, how “green” are EVs compared to hybrids?

Energy use and GHG comparisons of hybrids with EVs are very complex. A comprehensive “well-to-wheels” analysis has to factor in the current electricity mix and how it’s changing over time, energy used and lost in transmission of electricity and gasoline, energy used on oil extraction and refining, energy used in the manufacturing of EVs vs. hybrids, battery disposal and other subtleties such as driver habits.

Based on data from the ICCT and a November 2015 paper from the Union of Concerned Scientists, our sense is that the GHG footprint of a full hybrid like the Prius is roughly the same as an EV in a state with the average US electricity mix. The chart below shows the electricity mix by country and by US state. Where coal usage is high, hybrid cars can produce better GHG results than an EV. As penetration of renewable energy increases, the EV becomes the greener choice.

A few things to keep in mind when looking at this chart:

• Coal vs. natural gas. An EV charged by a grid powered 100% by natural gas has ~50% of the GHG footprint of an EV charged by a grid powered 100% by coal. Of the countries shown, only the US experienced a double-digit decline in coal's share of generation from 2006 to 2014, mostly due to expansion of natural gas. From 2006-2014, coal's share of global electricity generation was unchanged.

• Renewable energy mostly hydro. As per the chart on page 1, green renewable energy segments are mostly made up of hydroelectric power, whose global share of electricity generation was 3.6x higher than wind and solar power combined in 2015.

• How green is nuclear? Difficult question. The Clean Air Task Force, climatologist James Hansen of Columbia University, David Mackay of Cambridge, Robert Hargraves from Dartmouth and 65 biologists who signed an open pro-nuclear letter in 2015 support it. On the other hand, there are disturbing reports of Fukushima’s aftermath: rain and other sources of water flowing through the site and becoming radioactive, some of which seeps into the ground or the ocean; signs that cesium and strontium were still leaking into the ocean as of 2013; and the lack of knowledge as to exactly where the molten cores from the reactors are located. I don’t know what color to make the nuclear bars in the chart: green when it works and vantablack (the darkest color in the universe) when it doesn’t?

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Can Chi Fra Ger Jpn Nth Nor Swe UK US Bra Ind Indo Ita Kor Mex Pol Por Rus Spn Tha Tur AZ CA FL GA IL MA MO NY OH PA TX VA WA

Renewables (hydro, wind, solar, etc) Nuclear Natural gas Coal and oil

Source: World Bank (2014) for countries, EIA (2015) for US states, JPMAM.

How Green is My Valley: the CO2 footprint of your electric car is heavily dependent on where you live% of total electricity generation by source

Countries with largest # of EV cars Other select countries Select US states


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[III] A New York State of Mind: Thoughts on an ambitious new energy plan

In December 2015, New York State announced an ambitious energy plan designed to reduce GHG emissions by 32% by 203010. The plan has several components, but there are two primary ones:

• Cut energy use. By 2030, reduce energy consumption in commercial, residential and industrial buildings by 23%.

• Decarbonize the grid. By 2030, generate 50% of electricity from renewable sources.

While the first objective is ambitious over a 15-year timetable, it relies on established methods of energy conservation. But will the second objective be a sentimental journey, or a real one? New York assumes that an eight- to ten-fold increase in wind and solar will propel it to 50% generation from renewables. However, New York is not a particularly windy or sunny place, which explains its low wind and solar penetration to-date. Furthermore, its projections may not adequately reflect wind and solar intermittency, which may result in substantial back-up thermal capacity needs. This phenomenon is observed in Germany after its 15-year renewable energy journey. Grid de-carbonization is critical11 given adverse human health externalities associated with fossil fuels, but the economic and political levers required to make this vision a reality, and its associated costs, are still unclear.

10 New York cites a 40% GHG reduction target, but this is vs. a higher 1990 baseline; the 2030 target is a 32% reduction when compared to 2014 emissions. In addition to renewable sources of electricity energy and reduced energy consumption in buildings, New York also assumes GHG reductions from changes in transportation: increased use of plug-in electric vehicles (see pages 7-9); upgrade of less energy-efficient mass transit infrastructure, such as the NYC subway system; and reduced idling and enhanced traffic flow from sensors, improved traffic avoidance guidance and synchronized traffic signals. 11 Vaclav, on electricity grid de-carbonization: “Underlying all of the recent moves toward renewable energy is the conviction that such a transition should be accelerated in order to avoid some of the worst consequences of rapid anthropogenic global warming. Combustion of fossil fuels is the single largest contributor to man-made emissions of CO2 which, in turn, is the most important greenhouse gas released by human activities. While our computer models are not good enough to offer reliable predictions of many possible environmental, health, economic and political effects of global warming by 2050 (and even less so by 2100), we know that energy transitions are inherently protracted affairs and hence, acting as risk minimizers, we should proceed with the de-carbonization of our overwhelmingly carbon-based electricity supply – but we must also appraise the real costs of this shift.”

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Baseline: assuming 1.1% annualelectricity demand growth

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Source: EIA, NYSERDA, JPMAM. December 2015.

New York State goals for wind and solar power by 2030Wind plus solar energy as % of total electricity generation

Current wind + solar

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Objective #1: New York’s plan to reduce energy consumption in buildings by 23% by 2030

Conservation is a critical component of a more efficient energy future, and is a primary building block in most CO2 emission plans. New York’s conservation objectives rely upon established methods (solid-state/LED lightning, light fixture efficiency, heat pumps, adaptive and optimized thermostats, more efficient HVAC and insulation systems, reduced stand-by loads and smart plugs, remote appliance control, etc). Conservation has a good track record: since 1980, US energy use per sq ft has fallen by 21% and 11% in commercial and residential buildings. In Denmark, a conservation leader, energy consumption in buildings has fallen by 45% per sq meter since 1975. As shown in the first chart, energy intensity has declined in many regions, with conservation gains in buildings and machinery playing a large role.

While New York’s energy conservation methods are well-established, the magnitude of achievable savings is not easy to quantify. The New York State Energy Research and Development Authority (NYSERDA) is tasked with coming up with plans to reach the state’s goals. NYSERDA reports released in 2014 contain two scenarios for energy conservation in buildings. In the first, all projects with positive economics are implemented, while in the second, market barriers to implementation and extra costs are incorporated. NYSERDA estimates that energy consumption could decline by 29% in the first case, and by 11% in the second.

The first case is ambitious; let’s look at electricity, which accounts for 40% of total projected energy savings in buildings12. As shown above (right), in the first case, New York’s electricity usage would fall by 35% and decline below 1980 levels, while in the second, 2030 usage would be roughly the same as in 2013. Double-digit electricity usage declines have occurred in some European countries (see table), so while New York’s plans are very ambitious, they’re not totally unprecedented.

All things considered, reducing energy consumption in buildings by 10%-15% seems quite achievable, while a 23% reduction would take a more aggressive action plan with explicit incentives for businesses and households to make the necessary investments in energy-saving technology.

12 Reduced natural gas use accounts for another 40% of building energy savings in NYSERDA’s plan. The remainder is from reduced petroleum use.

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1997 1999 2001 2003 2005 2007 2009 2011 2013 2015Source: National statistics offices, BP Stat. Review of World Energy. 2015.

Examples of declining primary energy intensityIndex, 1997=100, BTUs of energy per unit of real GDP

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India

100110120130140150160170180190200

1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2030

Source: NYSERDA, JPMAM. April 2014. Pre-1990 electricity sales extrapolated from published load data.

NYSERDA electricity use scenariosNew York electricity sales, TWh, historical and projections to 2030

Historical data through 2013

Forecast without conservation

Conservation plan incorporating market and

economic barriers

All conservation projectsimplemented

Denmark -34%Belgium -21%Finland -19%UK -16%Italy -12%Netherlands -11%Sweden -5%Germany -4%Australia -4%France -3%Norway -2%Canada -2%US -1%

Declines in TWh of electricity consumption,

2015 vs. prior peak

Source: BP Statistical Review of World Energy. 2015.


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Objective #2: a large expansion in New York’s wind and solar power

New York is not a particularly windy or sunny place. New York ranks 31st out of 35 states based on its wind capacity factors (a measure of electricity generation efficiency described below13), and with respect to solar, New York ranks 48th out of 50 states based on capacity factors from the National Renewable Energy Laboratory. Wind and solar only play a small role in New York electricity generation (around 3%), so a plan relying heavily on their expansion is worth examining. New York is also an interesting bellwether: its solar irradiance is similar to China, Japan, Russia, the UK, Germany and the Philippines, and its wind speeds are similar to India, Brazil and large parts of Central Europe.

The next chart shows NYSERDA’s renewable energy projections for 2030 alongside New York’s current renewable electricity mix. NYSERDA examines two different cases: a “Technically Feasible” case which assumes all projects are built irrespective of their cost, and an “Economically Viable” case which assumes projects are only built if they make economic sense. The latter benchmarks wind and solar against the most expensive form of generation (typically natural gas peaker plants), and results in 8x-10x growth in wind and solar power by 2030. If these generation goals were achieved, New York would make good progress, particularly if energy conservation reduces demand14.

13 Capacity factors measure actual production relative to theoretical production (generation at full-power over the entire period). For example, assume a 1 MW wind turbine with potential output of 24 MWh in one day; if the turbine generated 8 MWh of electricity, its capacity factor would be 33%.

14 In its 2014 renewable energy projections, NYSERDA assumed annual electricity demand growth of 1.1% to 2030, rather than incorporating the impact of conservation goals stated elsewhere in the plan. If electricity loads in 2030 were flat vs. today, the Economically Viable case would imply 37% renewable generation rather than 30%.

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Source: Energy Information Administration. December 2015.

Wind and solar: just 3% of NY electricity generationNY state electricity mix, 1990 - 2015, % of total generation

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1 5 9 13 17 21 25 29 33 37 41 45 49State rank based on capacity factor, 1= highest

Source: Wind Action Group, NYSERDA, NREL. April 2014.

New York ranks near the bottom in terms of electricity generation efficiency from wind & solar, capacity factor %

Wind capacityfactor

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New York, #31 of 35

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Current (Dec. 2015) Technically Feasible Economically ViableSource: NYSERDA, EIA, JPMAM. April 2014.

Share of New York State electricity generation from renewable sources, Current and 2030 NYSERDA projections NYSERDA renewable energy scenarios for 2030:

• Technically Feasible case relies heavily on offshore as well as onshore wind, and a combination of utility-scale, residential and commercial solar power

• Economically Viable case mostly relies on onshore wind, and utility-scale and large commercial solar power

• In both cases, share of generation from biomass, hydroelectric, etc remain at current levels


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Our take on NYSERDA’s assumptions. While there are over 500 pages of NYSERDA documents, wind and solar assumptions matter most since NYSERDA’s 2014 analysis did not assume higher shares from biomass, biogas, hydropower, solar thermal, wave energy, etc. For the most part, the Economically Viable case assumptions regarding wind and solar seem reasonable to us:

• Onshore wind capacity factors. New York has 1.8 GW of onshore wind whose 2013 capacity factors were 23%-25%. Most plants were built from 2006 to 2009, and are located in New York’s windiest counties (map). NYSERDA assumes capacity factors of 33% to 40% on future installations, levels typically observed in much windier states (see US map). However, two recent installations in New York show capacity factors in the mid 30s. As new GW of wind are added, the state average should rise, although 40% by 2030 seems like a stretch to us. Challenges include community receptivity15 and degradation in capacity factors over time16, a trend which has adversely affected wind investor returns.

• Upfront capital costs for onshore wind and solar. NYSERDA estimates of upfront capital costs for onshore wind ($2,380 per kW) and utility-scale solar ($1,720 per kW) look reasonable and are maybe too high, particularly for onshore wind where we have seen lower estimates of $1,600 to $2,000 per kW. As we discussed last year, learning curves show continued unit cost declines for wind, solar and battery storage as production volumes increase.

• Capacity factors for utility-scale, commercial and residential solar PV. NYSERDA assumptions of 14%-15% for all 3 types are reasonable, although commercial/residential capacity factors are often 2%-3% lower. NYSERDA estimates are consistent with NREL regarding areas with NY’s solar irradiance.

• Offshore wind. Unsurprisingly, offshore wind’s projected share falls by 90% in the Economically Viable case. While offshore wind speeds are generally higher than onshore, many estimates of their costs (including grid interconnection) more than offset this benefit. A 2014 paper from the University of Sussex determined that offshore wind is the most expensive commercially available renewable energy source in the UK, and that rather than compelling economics, its development reflects the alignment of political and financial interests of its advocates17. Papers like these are useful since they reflect the experience of countries with actual offshore wind installations; the US currently has none.

• Distributed solar PV. In the Economically Viable case, residential and small commercial solar PV disappears due to higher costs. What remains is a projected 10 GW build-out of large commercial and utility-scale solar PV. To-date, most utility-scale solar PV has been built in states that are much sunnier than New York. However, we believe that NYSERDA solar capital cost, capacity factor and levelized cost assumptions of 11 to 12 cents per kWh are reasonable (the latter 1-2 cents too low at most).

15 There’s local opposition in the air, but it may not have an impact given passage of anti-NIMBY legislation. Three New York counties (Erie, Orleans and Niagara) passed resolutions opposing a proposed 200 MW project that entails 500-600 foot wind turbines across 20,000 acres. However, in 2011 Governor Cuomo signed Article 10 into law which allows the State to provide necessary approvals in a unified proceeding for clean energy projects, and which does not appear to require approvals from local communities.

16 Examples of wind capacity factor shortfalls and degradation. A study by the Renewable Energy Foundation on UK and Danish wind farms found that capacity factors fell as wind farms aged, from 24% to 15% in year 10 in the UK, and from 22% to 18% at age 15 in Denmark. A similar study from the Imperial College of London found that wind farm output declines by 1.6% per year as turbines age. In 2012, when S&P downgraded several single-asset wind projects below investment-grade, S&P cited capacity factors that were below what industry experts had cited as lower-bound estimates, as well as operating costs that were 30% to 40% higher than original forecasts.

17 What explains the development of offshore wind? “Our analysis demonstrates how the close alignment of economic and political interests of key actors within the specific context of the UK has led to the rapid deployment of offshore wind – by circumventing anti-onshore wind protest in the short term and meeting 2020 renewables targets in the medium term but at potentially high economic and political costs when the further deployment of offshore wind adds up to a significant impact on electricity bills”. Source: From laggard to leader: Explaining offshore wind developments in the UK, Kern et al, University of Sussex, February 2014.


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While NYSERDA’s individual assumptions seem reasonable, there’s another important question to answer: what happens when there’s not enough wind or solar irradiance to meet electricity demand?

The issue of wind and solar intermittency: the need for back-up thermal generation capacity

Costs for wind and solar power cannot simply be compared to thermal sources without accounting for wind and solar intermittency, since back-up thermal capacity is typically needed for periods when there’s not enough wind or solar power to meet demand. NYSERDA is aware of this issue and is not assuming that renewable capacity immediately displaces thermal capacity on a 1:1 basis. Based on our reading of the documents, NYSERDA assumes that thermal capacity is replaced at a constant rate that is less than 1:1. Even so, this may be optimistic, since existing research shows a diminishing (non-constant) ability to shutter thermal capacity as more wind and solar power are added to the grid18.

However, our even bigger concern is that everyone’s estimates of how much thermal capacity can be shuttered may be too high. Consider the next 2 charts from our 2015 energy paper19. Working with the Clean Air Task Force, we examined hourly generation and load patterns in both Germany and California. Even though Germany’s planned build-out of wind and solar (Energiewende) would result in 80% of electricity coming from renewable sources over the course of the year, we estimated that its back-up thermal capacity needs would be practically unchanged vs. current levels, given periods of low wind and solar power during winter months. The same outcome occurred in our analysis of California. Results were not very different when assuming energy storage (via batteries, pumped storage or hydrogen fuel cells), “demand management” or geographical grid expansion. Unfortunately for New York, its winter solar irradiance is similar to Germany, and its winter wind is like California’s (i.e., the worst of both).

Even if wind and solar capacity were expanded to generate 80% of electricity from renewable energy over the course of the year, in winter months, there would be extended periods when extensive back-up thermal capacity is needed

18 Electricity grid analysts refer to “capacity credits”: the amount of thermal capacity (natural gas and coal) no longer needed once wind and solar are added to the grid. The Lawrence Berkeley National Laboratory compiled various studies that all projected sharply falling capacity credits as wind and solar penetration increases. They are not alone; a 2015 paper from the Potsdam Institute for Climate Impact Research notes that integration costs in systems with high levels of renewable energy can be up to 50% of generation costs, and that the largest factor is the cost of back-up thermal power. Hence the problem with analyzing renewable energy simply based on stand-alone levelized costs per kWh. Lazard and Bloomberg New Energy Finance are well-known sources for levelized costs per kWh by generation source; they are usually cited in media reports on renewable energy without caveats on back-up power.

19 See Brave New World, Annual Energy Eye on the Market, October 19, 2015.

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Source: Germany grid operators, JPMAM. 2015.

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California: January load vs. renewable generationHourly generation by source with load, gigawatts

Source: CAISO, JPMAM. 2015.

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Here’s some real-world evidence: despite a large buildup of solar and wind capacity at a time of stable electricity consumption, Germany’s thermal capacity is almost unchanged and is still very actively used20. Thermal generation and CO2 emissions have declined, but not thermal capacity. This may partly explain why Germany and Denmark, countries with the highest renewable capacity per capita in Europe, also have the highest residential electricity prices at around 0.30 Euro cents per kWh.

All things considered:

• New York’s 50% renewable generation target is ambitious, particularly in just 15 years

• If Germany is any guide, New York’s back-up thermal capacity needs may be higher than those assumed by NYSERDA

• Even though New York is relying on market forces to bring this transition about, taxes/subsidies and electricity prices will almost surely end up playing a role. Even before New York’s energy transition begins, its electricity prices are the 8th highest in the US, and its state taxes are the highest in the US

• While renewable energy growth can drive electricity grid de-carbonization, its power density and intermittency dynamics suggest that some hard choices involving taxes, spending and electricity prices may eventually have to be made.

20 Coal still accounts for 44% of electricity generation in Germany, and as shown in the linked chart, coal plants are still very actively used. In 2014, brown coal plant capacity factors were over 75%, close to their highest level in 25 years. Black coal plant capacity factors have fallen from their historical average of 50% to around 40% in 2014.

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The benefits: a 15% reduction in German thermal generation, Share of total electricity generation

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1 5 9 13 17 21 25 29 33 37 41 45 49State rank based on electricity price, 1 = highest

Source: Energy Information Administration. 2015.

New York: 8th highest electricity price in the USElectricity price, USD/kWh, all consumers

New York: #8 of 50

Note: highest state (Hawaii) at $0.26 per kWh

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Source: Institute on Tax and Economic Policy. 2015.

New York: highest individual tax rates in the USEffective tax rate for the middle 20% of taxpayers

New York: #1 of 50

Note: effective tax rate shown after benefit of federal tax deduction; includes state and local income taxes, property taxes and sales taxes.


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[IV] The Utility Empire Strikes Back: Distributed solar power and billing changes

Several factors have contributed to growth in US distributed residential and commercial solar capacity from less than 1 GW in 2010 to over 10 GW in 2015 (1st chart):

• Declining costs of distributed solar power (2nd chart), and the availability of third party ownership/ leasing which allows customers to put less money down upfront

• The prevalence (until very recently) of most utilities compensating solar PV owners for electricity sold back to the grid at the customer’s retail rate, a practice known as “net metering”

• The practice by most utilities to recover the majority of costs through volumetric (per kWh) charges instead of fixed dollar charges, magnifying potential savings for PV customers and undercharging them for transmission infrastructure

• Attractive Federal and state subsidies for solar PV purchasers

Growth in distributed solar does not come without complications: how will utilities deal with the portion of transmission and infrastructure costs that PV customers no longer pay for? If utilities simply raise prices per kWh on everyone, some believe it could make distributed solar more attractive, leading to greater solar adoption and continually collapsing utility revenues (the so-called “death spiral”). There are a lot of debates about how realistic a death spiral really is21. Nevertheless, there are several options utilities are considering to prevent such a spiral from ever happening:

• Reallocating cost recovery from volumetric charges to fixed dollar charges

• Time-varying electricity rates, a system in which customers buy and sell electricity based on its instantaneous price at that point in the day. The implication: solar power sold in the middle of the day could be much less valuable since it would be more abundant

• Partial net metering: customers use what they produce, and sell their surplus electricity back to the grid at a price that’s lower than the retail rate at which they buy electricity from the grid

• Lower feed-in tariffs: this system effectively assumes that PV users are in the distribution business. All the power they produce is sold to the grid (not just their surplus generation) at a lower rate. Then, they have to purchase all power they consume at a higher rate. As a result, lower feed-in tariffs are less rewarding for PV customers than partial net metering

21 Death spiral? LBNL notes that there have been no studies to-date conclusively showing death-spiral dynamics in motion. They believe a utility death spiral is unlikely, since feedback effects operate in opposing directions: higher costs per kWh improve solar PV economics for residential customers, but worsen them for commercial PV customers on time-varying rates since higher PV adoption by residential customers increases electricity supply. The former is found to increase PV adoption by 2050 by 8%, while the latter reduces deployment by 5%. These are national estimates; effects for individual utilities could vary greatly, depending on their customer mix.

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Total installed distributed solar PVGW of residential and commercial capacity

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Source: National Renewable Energy Laboratory. August 2015.

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This not an abstract discussion. In California, Arizona, Nevada and Hawaii where 54% of US distributed solar capacity has been installed to-date, these changes are already happening:

• Arizona. In November 2013, the Arizona Corporation Commission (the regulatory body overseeing privately owned utilities in Arizona), voted to install a $5 monthly fixed charge on new residential solar PV users. Utilities governed by the ACC serve 2 million customers in Arizona (~1/3 of the population). Other smaller privately owned utilities in Arizona have sought regulatory approval to lower net metering rates from retail to wholesale rates, and to increase fixed charges.

• Arizona. The net metering debate is not confined to privately owned utilities. The Salt River Project, a public utility serving 1 million customers in Arizona, changed pricing for new solar PV users to be based on time-varying rates, and began applying monthly fixed charges and demand surcharges (extra fees based on periods of maximum customer demand).

• California. In January 2016, the California Public Utilities Commission (CPUC) voted to apply a one-time interconnection fee to all solar customers, to apply time-varying rates to all customers, and to accelerate them for solar PV customers. The three largest utilities in California who serve ~24 million customers had been arguing for a lower feed-in tariff instead, which would have been more negative for solar users. Our sense is that none of the newly adopted approaches are written in stone, and are subject to change; California has agreed to revisit the issue in 2019.

• Nevada. In February 2016, the Nevada Public Utilities Commission finalized new rules on all solar PV customers (not just new adopters) that increase fixed monthly charges on net-metering customers by 2x - 3x over the next 12 years, decrease net metering credits for surplus generation by 60% - 70%, decrease volumetric charges by 10% - 30%, and give net-metering customers the option to move to time-varying rates. This is a very complex billing system; from our perspective, this new approach is the most economically negative for solar PV customers since they include both fixed charges and lower net metering rates. The NPUC regulates NV Energy which serves 1.3 million customers, or around half of the state’s population.

• Hawaii. Hawaii has the greatest amount of distributed solar per capita. In October 2015, the Hawaii Public Utility Commission lowered pricing on surplus PV generation to 15 - 28 cents per kWh vs. an average retail rate of 38 cents per kWh.

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HI AZ NJ CA VT MA CO NV DE MD CT NMSource: EIA, US Census Bureau. January 2016. States shown are those with more than 3 MW per 100,000 people.

States with high distributed solar PV and net-metering changes, Distributed solar MW per 100,000 people

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28States that have enacted net metering changes

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How might such utility responses affect the rate of solar PV adoption? To answer that question, we turn to a 2015 analysis from Lawrence Berkeley National Laboratory on distributed solar power growth22. The chart below shows their results, which we interpret as follows:

• If “death spiral” utility responses are confined to small monthly fixed charges or a shift to time-varying rates, the projected impact on overall PV adoption is not radically different from a status-quo base case. Note that the time-varying adoption curve flattens out, since the greater the abundance of solar PV, the lower mid-day electricity rates would be for PV customers selling back to the grid.

• However, if more fundamental changes to customer billing were to take place (larger fixed monthly charges and lower feed-in tariffs), distributed solar adoption rates could be materially affected.

• What are the early signs? Mixed. In California, while time-varying rates adopted by the CPUC should only have a modest impact, ongoing utility counter-proposals would dampen solar PV incentives further. In Arizona, the outcome is modest so far with a $5 charge, while in Nevada, the outcome was much more negative for solar PV economics, leading to large solar industry layoffs in the state.

Below, we show each scenario in 2040: distributed solar capacity, its electricity generation assuming a 15% capacity factor23 and its share of all electricity generation. Even in the base case, distributed solar’s 2040 share would be less than what wind already contributes today.

22 LBNL expanded on an NREL model that simulates customer adoption of distributed PV. The model uses a bottoms-up approach where customer adoption depends on a comparison of PV system costs with reductions in customer electricity bills, using data from 216 solar resource regions and more than 2,000 electric utilities.

23 Current national weighted average rooftop solar capacity factors are 15%, using NREL data. While there have been large declines in the price of solar modules, capacity factor improvements have been more limited.

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Source: Lawrence Berkeley National Laboratory. July 2015.

National distributed solar PV deployment by scenarioGW

Base case: continuation of the status quo

All residential and commercial customers on time-varying rates$10 increase in fixed monthly charge for residential customers only

Partial net metering (see description on page 16)

$50 increase in fixed monthly charge for residential customers only

Low feed-in tariff at $0.07/kWh

Implied 2040

Capacity (GW)

Implied 2040

Generation (GWh)

Share of 2040 projected electricity

generation

Base case 139 182,560 3.7%

$10 fixed charge 118 155,208 3.1%

Time-varying rates 115 150,925 3.0%

Partial net-metering 93 122,585 2.5%

$50 fixed charge 52 68,937 1.4%

Low feed-in tariff 32 41,850 0.8%Source: Law rence Berkeley National Laboratory, EIA, JPMAM. July 2015.Note: assumes 15% capacity factor.

Implied 2040 distributed solar PV under various scenarios


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[V] Dam it: A look at the modest potential for more hydropower in the US

Hydropower is a reliable, cheap form of energy with little to no CO2 impact from ongoing operations. In some countries, hydropower represents 50%+ of total electricity generation: Iceland, Norway, Switzerland, Canada, Brazil, New Zealand, Colombia and Austria. In the US, however, hydroelectric power accounts for just 6% of generation, a lower share than in 1990. The US has plenty of rivers, but hydroelectric power is heavily reliant on topography: the mass of flowing water and the gradient of the river. Mountain rivers have good hydropower potential, while rivers like the Mississippi do not. In this section, we look at a realistic case: US hydropower could rise from 6% to 9% of total US electricity generation.

There are two primary kinds of hydropower, one based on storage and the other on diversion:

• Reservoir impoundment dams create a reservoir of stored water. The water flows through a channel (called a penstock) and spins a turbine, which in turn powers a generator. The penstock inlet is normally as high as the lowest likely water level in order to maximize the height of the water flow (“generating head”). The amount of energy a dam can create is the product of the mass of water flowing through the turbine, the generating head and a gravitational constant.

• Run-of-river facilities divert a river from its natural course into a channel. The water in the channel flows past a turbine, powers a generator and is then returned back into the river.

Could the US increase its hydropower footprint? The National Hydropower Asset Assessment Program at Oak Ridge National Laboratory (ORNL) examined the potential for US hydroelectric power. They looked separately at existing non-powered dams and at new stream development.

The potential from existing non-powered dams. ORNL looked at over 50,000 non-powered dams and assessed their potential for electricity generation based on head-heights, average annual flow, seasonal weather patterns and run-off. ORNL assumed 85% efficiency (the % of potential energy converted into electricity), and excluded dams that were too low and streams with minimal flow. It’s a work in progress with a few assessments for Ohio, West Virginia and Kentucky still pending, but most of the work is done. ORNL estimates that the US could build another 5.6 GW of hydropower on existing non-powered dams, generating 32 TWh of electricity annually. This would help the US renewable energy transition, but only on the margin, representing just 1% of total US electricity generation in 2015 (4,071 TWh).

The linked map shows where these sites are located, superimposed on maps of US wind speeds and solar irradiance. For the most part, non-powered dam sites are located in areas without the best wind and solar resources, which could help such states meet higher renewable energy targets.

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Continental US electricity generation by source% of total generation

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Source: Xeneca Power Development Inc.

How a reservoir impoundment dam works

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The potential from new stream development. ORNL scanned for suitable streams and rivers on which dams have not yet been constructed. This is a more complex process, involving physical, environmental and political obstacles that existing dam projects have already dealt with.

ORNL used the flood high water mark from the last 100 years as a measure of the potential head height (by definition, a best-of-all-possible-worlds assumption) when estimating reservoir height and volume. ORNL excluded national parks, scenic rivers and wilderness areas; rivers with insufficient water flow; and areas with project incompatibility issues, environmental concerns or existing hydropower facilities. Their results: 61 GW of new potential hydropower, capable of generating 315 TWh of electricity annually. The linked map shows where ORNL sees the greatest potential for new stream development; sites are generally concentrated in mountainous regions.

The chart below combines ORNL estimates for existing non-powered dams and new streams. In ORNL’s theoretical case, hydropower could increase from 6% of US electricity generation to 15%. However, ORNL conducted their assessment of more than 3 million undeveloped streams at a “reconnaissance level” which does not incorporate all issues arising from environmental impacts, local politics or cost. They see their paper as a rough road map for future study. As a result, we added a second scenario in which new stream development is 30% of ORNL’s estimate, and in which non-powered existing dam development is 75%. If so, hydropower would rise from 6% to 9% of US electricity generation24. This would be a welcome addition, but wind and solar would still represent the bulk of the US renewable effort.

The last table shows a cross-country comparison of current and potential hydroelectric generation from the World Energy Council and International Hydropower Association. Like the ORNL analysis, the potential amounts should be considered upper bounds given environmental, cost and local issues involved. The US is at the low end of the range; the comparison sends a similar signal to ORNL with respect to the modest incremental potential for US hydropower.

24 Separately, Idaho National Laboratory generated “theoretical” and “realistic” US hydroelectric power scenarios. The two scenarios cite a doubling in generation and an increase of 50%+, respectively, which are similar to the two projections shown in the chart above.

Existing hydro Existing hydro Existing hydro

New stream development

New stream development

0%

2%

4%

6%

8%

10%

12%

14%

16%

Current (Dec. 2015) Theoretical 75% NPD, 30% NSD& Current

Source: EIA, ORNL, JPMAM. April 2014.

Hydroelectric power: current vs. potential generationShare of continental US electricity generation

Non-powered dams

Non-powered dams

Current and potential electricity share from hydropower

Country Current Potential Country Current Potential Country Current Potential

China 19% 50% Mexico 10% 21% Ukraine 4% 14%

U.S. 6% 15% Italy 16% 33% Nether. 0% 0%

India 10% 43% Spain 10% 23% Venez. 60% >100%

Russia 16% 96% Australia 5% 17% Vietnam 39% >100%

Canada 61% >100% Turkey 26% 80% Belgium 0% 0%

Germany 3% 6% Thailand 2% 11% Kazakh. 9% 41%

Brazil 62% >100% S. Africa 0% 2% Sweden 44% 97%

France 9% 22% Poland 1% 5% Uzbek. 19% 45%

Indo. 7% 24% Argent. 29% 81% Norway 95% >100%Source: World Energy Council, International Hydropow er Association, BP. Countries selected represent largest overall energy consuming countries in 2015 for w hom the WEC projected hydropow er potential, sorted by 2015 consumption. Potential includes current generation.


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2014 Wind Technologies Market Report, Lawrence Berkeley National Laboratory, August 2015.

2015 Key World Energy Statistics, International Energy Agency, 2015.

A Brave New World: Deep De-Carbonization of Electricity Grids, Eye on the Market Special Edition, J.P. Morgan Asset Management, October 2015.

An Assessment of Energy Potential at Non-Powered Dams, Oak Ridge National Laboratory, April 2012.

Calculating Electric Drive Vehicle Greenhouse Gas Emissions, International Council on Clean Transportation, Aug 2012.

Cleaner Cars from Cradle to Grave – How Electric Cars Beat Gasoline Cars on Lifetime Global Warming Emissions, Union of Concerned Scientists, November 2015.

An Evaluation of Solar Valuation Methods Used in Utility Planning and Procurement Processes, Andrew Mills and Ryan Wiser, Lawrence Berkeley National Laboratory, December 2012.

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Energy Efficiency and Renewable Energy Potential Study of New York State, Optimal Energy, ACEEE, Vermont Energy Investment Corporation, NYSERDA, Volumes 1-5, April 2014.

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Energy Transitions, Vaclav Smil, (Prager, in print).

From laggard to leader: Explaining offshore wind developments in the UK, Kern et al, University of Sussex, Science and Technology Policy Research, February 2014.

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Acronyms

BNEF: Bloomberg New Energy Finance; EIA: Energy Information Administration; EV: Electric vehicle; GHG: Greenhouse gases; GW: Gigawatt; GWh: Gigawatt-hour; HVAC: Heating, ventilation and air conditioning; ICCT: International Council on Clean Transportation; ICE: Internal combustion engine; IEA: International Energy Agency; kWh: Kilowatt-hour; kW-DC: Kilowatt of direct current; LBNL: Lawrence Berkeley National Laboratory; LED: Light emitting diode; Li-ion: Lithium-ion; MW: Megawatt; NIMBY: Not in my backyard; NiMH: Nickel-metal hydride; NPD: Non-powered dams; NREL: National Renewable Energy Laboratory; NSD: New stream development; NYSERDA: New York State Energy Research & Development Authority; OECD: Organization for Economic Cooperation & Development; OPEC: Organization of the Oil Exporting Countries; ORNL: Oak Ridge National Laboratory; PHEV: Plug-in hybrid electric vehicle; PV: Photovoltaic; SRI: Stanford Research Institute; TWh: Terawatt-hour; WTI: West Texas Intermediate


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MICHAEL CEMBALEST is the Chairman of Market and Investment Strategy for J.P. Morgan Asset Management, a global leader in investment management and private banking with $1.7 trillion of client assets under management worldwide (as of March 31, 2016). He is responsible for leading the strategic market and investment insights across the firm’s Institutional, Funds and Private Banking businesses.

Mr. Cembalest is also a member of the J.P. Morgan Asset Management Investment Committee and a member of the Investment Committee for the J.P. Morgan Retirement Plan for the firm’s more than 235,000 employees.

Mr. Cembalest was most recently Chief Investment Officer for the firm’s Global Private Bank, a role he held for eight years. He was previously head of a fixed income division of Investment Management, with responsibility for high grade, high yield, emerging markets and municipal bonds.

Before joining Asset Management, Mr. Cembalest served as head strategist for Emerging Markets Fixed Income at J.P. Morgan Securities. Mr. Cembalest joined J.P. Morgan in 1987 as a member of the firm’s Corporate Finance division.

Mr. Cembalest earned an M.A. from the Columbia School of International and Public Affairs in 1986 and a B.A. from Tufts University in 1984.

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