Next eotm - Vaclav Smil

Transcription

EYE ON THE MARKET
Arc
History
THE
OF
OUR ANNUAL UPDATE ON 5 TOPICS IN THE WORLD OF ENERGY
1
1
1
1
The Arc of History. While the world has become twice as energy efficient over the last 50 years, global
consumption of primary energy is three times higher than it was in 19652; we are an energy-hungry planet.
The finite nature of fossil fuels, the increasing cost of extracting them and their environmental impacts
have prompted many countries to plan for greater reliance on renewable energy. While the arc of history
bends towards renewable energy, what will that arc look like?
For the last few years, we have written an annual piece on energy. In doing so, we have worked with
Vaclav Smil from the University of Manitoba (see biography below). In a recent article in Scientific
American, Vaclav provided a rough road map for what the arc of renewable energy use might look like.
The first three panels track the percentage of world energy that was based on coal, oil and natural gas in
their respective adoption phases; note that it took several decades for each to reach 30% penetration
rates3. The last panel shows modern renewable energy (ex-hydropower). Some argue that the pace of
technological progress is faster now, and that there is an environmental urgency that did not exist in prior
energy transitions. Perhaps; but given sunk capital costs, behavioral issues and complex systems involved,
prior gradual transitions are a good starting point for the pace of future change.
The Arc of Energy History, 1840 - 2012
Coal
Oil
Natural Gas
Percent, share of world energy
50%
50%
50%
50%
40%
40%
40%
40%
30%
30%
30%
30%
20%
20%
20%
20%
10%
10%
10%
10%
Years
0%
0
10
1840
20
30
40
50
60
Years
0%
0
1915
10
20
30
40
50
60
Modern Renewables
Years
0%
0
10
20
30
40
50
1930
60
3%
Years
0%
0
10
20
30
40
50
60
2012
Years after Energy Source Begins Supplying 5% of Global Demand
Biography. Vaclav Smil is a Distinguished Professor Emeritus in the Faculty of Environment at the
University of Manitoba in Winnipeg and a Fellow of the Royal Society of Canada. His interdisciplinary
research has included the studies of energy systems (resources, conversions, and impacts), environmental
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 35 books and more than
four hundred 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. He is also
described by Bill Gates as his favorite author.
2
The first statistic measures energy used to produce one dollar of world GDP; the second statistic measures total
primary energy consumption.
3
Europe reports that 14% of its primary energy came from renewable sources in 2012. On closer inspection, two
thirds of this amount came from hydropower (most viable locations have already been harnessed) and the burning of
wood. Another 13% came from biofuels (which are associated with nutrient leaching, soil erosion and increased CO2
issues). Only 22% of its renewable energy, or 3% of total primary energy, came from solar and wind.
2
For investors, the journey to a renewable energy world will be long, and subject to fits and starts regarding
what works and what doesn’t. The next chart is one way of visualizing the risks and opportunities. It shows
the excess returns on two diversified clean energy indexes4 over the S&P Small Cap Index. The peaks and
valleys are large, with more valleys than peaks; new ideas often generate tremendous excitement, but only
a few work out in the long run.
Renewable energy stocks fall in and out of favor
Rolling 1-year excess return of clean energy vs. S&P small cap
70%
NYSE Bloomberg AME
Clean Index minus S&P
Small Cap Index
50%
30%
10%
-10%
-30%
-50%
Wilderhill Clean Energy Index
minus S&P Small Cap Index
-70%
2003
2005
2007
2009
2011
2013
Source: Bloomberg. September 2014.
The table below shows additional comparisons. Clean energy stocks have trailed the broad market and the
oil & gas stocks which make up the majority of S&P energy sub-indices. Relative returns are similar when
starting the analysis in other years or when using different alternative energy indices.
Mapping the underperformance of alternative energy stocks (annualized total returns)
Index
Since 2002
Clean Energy Indices:
Wilderhill Clean Energy Index
-3.0%
NYSE Bloomberg Americas Clean Energy Index
**
FTSE Environmental Opps. Renewable & Alternative Energy Index
**
Benchmark Indices:
S&P Small Cap
11.7%
S&P Small Cap Energy
18.6%
S&P Mid Cap
11.9%
S&P Mid Cap Energy
11.6%
S&P 500
9.3%
S&P Large Cap Energy
13.9%
Since 2005
Since 2008
-9.8%
4.4%
**
-3.9%
11.3%
1.0%
8.3%
10.8%
8.9%
4.9%
7.6%
9.0%
17.5%
21.9%
19.4%
16.9%
17.0%
12.2%
Source: Bloomberg. September 2014. ** represents indexes prior to their inception. Past performance is not indicative of future results.
4
The Wilderhill Clean Energy Index contains companies that focus on renewable energy production, energy
conversion (DC-AC, fuel cells, LED screen manufacturers), pollution prevention, conservation and power delivery.
The NYSE Bloomberg Americas Clean Energy Index is composed of North and South American companies that are
active across the clean energy value chain, focusing on solar, wind, bioenergy generation and energy efficiency.
The FTSE Environmental Opportunities Index measures the performance of global companies involved in renewable &
alternative energy, energy efficiency and waste and pollution control.
3
In this year’s note, we examine 5 topics connected to the arc of energy history. The topics are presented in
order of their appearance and impact on the arc so far: oil, nuclear, wind, solar and storage of electricity5.
1. US energy independence in light of increasing domestic oil and gas
production. Rising US shale oil production makes US energy independence
feasible by 2025. It has brought down the marginal cost of oil, and
coincided with slowing oil demand for both cyclical and structural reasons.
Pages 5 – 7
2. The rising cost of nuclear power. Once thought of as a long-term bridge
between fossil fuels and renewable energy, rapidly rising costs have slowed
capacity additions outside of Asia. An analysis from France shows rapidly
increasing capital and operational costs over the last decade.
Pages 8 – 10
3. Wind power and the elephant in the room. US wind capacity was
growing rapidly and was ahead of the DOE’s “20% by 2030” plan until new
capacity additions collapsed in 2013. A variety of factors make the next
decade more uncertain for wind than the prior one.
Pages 11 – 13
4. Solar power in the US: an early look. Analysts at Lawrence Berkeley
National Laboratory now have enough critical mass to look at solar costs,
capacity factors and growth potential. While costs have declined sharply,
photovoltaic solar is starting from a very low base and relies heavily on
continued subsidies and the decline in module prices being permanent.
Pages 14 – 17
5. Electricity storage. Renewable energy intermittency can be mitigated by
increased interconnectedness of electricity grids, or through advances in
energy storage. In the final section, we focus on progress to-date in storing
electricity using the latest update from Sandia National Laboratories. Slow
going so far, with some progress in the lab.
Pages 18 – 20
Appendices I, II and III on battery storage, the Cautionary Tale of the
Monterey Shale, and US electricity capacity additions
Pages 22 – 23
Our findings on wind, solar and electricity storage support the view that energy transitions take a very long
time to play out. This is particularly the case when renewable energy subsidies lapse, as they have in the
US and Europe, and in the absence of fossil fuel externalities included in the cost of production and
consumption. Vaclav often writes about the importance and inevitability of renewable energy, but also
points out hyperbole regarding how quickly the arc of energy history can change6. By being realistic about
the pace of this critical transition, we can make better decisions along the way.
Michael Cembalest
J.P. Morgan Asset Management
5
What about natural gas? Last year, we covered US export potential, supply-demand conditions and the nat gas
impact on US electricity prices (which are 50%-60% of European and Asian levels). Next year, we plan to address
two related issues: adoption rates for natural gas vehicles, and fracking. On the latter, geochemists from Lamont
Doherty Earth Observatory are conducting a study of groundwater before, during and after fracking; a study from the
EPA is expected to be published in late 2014. The risks are less related to fracking fluids, and more to naturally
occurring salts, heavy metals and radioactive elements that are surfaced in the fracking process.
6
In a recent piece in American Magazine, Vaclav deconstructed a recent headline that read “Germany produces
half of energy from solar”. The period in question was only for one hour in the middle of the day; it was a holiday
with lower than normal demand; in low demand situations, wind and solar have priority over other generation
sources, so the result is somewhat axiomatic; and the header should have said “electricity” instead of “energy” since
it was referring to the electricity grid. According to Vaclav’s calculations, Germany got 0.5% of its primary energy
from solar power in calendar year 2013, and not 50%.
4
1: An update on US energy independence given rising shale oil production
This is a story best told with pictures. The first chart shows increasing US domestic oil production and
declining net oil imports, down 3mm bpd since 2006. Rising US production is mostly “light/sweet” and
has displaced similar grades imported from Africa (down 90% since 2010). What will happen to rising
volumes of US light oil, particularly if US refiners exhaust the capacity to refine all of it? The Department of
Commerce allows companies that obtain a special permit to export a small amount of crude oil (420k
barrels/day, mostly to Canada). Private rulings passed in 2014 also allow two Texas companies to export
minimally processed condensate from the Eagle Ford shale formation. However, legislation that allows
unrestricted exports of US crude has yet to be tabled. Lifting the export ban is not the only solution:
there’s more imported light oil that could be reduced, particularly if West Coast-Gulf Coast pipeline
infrastructure improved; light oil refining capacity could be increased; and refineries could blend more light
oil with heavier grades. As for the second option, the US will need to take a clearer stance on the oil
export ban to incentivize more capital spending on light oil refineries.
What US energy independence might look like
US: falling net imports, rising domestic production
US net crude oil imports, million barrels per day
Million barrels per day of crude oil
9
10.5
Net imports
8
9.5
8.5
6
4
6.5
4.5
1991
3
2
Domestic production
1
Imports for ref.exports
NGV/PEV displacement
Middle
East
5
7.5
5.5
Africa
+ other
7
2011
2012
2013
Net
Net
Net
Imports Imports Imports
CAFE standards &
Auto Replacement
South
America
North
America
Net increase in US
production
Net
Imports
0
1994
1997
Source: EIA. July 2014.
2000
2003
2006
2009
2012
2014 YTD Projected
Net Imports 2025
Source: EIA, IEA, JPMAM. July 2014.
What might greater US energy independence look like? If light oil refining capacity is added, then
both gross and net oil imports would fall. If light oil is exported, then net oil imports would fall while gross
imports remained the same. The balance of payments consequences of both scenarios are similar, while
the geopolitical consequences are not. In the chart above, we assume the following by 2025:
 Additional US light oil refining capacity and increased production result in reduced US net imports of
heavy crude (for 2025 US production, we average EIA forecasts of 9.5 mm bpd and IEA forecasts of 12.0
mm bpd). See Appendix II on the Monterey Shale as an example of a forecast gone wrong.
 More stringent CAFE standards and the auto replacement cycle reduce US gasoline demand, which
ultimately reduces net crude oil imports by ~1.5 mm bpd7.
 We assume a small amount of crude import displacement from 5% penetration of natural gas and
electric vehicles by 2025. We estimate the current US NGV/PEV penetration rate at less than 0.2%.
 Some crude is imported and refined solely for export. We exclude these imports from the energy
independence picture; they contribute to growth and employment but are not as critical as crude that is
imported and consumed.
7
Our estimate of reduced net oil imports resulting from higher CAFE standards (55.3 mpg for cars and 39.3 mpg for
light trucks) is based on Houser and Shashank in Fueling Up: The Economic Implications of America’s Oil and Gas
Boom. Their model incorporates second order effects from driver responses to increasing fuel economy (they drive
more), and rising population growth/energy demand. The 1.5 mm bpd reduction shown in the chart is lower than
similarly constructed estimates from the Union of Concerned Scientists.
5
When discussing US energy independence, why do we focus more on oil more than on gas?
While the US is also a net importer of natural gas (almost entirely via pipelines from Canada), the energy and cost of
imported crude oil is vastly greater. In 2013, the US spent 50 times more on net imports of crude oil than on net
imports of natural gas. Measured in energy terms, net crude imports are 12 times greater than those of natural gas.
Furthermore, it looks like the US will be a net exporter of natural gas before the same is true for crude oil (EIA
forecasts of US natural gas production exceed consumption beginning in 2017; US natural gas net imports peaked in
2007 at 3.8 trillion cubic feet per year, and have since fallen to 1.3 trillion). Factoring in the crude oil and natural gas
outlook (and current net exports of refined petroleum products), we expect the US net energy current account deficit
to improve to 0.5% of GDP by the end of the decade after peaking at 3.3% of GDP in 2008.
US Natural gas production and consumption
US net energy current account deficit
Net exports of energy products , percent of GDP
Trillion cubic feet per year
35
0.0%
2020 projection
-0.5%
Other estimates of 2025 production
33
IHS Global Insight
Energy Ventures Association
ICF International
BP
INFORUM
31
-1.0%
29
27
-1.5%
25
-2.0%
23
-2.5%
21
Consumption
19
-3.0%
Production
17
-3.5%
1978 1982 1986 1990 1994 1998 2002 2006 2010 2014 2018
Source: Bureau of Economic Analysis. JPMAM. Q1 2014 .
EIA actual data EIA estimates
15
1990
1995
2000
2005
2010
2015
2020
2025
Source: EIA. April 2014. Other estimates from respective sources.
2030
The US shale oil boom: lowering marginal costs at a time of weak cyclical demand
While US shale oil production has been rising, the rest of the global oil production complex was roughly
flat from 2006 to Q2 2014 (see first chart). Production disappointments have occurred in Brazil, Syria,
Azerbaijan and in conflict-ridden OPEC states (Libya, Nigeria, Algeria, Iran and Iraq). In August/September
2014, production picked up in Libya, and also in Iraq and Iran. Some of these increases are sensitive to
geopolitics and sanctions, and may not be permanent. However, the combination of rising US
production, small OPEC increases, declining demand growth in China and outright demand
declines in Europe8 created enough of a net supply increase to depress oil prices by 25% from
their June peaks. In late September 2014, production was running at ~2 mm bpd ahead of demand.
While slower oil demand growth is mostly cyclical, some is structural as well, reflecting efficiency gains and
industrial transitions from oil to natural gas. To-date, we have not seen a coordinated OPEC response to
cut supply, and it may be a while before we get one.
Apart from US shale, global production flat since 2006
Rising 2014 production: mostly US shale, some Libya
Increase in production since 1998, million barrels per day
Global oil production (including NGLs), million barrels per day
6
5
4
3
2
1
0
-1
-2
-3
-4
1998
94
Non-OPEC
ex-US
93
92
US shale
OPEC
91
US conventional
90
89
2000
2002
Source: EIA. June 2014.
2004
2006
2008
2010
2012
2014
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
2012 2012 2012 2012 2013 2013 2013 2013 2014 2014 2014
Source: IEA. Q3 2014.
8
In China, oil demand growth fell from 800,000 bpd in 2007 to 250,000 bpd in 2014; Spanish and Italian oil
consumption fell in 2013 vs. 2012, and are down 25% since 2007.
6
Since US shale oil production started rising, the marginal cost of oil has come down sharply.
One way to think about marginal cost: the oil price required to generate normal industry profits on recently
producing wells and those under development. As shown, estimated marginal costs on such projects have
flattened since 2009 to ~$80 per barrel for probable levels of future demand9. Improved technology,
fewer bottlenecks and more competition in the oil services industry following the recent oil price decline
may reduce marginal costs by another $5-$10 per
Shale oil era has reduced estimated future marginal costs
barrel (dotted line). This cost decline is good news
Breakeven cost for new projects, USD per barrel
for oil consuming nations, but creates challenges
$120
2009 2010
2011
2013
for countries with high fiscal break-evens (i.e., the
2014
2012
$100
oil price required to balance government budgets):
Libya, Iran, Venezuela and Russia. It also creates
$80
challenges for highly indebted quasi-sovereign and
2014 with cost
private sector oil companies, the largest 100 of
$60
deflation impact
which increased debt from $300 billion in 2005 to
$1.1 trillion in 2013. Many are already free cash
$40
flow negative (after capital spending and dividends),
$20
and will struggle to maintain production, capital
0
5
10
15
20
25
30
35
spending and hiring if oil remains at $80 per barrel
Estimated peak cumulative production, mm barrels per day
for a sustained period.
Source: Goldman Sachs, "400 projects to change the world", JPMAM. 2014.
How will falling oil prices affect energy independence since US producers now represent the
marginal supplier? As shown below, US shale oil with costs from $75-$80 (green dots) have displaced
more expensive Russian projects, Nigerian and Angolan deepwater, Canadian heavy oil and more complex
US deepwater reservoirs as the marginal unit of supply. If oil prices fell below $70-$75 on a sustained
basis, some US shale operators would eventually have to cut production. This would slow US energy
independence trends until oil prices rose back above US marginal costs. This adjustment period could take
1-3 years, during which time global oil demand slowly rises, inefficient US shale operators are squeezed out
and the survivors force cost reductions through the supply chain. Even if this comes to pass, with a 2025
time horizon, US energy independence as outlined earlier would still be achievable.
The marginal barrel is now US shale
Cost curve for new projects (recently producing, under development or pre-sanction), $ per barrel (excludes oil service/equipment deflation)
$110
US Gulf Deepwater
Norway
$100
$90
Complex
deepwater US
Gulf reservoirs
Russia
Nigeria Deepwater
Conventional shallower
US Gulf reservoirs
$80
Brazil Deepwater
Northern Iraq
$70
Bakken
Brazil
Lula
$60
Utica
Niobrara
$50
Canada oil sands
(steam assisted
gravity drainage)
$40
Canada heavy oil
(surface mining)
Eagle Ford
Permian Basin
US Shale Oil
Angola Deepwater
Canada
Venezuela
$30
$20
0
5
10
15
20
25
30
35
40
45
Estimated peak cumulative production, million barrels per day
Source: Goldman Sachs,"400 projects to change the world". May 2014.
9
Assuming increases in global oil demand of 1%-1.5% per year and 1.5%-2.0% annual decline rates at existing
fields, the world will need somewhere between 15 and 20 million new barrels per day over the next decade.
7
2: The rising cost of nuclear power
In 1945, physicists predicted that nuclear breeders would be man’s ultimate energy source. A decade later,
the chairman of the US Atomic Energy Commission predicted that it would be “too cheap to meter”. Then
things got complicated. Fast forward to today; while some countries have adopted a more cautious stance
(Japan, Germany), nuclear power is still with us. Asia leads in the number of reactors under construction
(China 29, India 6 and South Korea 5), and the US has 5 under construction as well (6 GW of capacity).
The rise, plateau and fall of nuclear energy's share of
global electricity generation, percent of total generation
20%
Asia leads the way in nuclear plant capacity currently
under construction, Gigawatts of capacity
35
18%
30
16%
14%
25
12%
20
10%
15
8%
10
6%
4%
5
2%
0
0%
1971 1975 1979 1983 1987 1991 1995 1999 2003 2007 2011
Source: 2014 OECD Factbook. Data through 2011.
China
Russia
South Korea
USA
India
Source: World Nuclear Association. June 2014. Under construction: f irst
concrete f or reactor poured, or major ref urbishment of a plant under way.
The appeal of nuclear power: capacity factors [see box on page 10] of 80%-95% for US nuclear vs. 5570% for coal10 and 30-40% for wind and hydro-electric power, and no CO2 emissions from ongoing
operations, though they can be high during construction. The problem: it is getting a lot more
expensive to build and operate. One place to examine these trends is France, #2 in terms of nuclear
terawatt-hours generated and #1 in terms of nuclear power as a share of electricity generation.
World's biggest nuclear electricity generating countries
Terawatt-hours of nuclear electricity generation
Share of electricity generation from nuclear energy
Nuclear generation as a % of total electricity generation, 2013
900
US
800
80%
70%
700
60%
600
50%
500
40%
France
400
30%
20%
Rus, Kor,
Chi, Can,
Ger
Japan
200
100
1973
1981
1989
1997
Source: BP Statistical Review of World Energy. 2013.
2005
2013
10%
0%
France
Belgium
Slovakia
Hungary
Ukraine
Sweden
Switzerland
Czech Rep
Slovenia
Finland
Bulgaria
Armenia
S. Korea
Romania
Spain
USA
Taiwan
UK
Russia
Canada
Germany
China
India
300
0
1965
Increase after
construction of 33 GW
of new capacity
Source: World Nuclear Association. June 2014
10
Any comparison of electricity generation sources should incorporate the fully-loaded costs of coal. In last
year’s energy note, we walked through the fact that coal powered electricity as a % of global primary energy
consumption is at its highest level since 1970, and discussed the various consequences for CO 2, smog, acid rain, heavy
metals emissions (sulfur dioxide and nitrous oxide) and mercury, and the associated creation of polluted streams,
waste heaps, slurry and fly ash ponds, underground fires, etc.
8
Nuclear power in France. After Fukushima, French Prime Minister Fillon ordered an audit of its nuclear
facilities to assess their safety, security and cost. As a result, we now have a more accurate assessment of
the fully-loaded levelized costs for French nuclear power. Levelized cost is an important concept in energy
analysis: it incorporates upfront capital costs, financing costs, operating & maintenance and fuel costs,
capacity factors (actual vs. potential output), and any insurance or fuel de-commissioning costs.
A prior assessment using data from the year 2000
estimated levelized costs at $35 per MWh. The French
audit report then set out in 2012 to reassess historical
costs of the fleet. The updated audit costs per MWh
are 2.5x the original number, as shown by the middle
bar in the chart. The primary reasons for the upward
revisions: a higher cost of capital (the original assessment
used a heavily subsidized 4.5% instead of a market-based
10%); a 4-fold increase in operating and maintenance
costs which were underestimated in the original study;
and insurance costs which the French Court of Audit
described as necessary to insure up to 100 billion Euros in
case of accident. In a June 2014 update from the Court
of Audit, O&M costs increased again, by another 20%.
The rising cost of nuclear power in France
Levelized cost measured in 2010 $/MWh
$140
Development
$100
Back-end
$80
$60
$40
$131
Insurance
$120
$91
Fuel
O&M
Capital and Financing
$35
$20
$0
Original Historical Cost Updated Historical Cost
Current cost of
(2000)
(2012)
new build
Source: N. Boccard, "The cost of nuclear electricity: France after Fukushima",
Energy Policy Journal, December 2013.
Subsequent analyses set out to assess the cost of future nuclear power in France. Based on data
from a 1.6 GW facility under construction in Flamanville, costs have risen again (third bar in the chart). The
main reason: higher capital costs for the new facility. Construction delays have compounded the project’s
cost, in part a consequence of greater security measures mandated after Fukushima. It’s possible that
future plant costs won’t be as high if the industry gains more experience with the new type of pressurized
water reactor being built in Flamanville. Nevertheless, the picture is clear: the days of nuclear energy
being a cheap way to add baseload power are a thing of the past.
Due to rising costs, France aims to reduce nuclear from 70% to 50% by 2025 and replace it with renewable
energy. On paper, wind is cheaper than nuclear in France, but replacing nuclear with wind/solar will require
spending on grid integration and/or storage (as things stand now, other than hydro, France only gets 5% of
electricity from renewable energy). The electricity issue is particularly important in France, as it has the most
electrified heating system in Europe. The path of least resistance: extend the life of existing nuclear reactors
to 50-60 years instead of building new ones, and phase in renewable energy over a longer period of time.
In France, nuclear looks more expensive than wind
USD per MWh, levelized cost
$140
$120
$100
$80
$60
$40
$20
$0
Nuclear
Wind
Source: N. Boccard, "The cost of nuclear electricity: France after Fukushima" ,
9
Escalating costs are not just an issue in France: in the US, real costs per MWh for nuclear power have been
rising at 19% annually since the early 1970’s. The highest nuclear cost bar in the chart below comes from
PJM, the US East Coast interconnection grid operator which oversees the world’s largest competitive
wholesale electricity market. Another confirming observation: in a 2010 analysis, Exelon’s assumed costs
per metric ton of displaced CO2 from nuclear are double the same estimates from 2008. One final example
of rising costs: the UK agreed to purchase power from EDF Energy at $158 per MWh (in today’s dollars),
sourced from a 3.2 GW nuclear plant to be completed by 2023. Bottom line: expect the contribution of
nuclear power to global electricity generation, shown in the first chart on page 7, to keep declining.
Nuclear all-in costs are high in the US as well
USD per MWh, levelized cost
$140
$120
$100
$80
$60
$40
$20
$0
Nuclear Nuclear Nuclear Wind
(PJM) (Lazard) (EIA) (Lazard)
Wind
(EIA)
Nat Gas Nat Gas
(Lazard) (EIA)
Source: PJM, EIA, Lazard (as of 2014). Subsidies not included.
What about the future for nuclear? Academics, scientists and private sector companies are exploring
ways of lowering costs, increasing productivity and reducing radioactive by-products (e.g. travelling wave
reactors). However, commercial deployment of these reactors is many years (if not decades) away, while
our report is about the most important developments of the year. The 2014 update from France is more
relevant as we consider near-term prospects for nuclear power in the OECD and its impact on electricity
prices. We do not have comparable data for nuclear costs in Asia, or insight into whether post-Fukushima
construction and operational standards have changed there. Given fewer domestic energy alternatives,
countries like China, Korea and India may be willing to pay a higher price for the certainty and lower
carbon footprint of nuclear power.
Understanding capacity factors
A capacity factor measures the ratio of electricity produced during a certain period of time relative to the
electricity that could have been produced if the generator had run continuously at full-power during the
same period. Reasons why capacity factors are less than 100%: intermittency of naturally occurring
resources (the degree of wind speeds and solar irradiation levels; availability of water for hydroelectric
dams); plant downtime for maintenance and repairs and inefficiencies resulting from plants being ramped
on and off; voluntary curtailment of power (e.g., when wind or solar energy cannot be absorbed by the
grid); or when looking at power plants that are not designed for continuous use, such as natural gas
peaker facilities which are only drawn upon when electricity demand spikes. As noted on page 11,
capacity factors for the US wind fleet have been stable over the last few years in the mid 30’s, while solar
capacity factors have been rising towards these levels in the sunniest US locations and when axis tracking
systems are used (otherwise, they are in the teens). Nuclear plants tend to have the highest capacity
factors (80%-90% in most countries), followed by coal and natural gas. Capacity factors are an
important input in the computation of levelized cost of electricity, since fully loaded costs measure actual
electricity output, rather than theoretical output.
10
3: The journey to 20% US wind penetration by 2030 has hit some air pockets
Every year, Lawrence Berkeley National Laboratory publishes an annual wind study on the US, which gets
4% of its electricity from wind. There are a few positive observations worth noting in the latest report.
First, upfront capital costs are declining after a modest spike in 2009. Second, instances of involuntary
wind power curtailment are declining; this refers to electricity grids being unable to absorb all the wind
power available for use, resulting in “unused” wind generation. And third, there has been an increase in
transmission line deployment, which helps to reduce the involuntary curtailment shown in the middle
chart. There are another 15,000 miles of transmission lines in various stages of development, some of
which are dedicated to sourcing wind from interior locations. One example of success: after the
completion of 3,600 miles of transmission lines as part of the Texas Competitive Renewable Energy Zone in
2013, ERCOT reports that wind-related congestion between West Texas and other zones has largely
disappeared.
Wind project costs trending lower
Involuntary curtailment declining
Capacity-weighted project cost, 2013 $ / kW
Percent of annual potential wind generation
$6,000
10%
Progress overcoming transmission
barriers, Transmission lines added (miles)
by year and voltage
4,000
$5,000
8%
3,500
3,000
$4,000
6%
500 kV
345 kV
≤ 230 kV
2,500
$3,000
2,000
4%
1,500
$2,000
1,000
2%
$1,000
500
$0
1983 1987 1991 1995 1999 2003 2007 2011
Source: LBNL. 2013.
0
0%
2009
2010
2011
2007 2008 2009 2010 2011 2012 2013
Source: FERC, LBNL. 2013.
Source: LBNL. 2013.
2012
2013
Wind is a mature industry in terms of technology: US capacity factors [see p.10] have ranged in the mid
30’s for the last few years when evaluated based on year of construction. Even if wind lost to involuntary
curtailment were included in the generation numbers, capacity factors would only rise by 1%-2%. Why
are capacity factors stable despite productivity enhancements such as taller hub heights and larger rotor
diameters? In isolation, these enhancements do improve the efficiency of the US fleet, but projects are
increasingly being built in less optimal (i.e., less windy) locations, as shown in the second chart. As a result,
less optimal locations have roughly offset productivity improvements when looking at overall capacity
factors. Expansion of transmission lines can re-launch projects in windier more remote locations, which is
what happened in 2013.
Stable US wind capacity factors imply mature technology
Average 2013 capacity factor by year of construction
"Windiness" of project locations by year of construction
Index of wind quality resource at 80 meters, with 1998-99 = 100
40%
100
35%
96
30%
92
25%
88
More windy locations
Less windy locations
84
20%
80
15%
2000
2002
2004
2006
2008
2010
Source: Lawrence Berkeley National Laboratory. August 2014.
2012
1998- 2000- 2002- 2004- 2006 2007 2008 2009 2010 2011 2012 2013
99
01
03
05
11
The good news on the prior page obscures the elephant in the room: continued reliance on
subsidies to maintain capacity growth. Subsidies have been in place almost continuously since 1994.
Whenever subsidy extension was unclear, capacity additions fell in the following year by 70%-90% (in
2000, 2002 and 2004). It happened again in 2013, when the Production Tax Credit (PTC) lapsed and was
extended in January 2013 for one year (for projects started that year), and capacity additions fell sharply.
Currently, the US is still ahead of the Department of Energy “20% Wind by 2030” deployment path.
However, capacity projections from the EIA and from private sector consultants for 2014-2016 are well
below the DoE deployment path, a reflection of uncertainties regarding the future extension of subsidies,
and the fact that many states are now closer to meeting their Renewable Portfolio Standards (see next
page for map of binding and non-binding goals).
20% US wind by 2030? Ahead of schedule in 2012, but running into "headwinds"
Annual wind capacity additions (GW)
Tracking the wind deployment path
18
16
14
Actual wind capacity additions
(brown bars) exceeded the US DoE
deployment path (blue bars) in every
year from 2006 to 2012. By the end
of 2012, the US was ahead of DoE
projections. The small amount of
additions in 2013 wiped out 40% of
the progress that had been made vs.
the deployment path. Projections for
future additions (dotted brown bars)
are well below the deployment path.
Deployment path in 20% Wind Report
Actual wind installations
Average projection
12
10
8
6
4
2
0
2006 2008 2010 2012 2014 2016 2018 2020
Source: Lawrence Berkeley National Laboratory, DOE. August 2014.
2022
2024
2026
2028
2030
Why do capacity additions plummet when it appears that subsidies may lapse? The wind industry
and utilities that sign power purchase agreements have become reliant on subsidies, and rush to complete
projects if there’s a risk subsidies might go away (that may partially explain the spike in additions in 2012).
Subsidies provide depreciation benefits and tax credits which are only valuable to entities with substantial
taxable income. As a result, tax equity partners are often brought in to monetize the tax benefit. The
search for yield by investors has contributed to a decline in 20-25 year power purchase agreement prices
signed by utilities, which have fallen from 6 cents per kWh in 2009 to 2.5-3.0 cents per kWh today for
optimal interior (Midwest) wind locations.
How important are subsides to the current financing
approach? Very. Assuming a contract price of 4
cents per kWh and assuming the upper end of wind
capacity factors of 40%, it would probably be
difficult to mobilize private sector capital for wind
projects without Cash Grants, Production Tax
Credits or Investment Tax Credits. A simplified
11
model illustrates why. At 4 cents per kWh and
without subsidies (the first 2 rows in the table),
estimated after-tax returns would not be sufficient
to get the project financed, whether tax partners
were present or not.
After tax returns to wind project partners
Operating
Scenario
Partner
No incentives; no Tax Partner
2.7%
No incentives; with Tax Partner*
13.9%
Cash Grant = 30% of upfront cost
Production Tax Credits of 2.3-2.8
cents per kWh
Investment Tax Credit = 30% of
upfront cost
Tax Equity
Partner
N/A
-6.7%
9.0%
N/A
13.6%
9.8%
9.3%
8.5%
Source: J.P. Morgan Asset Management. * Assuming the same capital,
cash flow and tax allocation splits as the PTC scenario, but without the
benefit of the PTC
11
Capital cost of $1,750 per kW; 40% capacity factor; 25-year life with 25-year Power Purchase Agreement at 4.0
cents per kWh, growing at 1% annually; operating and maintenance expenses of 1.0 cent per kWh, indexed to
inflation. Operating Partner finances their share with 65% debt and 35% equity using a 5%-6% cost of debt. Tax
Equity partners, when present, are assumed to finance 59%-66% of project costs. Bonus depreciation assumed.
12
What would happen if tax subsidies lapsed permanently? On paper, our sense is that power
purchase agreement prices would simply rise back to 5.5 - 6.0 cents per kWh and eliminate the need for
tax equity partners. Long-term non-escalating agreements for wind at these prices seems like they would
still be attractive to utilities compared to other alternatives, particularly given uncertainty around future
natural gas prices. However, with utilities having been able to sign cheaper PPAs in recent years, they
might wait and see if subsidies are reintroduced rather than pay more. Some argue that wind generation
should qualify for tax-advantaged Master Limited Partnership status in the absence of the PTC subsidy,
since the natural gas industry benefits from MLPs that effectively lower the cost of distribution and final
price of natural gas supplies. To-date, MLP status remains unavailable to power generation companies.
All things considered, the next decade is a lot less certain for wind than the prior one:
 The PTC has expired again and nothing has replaced it (the current lapse is the longest since 1992)
 Natural gas prices fell below $6 in 2009 and have averaged $4 since, lowering the break-even cost wind
is often benchmarked against
 Electricity demand is growing slowly at 1% due to sub-trend GDP growth and increased efficiencies
 The US has not adopted a carbon tax on fossil fuels, a federally binding Renewable Portfolio Standard or
a plan to nationally integrate the electricity grid12 (all of which would increase wind demand)
 Twenty-nine states passed their own mandatory Renewable Portfolio Standards which may eventually
create more demand for wind. However, as stated above, many states are well on their way to already
meeting their standards (most did not adopt California’s higher target of 33%)
 While transmission investment is rising, in some locations with good wind resources (e.g., Wyoming and
Montana), local and regional grid investment is insufficient to incent greater wind development
Given these circumstances, for wind to reach a larger footprint as envisioned by the DoE in the
years ahead, one or more of the factors above will have to change.
Binding and Non- Binding Renewable Energy Portfolio Standards by state
12
There’s a $1.2 billion project (TresAmigas, in Clovis, New Mexico) which for the first time will allow western US,
Texas and eastern US grids to exchange small amounts of electricity. The first phase of the project entails enough
transmission capacity to exchange 750 MW of power, about as much as the output of a single large coal plant. Most
of the power will still need to move on either end through aging transmission systems that are subject to congestion;
the project was not designed to address the larger issue of stranded renewable capacity on a national or regional
level. Furthermore and to the point made above, the project has no government guarantees or financial support.
13
4: The sun also rises: an early look at solar power in the US
While sunlight has the highest theoretical potential of the earth’s renewable energy sources (solar energy
hitting the earth every few hours is equal to a year of global energy consumption), its real-world limitations
and costs have made its adoption slower than wind. Over the last few years, however, falling component
costs and subsidies spurred substantial growth in utility-scale photovoltaic and concentrated solar power.
There is finally a critical mass of US projects to analyze, and which form the basis for this section13.
First, to level-set everyone’s understanding of the status quo, the US gets just 0.2% of its electricity from
utility-scale and large commercial solar installations > 1 MW in size14. Around 6.3 GW of capacity are in
operation; even if all 40 GW of planned solar projects in interconnection queues at the end of 2013 were
completed, the 0.2% would rise to just 2.0%. Capacity forecasts from the EIA and the Solar Energy
Industries Association imply that solar’s contribution will rise to 0.6%-0.9% of US electricity generation by
2016, which would still leave solar behind biomass.
US electricity generation from utility-scale solar > 1 MW
% of total generation
2013 (actual), installed base of 6.3 GW
2016: after EIA projected additions of 9 GW
2016: after SEIA projected additions of 16 GW
2016: completion of entire queue (40 GW)
0.2%
0.6%
0.9%
2.0%
Sources: EIA, SEIA. 2014. Future completions assume capacity
factors of 27% and DC/AC ratio of 1.25
Largest shares of solar electricity as % of total generation
Country
Share Country
Share Country Share
Italy
7.8% Czech Rep
2.4%
Japan
1.0%
Germany
4.7% Belgium
2.3%
Austria
0.9%
Spain
4.6% Slovakia
2.1%
Portugal
0.9%
Bulgaria
3.2% Denmark
1.5%
France
0.8%
Greece
3.2% Australia
1.5%
Israel
0.8%
So urce: B P Statistical Review o f Wo rld Energy. 2013.
From an international perspective, even with 1% of generation from solar, the US would rank below most
of Europe. However, some context is needed regarding solar penetration in countries like Italy, Germany
and Spain. Feed-in tariffs and other subsidies which played a key role in sponsoring solar growth are being
phased out due to budget constraints (see page 16 for more details). In the top three countries, solar
capacity growth averaged 65% annually from 2005 to 2012; in 2013, it rose by just 9%.
The primary factors driving the increase in US solar installations: subsidies, Renewable Portfolio
Standards and the decline in module costs for photovoltaic solar. There have also been declines in
“balance of system” costs (labor, other supply chain costs, acquisition/permitting costs, taxes). For reasons
we explain later, we do not expect substantial component cost declines in the near future. [Around 80% of
US utility scale solar is photovoltaic; the remainder is concentrated solar/thermal].
Photovoltaic upfront capital costs
Silicon and thin film module prices are leveling out
USD per kW-DC
USD per kW-DC, modeled for 185 MW project
$2,000
$4,500
$4,000
$3,500
Balance of System
Inverter
Module
$1,750
$1,500
$3,000
$2,500
Average silicon
module
$1,250
$2,000
$1,000
$1,500
$1,000
$750
$500
$0
2009
2010
2011
2012
Source: National Renewable Energy Laboratory. 2014.
2013
$500
2010
Average thin film
module
2011
2012
2013
2014
Source: Bloomberg. September 24, 2014.
13
A source of confusion in solar power research relates to the fact that unlike other generation types, PV solar
generates DC power which is converted to AC power via an inverter before being transferred to the grid. To
optimize costs and output, solar project DC capacity is typically higher than the AC capacity based on its inverter. PV
solar capital costs and capacity factors can be computed in either DC or AC terms, which should be explicitly noted
to avoid apples-to-oranges comparisons (and which we do here).
14
The GW of residential and commercial installations less than 1 MW are roughly the same as utility scale and
commercial > 1 MW, and tend to have lower capacity factors.
14
The good news on solar, other than falling capital costs: notable improvements in capacity
factors cited by Lawrence Berkeley National Laboratory on newer projects. PV solar in areas with
less solar irradiance (radiation received per unit of area per day) and with traditional fixed-tilt panels
generate capacity factors (see p.10) in the high teens. However, LBNL found that in sunnier Southwest
locations (see map on p.17), when more expensive systems whose panels track the arc of the sun are used,
and when DC panels are over-built relative to AC inverter capacity, capacity factors can be 10%-12%
higher. Consistent with these findings, the National Renewable Energy Laboratory reports capacity factors
increasing by 6% with 1- or 2-axis tracking vs. fixed tilt panels.
LBNL sample set: PV solar capacity factors based on location and design
Solar energy per sq.
meter on an average day
Photovoltaic system
type
Amount of DC
over-building
vs. AC inverter
Net capacity
factor (AC)
Low (<5 kWh/m2/d)
Fixed tilt
Low (<115%)
Low
Fixed tilt
High (>125%)
Low
Single axis tracking
Low
Medium (5-7 kWh/m2/d)
Fixed tilt
Low
Medium
Fixed tilt
High
Medium
Low
Medium
High
High (>=7 kWh/m2/d)
Fixed tilt
High
High
Low
High
High
Source: LBNL sample set of 64 projects totaling 1.5 GW, 2007-2012 vintage
17%
19%
23%
23%
25%
27%
28%
29%
29%
31%
On PV solar capacity factors
Sunnier locations, panels that track the arc of
the sun, and higher degrees of DC overbuilding contribute to higher capacity factors.
The LBNL survey of capacity factors involves 64
recently built projects totaling 1.5 GW of
capacity. This is a reasonable sample set, but
for comparison purposes, there was 6.3 GW of
solar power installed in the US at the end of
2013; and the sample set for the 2013 LBNL
wind report involved 582 projects and 57 GW
of capacity.
Once you estimate capital costs, capacity factors, financing costs and ongoing operation and maintenance
(O&M) expenses15, you can compute levelized costs per MWh. However, when capital costs decline
sharply, levelized cost is a moving target. The range of capital costs reported for PV solar is very wide, a
reflection of different methodologies. Some studies show costs of projects completed in a given year;
others model projects that are planned and contracted in a given year; and others are based on selective
surveys of projects in optimal locations. Industry surveys of existing projects in the planning stage are (in
my view) more relevant to the concept of levelized cost than projects contracted in prior years. However,
without transparency around how surveys are done, historical costs on all project completions from
agencies like the EIA and LBNL are still important to look at. This is particularly the case when there are
outlier observations, such as Lazard estimates of capital costs. As shown below, there’s a lot more
consistency on capital costs of completed projects than on future ones.
PV solar capital cost estimates: they mean very different things depending upon who is
computing them, and how
Provider
Energy Information Administration
National Renewable Energy Laboratory
Lawrence Berkeley National Laboratory
Bloomberg New Energy Finance
Lazard
$/kW-AC
$3,873
$3,750
$3,700
$3,046
$2,463
$2,250
$1,750
Methodology
Consultant study of projects coming online in 2013
Projects completed in 2013
Projects completed in 2013
Modeled cost for 2019 delivery
Estimate for c-Si tracking projects begun in 2014
Estimate for c-Si fixed axis projects begun in 2014
Estimate for c-Si tracking projects begun in 2014
Source: JPMAM. Original $/kW-DC sources converted to $/kW-AC using a 1.25 DC/AC ratio. c-Si = crystalline silicon
15
The LBNL report notes that reporting of O&M costs is sparse, does not have much history and is insufficient for
drawing conclusions about levels or trends; instead they rely on rating agency research for these numbers. This may
not be a very reliable approach: a paper presented in 2011 at the Syracuse Biophysical Economics Conference by
an operator of solar plants in Spain estimates that after taking unexpected operating and maintenance expenses into
account, the energy return on investment for solar was closer to 3x than to 8x.
15
So, given improved productivity and falling capital costs, how do all-in costs for solar compare with wind
and natural gas? The charts below show US estimates from the EIA and Lazard, and global estimates from
Bloomberg New Energy Finance. All show an impressive and rapid convergence of solar levelized costs
relative to wind and natural gas, but levels differ. There’s more agreement on capacity factors than on
capital cost; Lazard’s estimate of the latter is much lower, as are their estimates for O&M costs. Keep in
mind that levelized costs for wind and solar power are as much an abstraction as they are a
reality, since they assume future unknowns (capacity factors, O&M costs, wind/solar conditions),
they vary by location, and they do not incorporate most transmission or back-up generation
costs required due to intermittency.
US Energy Information Agency
Lazard's energy group
Average levelized cost of electricity, USD / MWh
Levelized cost of electricity, USD / MWh
$400
Average levelized cost of electricity, USD / MWh
$400
$400
$350
$350
$350
$300
$300
$250
$250
$200
$150
$100
$50
$200
$150
Wind
$100
$50
Nat Gas - Combined Cycle
2014
Crystalline silicon,
single axis tracking
$250
$150
Wind
Crystalline silicon,
fixed tilt
$300
Optimal US
location
$200
PV Solar
$0
2009
2010
2011
2012
2013
Source: EIA annual energy outlook reports
Crystalline silicon with
tracking (global average)
$100
$50
Nat Gas - Combined Cycle
$0
2009 2010 2011 2012 2013
Source: Bloomberg New Energy Finance
2014
Wind
(avg)
$0
2009
2010
2011
2012
2013
2014
Source: Lazard LOCE Analysis 8.0. 2014.
One thing is undeniable: power purchase agreement prices for solar power have declined
steadily. This reflects falling components costs, and the fact that the solar industry has been more
fortunate than wind: its subsidies have not lapsed, and have generally been extended for longer periods of
time (the latest extension was for 8 years). As shown on page 12, subsidies can have a huge impact on the
attractiveness of alternative energy projects to investors, and solar is no exception.
Declining solar power purchase agreement prices
Government subsidies to Chinese firms, 1985-2005
Annual, $ bn
Levelized PPA, USD per MWh
Cumulative, $ bn
$250
$25
$200
$20
$150
$15
$200
$100
$10
$150
$50
$5
$350
$300
$250
$100
$0
$0
2006 2007 2008 2009 2010 2011 2012
Source: Lawrence Berkeley National Laboratory. 2014.
2013
2014
$50
$0
1985
1989
1993
1997
2001
2005
Source: “Subsidies to Chinese Industry”, Usha Haley and George Haley,
Oxf ord University Press, April 2013.
Where to from here? The primary questions relate to capital costs and subsidies. As shown above
(right), China provided massive subsidies to its steel, auto, solar, glass and paper industries for many years.
Notably, its 5 largest solar companies received the equivalent of $31 billion in low-interest credit lines from
the state-owned China Development Bank and other subsidies from national and provincial governments.
As a result, Chinese PV module production soared and prices collapsed. You might have expected solar
companies to go out of business and rationalize supply; in both the US and China, some did. However,
China burns coal for 68% of its electricity and has set a target below 60% by 2020. Government plans call
for 14 GW per year in solar power, and 100 GW by 2020. So far this year, only 3 GW have been installed,
creating a backlog in demand for Chinese solar companies. The Chinese government recently clarified grid
16
connection and payment issues regarding distributed solar (residential and commercial installations), which
may help the industry further. As China’s solar industry consolidates and absorbs more of its own
production and given the June 2014 imposition of US tariffs on Chinese and Taiwanese panels, we do not
expect US module prices to fall much further. The experience curve may lower module and balance of
system costs further, but we expect such costs to decline at a much slower pace than during 2008-2012.
On US subsidies, solar faces some of the same challenges as wind. The Investment Tax Credit (ITC)
for solar will fall from 30% to 10% in January 2017. EIA forecasts call for a sharp drop-off in solar
installations when the ITC declines, from 2.6 GW in 2016 to 0.1 GW in 2017. If history repeats itself, solar
subsidies will be extended for multiple years and create another wave of US capacity growth as long as
module prices remain low. Even so, it may take many more years of subsidies and grid interconnection investment for US solar to represent 5% of US electricity generation.
For wind and solar, limitations regarding levelized cost estimates relate to their intermittency and
the consequent need for back-up power. The development of cost-effective electricity storage would
reduce the need for back-up power, and increase the relevance of levelized cost estimates. That’s the
subject of our final section: progress to-date in storing electricity.
Map of LBNL sample set of US solar projects built from 2010 – 2013 by type and solar resource quality
Solar outlook for Europe. Feed-in tariffs played a large role in sponsoring solar capacity growth in Europe, which
averaged 65% annually from 2005 to 2012:
 The Spanish government paid renewable energy producers $41 billion more than the power was worth on the open
market since 2000; Italy has had a solar feed-in tariff since the 1990’s; and in Germany, feed-in tariffs paid renewable
electricity producers 17 Euro cents per kWh compared to a price of 3.2 Euro cents on the open market.
 However, budget cuts resulting from the European debt crisis changed the subsidy landscape. Spain terminated its
feed-in tariff and retroactively capped payments on existing projects; after the changes, solar employment in Spain fell
from 60,000 to 5,000. Italy reduced the scope of its feed-in tariff program, and introduced a 10.5% tax on large
renewable energy producers.
 In Germany, there haven’t been changes yet, but they may come: the renewable energy surcharge levied on German
households and businesses has nearly tripled since 2010 and now accounts for ~18% of a German household's electric
bill. On the supply side, generation companies like Eon and RWE are closing power stations due to falling revenues.
Bottom line: in 2013, European solar capacity growth slowed to 9%, and the low end scenario from the European
Photovoltaic Industry Association shows 8% capacity growth through 2018.
17
5: The ongoing search for energy storage
Even when it’s windy and sunny, electricity demand patterns may not match up well with supply.
Examples: nighttime Texas wind coincides with weaker electricity demand, and in California, growing solar
capacity additions will provide plenty of power mid-day, but will also require massive ramp-up of nonrenewable sources to meet peak demand in the early evening (see charts). As a result, without storage,
substantial increases in renewable energy may require one or more of the following:
 Curtailment of natural gas: in locations where there is plenty of gas, this is the preferred option. Newer
combined cycle gas plants are designed to be ramped up and down with only a modest loss of efficiency.
 Curtailment of coal: this is not as easy. Coal plants are not designed to be ramped up and down, and
suffer substantial losses in efficiency when doing so.
 Curtailment of renewables: the sun shines or the wind blows but the energy is not harnessed and supplied
to the grid. An opportunity loss for owners of renewable capacity that require a return on invested capital.
 Maintenance of costly back-up dispatchable power: usually natural gas or oil peaker plants.
 Much greater investment in regional or national electricity grids: costly at a time of fiscal restraint.
However, if energy could be stored at a reasonable cost and without too much loss, it could be made
available during periods of peak demand and contribute to lower electricity prices, reduce carbon
emissions, reduce wind/solar curtailment and reduce the need for back-up power. Can it be done?
Texas electricity demand vs. actual wind output
Gigawatts
Gigawatts
70
6
Demand
65
5
60
26
4
22
3
20
50
45
As solar power is added, baseload power
requirements fall mid-day and then ramp up
sharply in the early evening. Load shifting would
ideally flatten the baseload power curve
18
40
2
35
30
20
8/1/11
28
24
55
25
California solar power growth creates ideal conditions
for load-shifting, baseload power required by hour, GW
Wind output
8/2/11
8/3/11
8/4/11
8/5/11
8/6/11
8/7/11
8/8/11
Source: Electric Reliability Council of Texas. Data as of August 8th, 2011.
2012
2013
2014
16
1
14
0
12
12 am
2015
2020
4 am
8 am
12 pm
4 pm
8 pm
Hour of the day on March 31 of each year
Source: California Independent System Operator. March 2014.
First, the basics. Most electricity is used when generated
and not stored. Storage facilities are equal to just 2% of
installed global generating capacity, and most can only
store minutes or a few hours of supply. The most
common approach is pumped storage: pump water
uphill into a naturally-occurring or man-made reservoir at
night when electricity prices and demand are lower, and
discharge the water downhill to spin a turbine during the
day when prices and demand are higher. According to
the Electric Power Research Institute (EPRI), pumped
storage accounts for 99% of all electricity stored around
the world. Pumped storage efficiency rates range from
70%-85% (i.e., the amount of electricity discharged
relative to how much is used to pump the water uphill16).
12 am
Seneca pumped storage and
hydroelectric facility,
Warren County, Pennsylvania
16
A reservoir one kilometer in diameter with a depth of 25 meters holds roughly 10,000 megawatt-hours of electricity
[for comparison, Ann Arbor, MI uses 5,000 megawatt-hours per day while Dallas, TX uses 50,000]. The reservoir and
hydroelectric dam shown in the picture are located in Warren County, Pennsylvania and can hold enough water to
generate roughly 4,800 megawatt-hours of electricity. Photo courtesy of the U.S. Army Corps of Engineers.
18
Pumped storage can be designed with capacities up to 4,000 MW and which may last 50-60 years. Fullyloaded, levelized costs range from $150 to $200 per megawatt-hour of discharged electricity. How cheap
does energy storage “need” to be to result in broader adoption? This is no longer an abstract
discussion: Japan, Germany, South Korea and some US states have passed legislation requiring minimum
levels of electricity storage (California approved a mandate in 2013 that requires utilities to add 1.3 GW of
grid storage by 2020). The answer depends on whether we are referring to bulk or localized storage.
Bulk storage. Pumped hydro facilities are an example of “bulk storage”, which involves storing large
amounts of electricity (20 MW or more) that can be discharged over several hours if needed. Think of a
municipality seeking to store excess wind generated at night, draw upon it during the day and not have to
build and maintain back-up dispatchable natural gas plants to meet peak demand. Another example: a
large industrial farm in California seeking to load-shift solar energy from noon to evening watering times.
To get a sense for bulk storage options and their respective costs, we met with Energy Storage Program
Manager Haresh Kamath from EPRI to review a report jointly prepared by EPRI, the DoE and Sandia
National Laboratories. The next chart shows bulk storage approaches and EPRI estimates of their levelized
costs per MWh of discharged electricity17. We differentiate the market-readiness of each through the color
of the bars: only dark and light blue ones are now in use. Based on the principle that storage would
first displace the most expensive electricity source on the dispatch curve, we compare each approach to
natural gas peaker plant18 levelized costs of $170 to $220 per MWh (dotted lines, based on data from the
EIA and Lazard). These are national averages, so in some locations breakeven costs would be higher/lower.
Cost effective second-generation bulk electricity storage solutions are still in the lab
Levelized cost per MWh of discharged electricity, US$
$900
$800
$700
$600
Development stage
Mature
Existing
Emerging
Demonstration
$500
$400
$300
Solid Electrode Batteries
Liquid Electrode
Batteries
Flow Batteries
Potential Energy
Nat Gas peaker
range
$200
$100
$0
Pumped Hydro Compressed Air Advanced Lead
Lithium Ion
Zinc Hybrid
(280-900MW,
(50-400MW,
Acid
(1-3MW, 4-5 Hrs) (50MW, 6 Hrs)
8-16 Hrs)
5-8 Hrs)
(50MW, 5 Hrs)
Sodium Sulfur Sodium Nickel Vanadium Redox Zinc Bromine
Iron Chromium
(50-100MW,
Chloride
(50MW, 5 Hrs)
(10MW, 5 Hrs) (50MW, 5-10 Hrs)
6-7.2 Hrs)
(50-53MW, 5 Hrs)
Source: Sandia National Laboratories, Electricity Storage Handbook. July 2013.
While some cost estimates appear close to natural gas peaker plant levels, most are not mature
in terms of field-testing and reliable execution on a utility scale. This leaves first-generation
solutions (pumped storage and compressed air) as the most cost effective ones now in use.
On the chart: natural gas comparison lines are not static with respect to the magnitude of bulk storage. If
bulk storage were added in large amounts, the next most expensive electricity source on the dispatch curve
would become the break-even that storage would then have to beat. In some places, bulk storage would
compete with baseload coal after displacing natural gas peaker plants, and then compete with combined
cycle natural gas plants whose levelized costs are closer to $60-70 per MWh. In other words, early
applications of bulk storage are likely to have the greatest payoff per MWh, with future storage
build-outs competing with cheaper power. One last point on bulk storage: if natural gas prices ever
rose sharply or if a carbon tax were applied, breakeven costs would shift upwards, making storage a more
economic solution when charged by renewable energy.
17
We prefer to compare levelized costs per discharged MWh rather than $/MW of installed capacity, since the latter
does not incorporate the duration of nameplate power, or the different lifespans of the technologies involved.
18
There are unique situations where gas is not the most expensive part of the dispatch curve that storage would
replace. One example is Hawaii where oil peakers are used given the scarcity of gas. Furthermore, when gas falls
below $3 per mm btu, in some locations, coal can be more expensive and used for peaking power instead.
19
Distributed energy storage. A more efficient approach might involve distributed (e.g., local) storage
rather than remote bulk storage. Bulk storage still requires transmission lines and interconnections that
can handle large flows of electricity at times of peak demand. The process might work better if energy
were stored closer to its point of use: there would be less transmission congestion, since power generated
at night would also be distributed at night (when power lines are not as heavily used) and not during the
day (as is the case with bulk co-located storage). As a result, distributed storage could enable less longterm investment and upgrades in new transmission and distribution assets.
Measuring the cost/benefit of distributed storage is more complicated than for bulk storage. Distributed
storage value comes from being able to provide energy both when and where you need it; and from the
benefit of reducing locally incurred demand charges for guaranteed capacity. The value of distributed
storage is better compared to the cost of transmission and distribution than to the cost of generation.
One example: ConEdison is developing a storage program in NYC with the goal of reducing its purchases
of energy at high marginal prices. The ConEdison program reimburses customers for the cost of storage
installed on the customer side of the meter when it reduces the load on ConEdison’s system and its
transmission lines. For this service, ConEdison is willing to pay up to 50% of the cost of the storage, up to
$2,100/kW. The reason the storage is valuable has nothing to do with the levelized cost of generation; it
has to do with the supply and demand of energy in the New York City market where supply is limited
because of transmission constraints.
To be clear, distributed storage is still more of a concept than a reality. As shown below, of the
electricity stored globally, over 99% involves bulk storage via pumped hydro. Distributed storage, mostly
accomplished via different kinds of batteries and thermal storage, is still in its infancy according to EPRI
data. One challenge: distributed storage in homes, businesses and small towns often entails smaller units
with higher energy densities that have lower economies of scale than bulk storage. Localized use may also
disqualify approaches that involve combustible and/or hazardous materials, very high temperatures or other
safety issues. Two approaches described above are currently viable for distributed storage applications of
500 kW to 1 MW: lead acid and lithium ion batteries. However, according to EPRI, both are much costlier
on a distributed basis than on a bulk storage basis. EPRI zinc hybrid cost estimates do not rise much in
smaller applications, but this is an approach which is still under development.
2013 Global Deployment Snapshot: Pumped hydro accounts for 98%+ of storable power/energy
Approach
Primary use
Pumped hydro
Compressed air
Thermal storage
Batteries
Hydrogen storage
Flywheels
Bulk
Bulk
Distributed
Distributed
Distributed
Distributed
Installed power (MW) Installed energy (MWh)
141,000
435
1,570
387
3
898
1,420,000
4,010
3,734
595
35
9
Source: EPRI, July 2014. Installed storage of 144,000 MW is 2.4% of installed global electricity generation capacity of 6 TW.
Our bottom line: there are unique local circumstances in which bulk and distributed storage already make
sense using existing technologies. However, a broader, nationwide adoption of electricity storage is likely
to require a combination of more time and technological progress, policy changes (e.g., universal
allowance for utilities to include storage capital costs in rate base calculations), and more externalities
included in fossil fuel prices.
20
Sources and Acknowledgments
In addition to Vaclav’s insights, we benefitted from the contributions of other individuals whose insights
were instrumental in the preparation of this paper. Special thanks to Haresh Kameth and Ben Kaun from
EPRI and Steve Hellman from EOS for their time, insights and edits on our electricity storage drafts. On
solar, we learned a lot from Ted James and Ran Fu at NREL, who also helped us uncover a methodology
error at the EIA regarding solar capacity factors (the EIA was understating them substantially; after
correcting for the error, LBNL and EIA capacity factor measures for PV solar are very similar). Mark
Bollinger and Andrew Mills at the LBNL and the team at Bloomberg New Energy Finance were generous
with their time as well with respect to discussions on solar and wind.
General energy compendiums
2014 EIA Annual Energy Outlook and the 2014 BP Statistical Review of World Energy
Introduction
“How Green Is Europe?”, Vaclav Smil, The American, September 30, 2014.
US Energy Independence
“400 projects to change the world”, Goldman Sachs, May 16, 2014.
“Drilling California: A Reality Check on the Monterey Shale”, J. David Hughes, Post Carbon Institute,
Physicians, Scientists & Engineers for Healthy Energy. December 2013.
Update on the rising cost of nuclear power
“Lazard’s Levelized Cost of Energy Analysis – Version 7.0”, August 2013.
“The cost of nuclear electricity: France after Fukushima”, Nicolas Boccard (University of Girona – Spain),
“World Nuclear Association – Reactor Database”, June 2014.
Update on wind power
“2013 Wind Technologies Market Report”, US Department of Energy, Wiser and Bolinger, Berkeley National
Laboratory, August 2014.
Update on solar power
“Germany’s Expensive Gamble on Renewable Energy”, Matthew Karnitschnig, Wall Street Journal, August 2014
“Global Market Outlook for Photovoltaics 2014-2018”, European Photovoltaic Industry Association, 2014
“Governments Rip Up Renewable Contracts”, Brady Yauch, Financial Post, March 2014
“H2 2014 Global LCOE Outlook”, Bloomberg New Energy Finance, August 2014
“Photovoltaic System Pricing Trends: Historical, Recent, and Near-Term Projections”, National Renewable
Energy Laboratory and Berkeley National Laboratory, September 2014
“Utility Scale Solar 2013: An Empirical Analysis of Project Cost, Performance, and Pricing Trends in the
United States”, Bollinger and Weaver, Berkeley National Laboratory, September 2014
Lazard Levelized Cost of Energy Analysis, version 8.0, September 2014
Progress to-date in utility-scale battery storage
“Electricity Storage in Utility Applications”, Haresh Kamath, Electricity Power Research Institute,
September 2013.
“Sandia Report – DOE/EPRI 2013 Electricity Storage Handbook”, July 2013.
“Grid Energy Storage”, US Department of Energy, December 2013.
21
Appendix I: Additional detail on storage levelized costs and technologies
The table provides context on development stages used to describe each technology. Then, some brief
details on the mechanics of each.
Key Word
Description
Mature
Mature technology with multiple existing units and operating history
Existing
Existing but less mature technology with fewer installations and a wider range of observed costs
New technology now being implemented with small applications in field conditions for the first time; limited experience on
operational, maintenance or life cycle costs
Demonstration Early stage of field deployment and demonstration trials on small applications; substantial scale-up uncertainties
Emerging
Source: Sandia National Laboratories, Electricity Storage Handbook . July 2013.
Storing potential energy. Pumped storage is one way to harness potential energy; compressed air is
another (when electricity demand rises, the stored air is released and powers a turbine), but there are still
only two significant commercial applications. The world’s first compressed air storage began to operate in
salt caverns underneath Huntorf, Germany in 1978 and it remains the largest project (capacity of 321 MW
over two hours); McIntosh in Alabama (completed in 1991) is rated at 110 MW. The cost of pumped
storage and compressed air falls slightly above the optimal zone in the chart; existing projects often
19
benefited from government subsidies or unique circumstances in which break-even costs are higher.
Solid Electrode Batteries. This is the traditional battery concept used in cars and electronic devices: two
solid metal electrodes (an anode and a cathode) are connected by an electrolyte which serves as a
conductor. The opposing charges prompt the anode to shed electrons and the cathode to attract
electrons, with the electron flow generating electricity. Advanced lead acid and lithium ion batteries are
less well-suited to bulk storage given life-cycle and efficiency limitations, maintenance requirements and
disposal costs. Zinc hybrid battery technology is potentially promising for both bulk and localized
applications in terms of its efficiency, life-cycle and energy density properties, but remains in the early
stages of demonstration.
Liquid Electrode Batteries. Metal electrodes exist in their liquid states, and are connected by an electrolyte
in a way to maximize the conductive surface area. While these batteries are highly efficient (round trip
efficiency of ~90%) and provide up to 6 hours of energy delivery, compounds used in these batteries are
very reactive (operating temperatures > 300 degrees C) and often hazardous, requiring extensive heat
management and materials containment. The most frequently used liquid electrode application is sodium
sulfur batteries with over 190 sites and more than 270 MW of capacity in Japan. Sodium-sulfur batteries
entail higher costs and offer much smaller scale than pumped storage: installations in Japan typically range
from 2 to 10 MW. Ideal applications: localized grid support and wind power integration (one facility in
Lucerne can power 500 homes for seven hours).
Flow Batteries. Flow batteries also rely on liquid active materials, but store them in separate tanks which
then feed into a smaller reaction chamber. The presumed advantage of flow batteries is that the tank size
used to store active materials can be scaled up, thereby increasing the amount of energy that can be
stored, without having to increase the size of the electricity-generating reaction chamber. The physical
scale of flow batteries tends to be large, especially in utility scale applications, since the increased capacity
is a result of larger storage tanks (some reaching a height of two stories). In some flow batteries, the active
materials do not degrade over time, making the prospects for longevity encouraging. Flow batteries are still
in the demonstration or emerging phase: there is a small 600 kW Vanadium Redox project underway in
Oxnard California, and US utilities plan to start field-testing 1 MW Zinc Bromine systems in 2014-2015.
19
Many pumped storage projects were built in the 1960s/1970s when utilities and the Department of Energy
expected large baseload nuclear power additions, such that nuclear + storage (to manage peak demand) would be
cheaper than other sources such as coal. This led to storage subsidies from the Federal government.
22
Appendix II: The cautionary tale of the Monterey Shale
Production is hard to predict, and in the case of shale oil, there have been notable misses (both high and
low). On the low side, EIA forecasts for US shale oil production have been too conservative, perhaps a byproduct of underestimating productivity per well for both shale oil and shale gas [oil production per well at
Eagle Ford and Bakken rose from 200 bpd in 2010 to 500 bpd in 2013]. While recent production of shale
oil has exceeded expectations, the industry is still relatively young; shale oil’s exponential decline rates
require a constant stream of new finds in order to maintain production forecasts.
As for estimates that proved too high, there was a collapse in recoverable oil projections for California’s
Monterey shale this year. In 2011, projections for Monterey were ~4 million bpd, at which time it was
projected to hold nearly two-thirds of all US recoverable shale oil reserves. In May 2014, the EIA cut its
Monterey forecast by 96%. What happened? According to our industry contacts, the Monterey
outlook was based on poor geological comparables (Bakken and Eagle Ford). Monterey has shale burial
depths ranging from 2,000 to more than 18,000 feet; spans 1,800 square miles, and would require 16
wells per square mile. In contrast, Bakken/Eagle Ford shale depths are more consistent, the region spans
8,000 square miles, and 1-2 wells are drilled per square mile. As a result, Bakken/Eagle Ford drilling and
recovery operations are more homogenous and less cramped than in the Monterey region. This downward
revision was not that surprising to many E&P companies, since only one was actively pursuing the shale oil
opportunity in the Monterey region, and since it has no impact on the immediate future of oil and gas
shale production. Still, it is surprising to see EIA-sanctioned forecasts revised down this sharply.
Appendix III: A history of US electricity capacity additions, with EIA forecasts to 2040
2000 marks the beginning of the natural gas century in the United States
Gigawatts, electricity generating capacity additions
60
60
Other renewables
Solar
Wind
Natural gas
Nuclear
Hydropower/other
Coal
EIA Forecasts
50
40
30
50
40
30
20
20
10
10
0
0
1985
1988
1991
1994
1997
2000
2003
2006
2009
2012
2015
2018
2021
2024
2027
2030
2033
2036
2039
Source: EIA. 2013.
23
Acronyms
AC-DC
bpd
BNEF
BTU
c-Si
CAFE
CNG
CPV
CSP
DOE
ECB
E&P
EIA
EPRI
ERCOT
FERC
FTSE
GW
IEA
IOU
ITC
Alternating current – Direct current
Barrels per day
British thermal unit
Crystalline Silicon
Corporate Average Fuel Economy
Compressed Natural Gas
Concentrated Photovolatics
Concentrated solar power
Department of Energy
European Central Bank
Exploration & Production
Electric Power Research Institute
Electric Reliability Council of Texas
Federal Energy Regulatory Commission
Financial Times Stock Exchange
Gigawatt
International Energy Agency
Investor-owned utility
Investment Tax Credit
JPMAM
KW
LBNL
LCOE
LED
MLP
MW
NGL
NREL
NGV
NYSE
O&M
OECD
OPEC
PEV
PTC
PV
RPS
S&P
SEIA
TW
J.P. Morgan Asset Management
Kilowatt
Lawrence Berkeley National Laboratory
Levelized Cost of Energy
Light-emitting diode
Master Limited Partnership
Megawatt
Natural Gas Liquid
Natural gas vehicle
New York Stock Exchange
Operating and Maintenance
Organization for Economic Co-operation and Development
Organization for Petroleum Exporting Countries
Plug-in electric vehicle
Production Tax Credit
Photovoltaic
Renewable Portfolio Standard
Standard & Poor’s
Solar Energy Industries Association
Terawatt
24
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