Medium-term outlook for US power: 2015 = deepest de

Transcription

BNEF White Paper
8 April 2015
Medium-term outlook for US power:
2015 = deepest de-carbonization ever
Contents
1. RENEWABLES:
TEMPORARY BOOM ........2
2. COAL RETIREMENTS:
BEGINNING OF THE
END ...................................3
3. FUEL BURN:
‘STRUCTURAL’ GAS
GROWTH ..........................4
4. CARBON EMISSIONS:
FURTHER TO FALL .........7
APPENDICES .........................8
5. FURTHER READING ........8
In 2015, the US could set new national records: for annual renewable build; for coal retirements;
and for gas burn from the power sector. Meanwhile, electricity-related emissions could fall to their
lowest levels since 1994. This Research Note examines our short-term forecasts for US power.
•
Renewable build will total 18.3GW in 2015 – 9.1GW from solar (an all-time high); 8.9GW from
wind (third-most ever). Both technologies are in the midst of a temporary build rush, as
developers race to capture important federal tax incentives that are set to step down or expire
by 2017. California will account for over half of the solar build in 2015; ERCOT will absorb over
one third of the new wind.
•
The Mercury and Air Toxics Standard (MATS) take effect on 16 April 2015, hastening a wave
of coal retirements among generators whose economics are otherwise challenged by the
effects of old age and cheap gas. In all, expect 23GW to stop burning coal this year, with
another 30GW falling offline before decade-end. PJM and the Southeast will be hardest hit.
•
Natural gas-fired generators are poised to back-fill lost generation from retiring coal; and even
more importantly, plummeting gas prices have enabled efficient, combined-cycle gas turbines
to undercut marginal costs of coal in many parts of the country. Coal-to-gas switch calculus is
complex, but we believe these two factors (lost coal capacity and a relative improvement in
gas-fired economics) will lead to the most gas burn from the power sector ever – more even
than witnessed in 2012 (‘the year of no winter’, when Henry Hub sank below $3/MMBtu).
Figure 1: US power mix
Figure 2: New build and retirements
TWh/year
Figure 3: Fuel burn and CO2 emissions
GW/year
5,000
Fuel burn (quads)
Build
4,500
30
4,000
20
1,473
1,514
2,000
500
255
246
349
237
769
774
2,109
19
15
15.9
10
5
500
0
-
Retirements
2019
2020
2018
2016
Gas
2017
2015
2013
2014
2012
2010
2011
2020
2019
Coal
2018
Renewables
2017
2016
2015
2014
2013
2012
2011
2010
1,000
10.1
-23
-30
Large hydro
1,500
15.4
Gas burn
9.8
-12
-20
0
Nuclear
2,000
2,094
Coal burn
17
-10
1,000
20
0
1,500
Carbon emissions
14
4
10
2,500
2,500
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
3,000
9
1,265
1,239
3,500
Carbon (MtCO2e)
25
40
Oil
Click here to view these same graphs on a US regional basis – and to access other detailed outputs behind this analysis
Source: Bloomberg New Energy Finance, EIA 923, EIA 860, Bloomberg Terminal
•
Meredith Annex
+1 646 324 4147
[email protected]
Only 8% of the nation’s power-sector carbon emissions are actually ‘covered’ by cap-andtrade; meaning only 8% carry a price tag. But the industry should take notice of emissions
levels in light of the Clean Power Plan, which is (mis)-understood to call for a ‘30% carbon cut
from 2005 levels by 2030’. Our estimate puts 2015 emissions at 2,094MtCO2 – 16% below
2005 levels, and roughly 350Mt away from our 2030 ‘goal’. On an emissions rate basis (t/MWh),
2015 will be the cleanest year in over 60 years for which we have historical data.
© Bloomberg Finance L.P.2015
No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact [email protected]. Copyright and
Disclaimer notice on page 10 applies throughout.
Page 1 of 10
BNEF White Paper
8 April 2015
•
This Research Note is more sensationalist than we typically write. While it is true that US power
will break several records in 2015, it is important to keep these changes in a broader context.
Figure 1 tells a relatively sobering story: that at a high level, even when multiple records are
broken, the generation mix from one year to the next looks roughly similar. There is plenty of
inertia in a +1,000GW, +4,000TWh/year system such as the US power grid. Change comes
slowly, even in the most transformative times.
1. RENEWABLES: TEMPORARY BOOM
Installed renewable capacity grows every year. As such, every year breaks a record for total
renewable energy capacity and generation (Figure 4) – but 2015 is shaping up to be an exceptional
year for new installations as well.
Figure 4: Renewable build, cumulative capacity and generation – historic and according to BNEF base case forecast
New build (GW/year)
Cumulative capacity (GW)
250
25
12%
Renewable
penetration
500
200
20
Generation (TWh/yr)
600
400
4.9
12.9
5
100
50
0
0
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
1
Small hydro
Wind
Geothermal
Solar PV (rooftop)
6%
15
12
4
58
15
300
6%
RPS demand
200
4%
74
16
Municipal Waste
Solar PV (utility)
100
2%
0
0%
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
3.5
10
8%
150
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
1.7
1.6
8.9
15
10%
8%
0.9
Biomass
Solar thermal
Biogas
Source: Bloomberg New Energy Finance build and generation forecasts; historical build and generation from EIA Form 860 and Form 923.
Click here for underlying data
•
In total, we expect 18.5GW of renewable build in 2015. This would eclipse the previous record
of 17.1GW observed in 2012. While the 2012 record was met largely as a result of record wind
build ahead of policy expirations, this year will see a nearly even mix of wind and solar. Next
year (2016) could be a repeat of this one, as projects in wind and solar rush to meet completion
dates in line with expiring tax credits.
•
Utility-scale solar installations are expected to reach an all-time high of 4.9GW this year, thanks
to the completion of a handful of mega-projects (+100MW) in California1, and bolstered by a wave
‘baby ground mounts’ in the 1-10MW range. (This 1-10MW range is where we think the sector’s
most promising future lies.) Saturation2 in California and the pending step-down of the federal
1
For example, Mount Signal I PV is a two-phased project totalling 266MW in Imperial Valley, California which
came online in May 2014 and was acquired by TerraForm (the yieldco of SunEdison) shortly thereafter.
2
California is approaching saturation points for utility-scale solar on two fronts: firstly, its existing RPS targets
for 2020 are largely met, eliminating the need for incremental build beyond the existing pipeline; and
secondly, a surplus of installed solar capacity is already causing mid-day prices to sag, due to a phenomena
known as the ‘merit order effect’.
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8 April 2015
Investment Tax Credit (ITC) from 30% to 10% will temporarily cripple the utility-scale solar
business beyond 2016. The next two years will be utility-scale solar’s time in the sun.
•
Rooftop solar is also on the rise, thanks to module cost declines and innovations in financing
and ownership. We expect the US will finish with a record 1.9GW of residential solar
installations in 2015, and another record of 1.6GW on non-residential roof-space. Rooftop solar
will prove more resilient to the step-down of the ITC than utility-scale build, because of
favourable economics (rooftop solar competes against retail electricity prices; utility-scale
against wholesale prices) and broader geographic diversity (less dependence on California).
•
Technically, the Production Tax Credit (PTC) for wind was extended for just two weeks last
December, but in practice, safe-harboured projects have until the end of 2017 to capture the
important federal incentive without facing additional IRS scrutiny. Further extensions beyond the
effective end-date in 2017 are viewed as unlikely with the current US Congress.
As such, developers are racing to bring projects online ahead of 2017 to qualify for the
programme. As part of this wave, we expect nearly 9GW of new wind projects to be
commissioned in 2015, with a similar number pending for 2016. This is almost double the capacity
additions in 2014 (when 4.9GW came online), but is overshadowed by the incredible rush of
projects in 2012 – ahead of the previous expiration of the PTC.
Figure 5: Renewable build
by region (GW/year)
•
RPS requirements jolt upward by 43TWh in 2015 – by far the steepest annual increase in
renewable energy credit (REC) demand in history and in the projected future (Figure 4). States
with the largest annual increase in RPS demand from 2014-15 are as follows: Oklahoma’s
voluntary 15% RPS goal kicks into gear in 2015; California’s RPS marches steadily forward;
and North Carolina, Oregon, Michigan, Colorado and Wisconsin take step-function leaps.
22
20
18
16
Regional build (Figure 5)
14
•
12
At the end of 2014, California housed near half of all installed solar capacity in the US; that
ratio will carry forward into 2015. Part of the reason we think that California took on so much
utility-scale solar capacity relates to the way in which utilities valued the time-of-day production
of a typical solar array. California’s investor-owned utilities (IOUs) may have over-valued the
10
8
6
‘on-peak’ aspect of solar generation during requests for proposals (RFPs) to meet their RPS
demand.
4
2
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
0
SPP
PJM
Northwest
New England
Florida
Hawaii
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
22 ERCOT
20
18 Southeast
16
14
12 Southwest
10
8 New York
6
4
2 MISO
0
California
Alaska
Source: Bloomberg New Energy
Finance
•
Texas is in the midst of its second wave of wind build – with 9GW expected to come online
between 2014 and 2016. The first occurred from 2007-09, when Texas installed nearly 7GW.
Most of the renewable capacity added in ERCOT in 2015 will be located in the Panhandle,
where resources are especially strong, and where the last leg of the Competitive Renewable
Energy Zone (CREZ) transmission lines were recently completed.
2. COAL RETIREMENTS: BEGINNING OF THE END
The US coal fleet is entering an unprecedented period of retirements, as the industry faces a threepronged assault from low gas prices, an aging fleet, and stringent environmental compliance.
•
Old age: numerous units are today approaching 50+ years of operation.
•
Cheap gas: sub-$4/MMBtu Henry Hub gas will hit coal units twice – first, by reducing wholesale
power prices; and second, by bringing combine-cycle gas turbines (CCGTs) into the base-load
power mix, encroaching on sales of coal-fired electricity.
•
Environmental regulations: standards laid out by the US Environmental Protection Agency
(EPA) will force generators to decide whether to invest in expensive environmental controls.
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BNEF White Paper
8 April 2015
2015 will be particularly noteworthy, as the first date for compliance with EPA’s Mercury and Air Toxics
Standard (MATS) arrives on 16 April 2015. MATS serves as an artificial deadline for the retirement
of units whose economics were already challenged. Overall, we expect 23GW of coal to retire in
2015 alone, in what marks the largest wave of coal retirements in US history. Over 50GW are
expected to retire by 2020.
The coal units now slated to come offline accounted for over 270TWh/year from 2013-14 – roughly
7% of US generation. While we do anticipate higher capacity factors at the remaining coal units,
the result should be a fundamental reduction in coal’s share of the US power mix.
The impact of coal retirements will be particularly strong in the regions east of the Mississippi: nearly
70% of retiring capacity is located in the Southeast and PJM power regions (Figure 6).
Figure 6: Coal capacity, retirements, and generation, according to BNEF forecasts, 2010-20 (GW)
Retirements by coal type
Retirements by region
Source: Bloomberg New Energy Finance, EIA Form 860, company filings and interviews.
2020
2…
2018
2019
2…
2…
2…
2017
PJM
SPP
ERCOT
Florida
New York
2…
2015
2016
2…
2014
2013
2…
2…
50 Southeast
0 MISO
-50 Southwest
Northwest
New England
2…
2012
2010
2011
2020
2018
2019
2016
2017
2013
2015
Lignite
0
-2
-4
-6
-8
-10
-12
-14
-16
-18
-20
-22
-24
2…
Sub-bituminous
2
0…
Bituminous
2
0…
2
0…
2
0…
500
0
2
0…
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
0
2014
50
2
0…
100
2011
150
2012
200
2
0…
250
2
0…
300
2010
0
-2
-4
-6
-8
-10
-12
-14
-16
-18
-20
-22
-24
2…
Operational capacity by coal type
350
3. FUEL BURN: ‘STRUCTURAL’ GAS GROWTH
In 2012, natural gas burn in the power sector reached a record high of 25Bcfd, driven by a perfect
combination of low gas prices and high summer load. Now, 2015 is shaping up to be a major year for
gas generation as well. Year-to-date, natural gas burn in 2015 is 1Bcfd above 2012 levels. With 23GW
of coal unit retirements, 14GW of gas build, and Henry Hub forward curves predicting gas prices below
$3.00/MMBtu, 2015 looks likely to overtake – or at least match – 2012 in terms of gas burn (Figure 7).
Page 4 of 10
BNEF White Paper
8 April 2015
Figure 7: US power sector gas and coal Figure 8: Gas burn by region, 2005-20
burn forecasts, 2005-20
(Quads)
30
28
26
24
22
20
18
16
14
12
10
8
6
4
2
0
Coal burn (Mst)
Gas burn
3.00
2.75
2.50
2.25
2.00
1.75
1.50
1.25
1.00
0.75
0.50
0.25
0.00
1,050
1,000
950
900
850
800
750
700
3.00
California
2.75
2.50
2.25
2.00
1.75
1.50
1.25
1.00Southwest
0.75
0.50
0.25
0.00
Florida
Coal
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
MISO
New England
Alaska
6.00
5.50
5.00
4.50
4.00
3.50
3.00
2.50
2.00
1.50
1.00
0.50
0.00
PJM
SPP
Hawaii
Southeast
ERCOT
Northwest
New York
20
05
20
06
20
07
20
08
20
09
20
10
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
Gas
2
0…
2
0…
29
27
25
23
21
19
17
15
2
0…
2
0…
2
0…
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
Coal burn
1,500
1,400
1,300
1,200
1,100
1,000
900
800
700
600
500
400
300
200
100
0
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
Gas burn (Bcfd)
Figure 9: Coal burn by region, 2005-20
(Quads)
Source: Bloomberg New Energy Finance, EIA 923, Bloomberg Terminal
Structural fuel switching: evolution of the plant stack
In addition to the relative price of fuel, the available plant stack has an impact on coal and gas
generation: in order to switch off coal generators in favor of gas (when prices signal such a choice),
there must be sufficient capacity of gas and coal available for generation. As explained in Section 2,
a wave of coal retirements will reduce this potential going forward – especially in the Southeast and
PJM, where nearly 70% of coal unit retirements will occur. Meanwhile, gas capacity is set to grow,
with over 56GW of net gas capacity additions expected online between 2015-20.
Operational fuel switching: relative economics of gas versus coal
On an operational basis, gas burn is governed by the hour-by-hour competition between the nation’s
450GW of gas turbines and its 300GW of coal. Since fuel price is the most significant component of
operating costs for both gas and coal units, the relative price of each fuel in a dollar per megawatthour ($/MWh) basis has a significant impact on the relative generation from gas versus coal.
•
Coal prices have come down since 2011, especially for Central Appalachian coal, which is
consumed by most power plants in PJM (the unregulated market which spans the mid-Atlantic
and Midwest) and the Southeast.
•
However, natural gas prices are also low this year – with forward curves suggesting that prices
this summer will be near 2012 levels (or even below, in the case of PJM).
As a result, competition between the average gas and coal generator will be intense across the US.
Figure 10 shows the average short run marginal costs for fossil generators in the four US region
with the highest levels of natural gas burn for electricity. When the costs for gas generators (purple)
fall below those of coal (black/grey), there is an opportunity for switching to gas.
For the rest of the decade, natural gas economics look very strong relative to coal in the Southeast
and PJM – although in ERCOT and MISO, where generators can take advantage of cheaper coal
from the Powder River Basin (PRB), coal generation has a slight edge past 2015.
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BNEF White Paper
8 April 2015
Figure 10: Short run marginal costs of generation by fuel and region, 2010-20 (all-in $/MWh; real 2014USD)
Southeast
PJM
$80
$80
$50
Gas generator
(Henry Hub)
$40
MISO
2020
2019
2018
2017
2016
ERCOT
$80
$80
Gas generator
(MichCon City Gate)
$70
$70
$60
$60
$50
$50
$40
$40
$30
$30
$20
Coal generator
(PRB sub-bituminous coal)
Coal generator
(ILB bituminous coal)
Gas generator
(Houston Shipping Channel)
Coal generator
(PRB sub-bituminous coal)
$20
$10
$-
2020
2019
2018
2017
2016
2015
2014
2013
2012
2010
2020
2019
2018
2017
2016
2015
2014
2013
2012
2011
2010
$-
2011
$10
2015
Coal generator
(Central Appalachian coal)
2010
2020
2019
2018
2017
$-
2016
$-
2015
$10
2014
$10
2013
$20
2012
$20
2011
$30
2010
$30
2014
$40
2013
$50
$60
2012
$60
Gas generator
(Tetco M3)
$70
Coal generator
(Central Appalachian coal)
2011
$70
Click here for our database of US power and fuel prices
Source: Bloomberg New Energy Finance, EIA 923; Bloomberg Terminal Fair Value Curves. Notes: All lines represent marginal costs of generation,
based on various fuel prices. Dotted lines track fuel hub prices; solid lines track average all-in costs, including transport from hub to plant. Marginal
costs in Figure 10 are calculated using the following formula:
where applicable
Wholesale
power price
=
marginal cost of
generation
(for the marginal
generating unit)
=
opex
+
=
operating
expense
+
fuel cost
fuel
price
*
heat
rate
carbon cost
+
+
carbon
price
*
carbon intensity
of fuel
*
heat
rate
Where fuel and carbon prices are tied to the market-traded forward curves; heat rate assumptions for coal-fired generators and natural gas combined
cycle turbines are 10MMBtu/MWh and 7MMBtu/MWh, respectively; opex costs are assumed to be $4.50/MWh for coal and $3.50/MWh for gas; carbon
intensity is 0.10tCO2/MMBtu for coal and 0.05t/MMBtu for gas. Dotted lines represent fuel prices, solid lines represent the all-in average short run
marginal cost of generation. PRB is Powder River Basin coal, ILB is Illinois Basin coal.
Page 6 of 10
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8 April 2015
4. CARBON EMISSIONS: FURTHER TO FALL
Rising renewable penetration and coal-to-gas switching culminates in lower carbon emissions. Only
load growth can prevent 2015 from posting the lowest electricity-related emissions in over two
decades. So long as we do not see extreme summer heat waves 3, US power sector emissions are
poised to drop 35Mt (2%) below last year’s levels.
This would not be the steepest single-year drop: emissions recently fell 126Mt between 2011 and
2012, but the 2012 decline was more cyclical in nature – driven by inherently temporary, weatherrelated declines in natural gas prices and electricity load. (Emissions rebounded the following two
years.) In contrast, the reduction in 2015’s carbon footprint from the power sector is a more
‘structural’ phenomenon – driven by permanent factors like more renewable capacity and less coal.
Figure 11: US fleet-wide
emissions rates, 1950-2020
(tCO2e/MWh)
0.8
0.7
Ultimately, to put carbon emissions in proper context, we must take a longer view. The relevant
milestone for US power-sector emissions is 2030: the final deadline to comply with the Clean Power
Plan. Figure 12 demonstrates how 2015 emissions stack up relative to the trajectories required in
order to comply with the Clean Power Plan, according to EPA modelling. And just for fun (or
because the Clean Power Plan itself does not target emissions; it targets ‘adjusted’ emissions
rates), Figure 11 maps estimated emissions rates from 1950-2015, showing that megawatt-hour for
megawatt-hour, 2015 is poised to be the US power sector’s cleanest year on record.
0.6
Figure 12: US power-sector emissions under various forecasts (MtCO2)
0.5
2,750
0.4
2,500
Historical emissions
2,094
2,250
0.3
EPA forecasts
2,000
0.2
1,750
BNEF forecast
1,500
0.1
Under BAU, the EPA forecasts
2030 emissions at 2.25Gt;
Under the Clean Power Plan, EPA
estimates put US power-sector
emissions at 1.7-2.0GtCO2.
1,250
1,000
750
Source: Bloomberg New Energy
Finance, EIA Notes: Calculations
for pre-2000 emissions rates are
rough approximations, based on
the energy generated from
different resources. We assumed
a flat emissions factor for coal,
gas, oil, etc.
250
500
Capped emissions
(Power-sector emissions that fall under
RGGI or California cap-and-trade)
2030
2025
2020
2015
2010
2,750
EPA forecasts2,097
2,500
2,250
2,000
1,750
1,500
1,250
1,000
Range under the Clean Power Plan
750
500
250
0
Business as usual (BAU)
1…
1…
2…
2…
2…
2…
2…
2…
2…
19…
19…
20…
20…
20…
20…
20…
20…
20…
2,750
Capped emissions
2,500
2,250
2,000
1,750
2,…
1,500
California in-state
1,250
1,000
750
500
250
0 California imports
RGGI
2005
2000
1990
0
1995
2010
2020
1990
2000
1970
1980
1950
1960
0.0
Source: Bloomberg New Energy Finance, EIA 923, EPA modelling, RGGI, CARB
3
Hot summers lead to increased use of air conditioners – major drivers of electric load. Increased electricity
demand in turn leads to more fuel, and more carbon emissions.
Page 7 of 10
BNEF White Paper
8 April 2015
Appendices
5. FURTHER READING
This Research Note draws extensively from other analyses; it updates themes laid out in our
previous comprehensive survey of the US electricity sector; and it sets the stage for a longer, more
detailed view of US power out to 2045 (currently in our research pipeline). In the meantime, Table
1 recommends previous publications for further reading.
Table 1: Selected publications for further reading
Title
Publication Date
US Power
US power in transition: gasify, oversize, de-carbonize
26 September 2014
US power and fuel prices (2005-35)
Updated monthly
Renewables
H1 2015 US Solar Outlook
16 January 2015
H1 2015 US Wind Outlook
Coming in April 2015
H1 2015 US SREC Outlook
9 January 2015
H1 2015 US REC Outlook: California
H1 2015 US REC Outlook: PJM
H1 2015 US REC Outlook: New England
Fossil generation
Wave goodbye to 17% of US coal capacity
16 March 2015
Q1 2015 North American Gas Outlook
25 Feb 2015
H1 2015 North American Long-Term Gas Outlook
16 Jan 2015
Carbon and the Clean Power Plan
RGGI Deep Dive: fuel switching fades away
H1 2015 California Carbon Deep Dive
18 March 2015
Who’s afraid of the EPA Clean Power Plan?
5 November 2014
Rate-based trading under the Clean Power Plan
3 November 2014
Finance and Economics
H1 2015 AMER LCOE Update
H2 2014 US PPA Market Outlook
13 March 2015
15 December 2014
Page 8 of 10
BNEF White Paper
8 April 2015
About Us
Subscription details
Gas, Renewables, Carbon, RECs, AMER
[email protected]
Contact details
William Nelson
[email protected]
Head of Analysis, North America
+1 646 324 4142
Meredith Annex
[email protected]
Associate, Gas
+1 646 324 4147
Nick Culver
[email protected]
Lead Analyst, US Solar
+1 646 324 4140
Daniel Shurey
[email protected]
Analyst, North American Wind
+1 646 324 4128
Colleen Regan
[email protected]
Associate, Carbon
+1 646 324 4145
Kyle Harrison
[email protected]
Research Analyst, North America
+1 646 324 4138
Madeline Yozwiak
[email protected]
Analyst, US Power and Environmental Markets +1 646 324 4144
Copyright
Jacqueline Lilinshtein
[email protected]
Senior Analyst, Clean Energy Economics
+1 646 324 4141
© Bloomberg Finance L.P. 2015. No portion of this document may be reproduced, scanned into
an electronic system, distributed, publicly displayed or used as the basis of derivative works
without the prior written consent of Bloomberg Finance L.P.
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8 April 2015
Disclaimer
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Medium-term outlook for US power: 2015 = deepest de

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