select topics from prior eye on the marketenergy papers
TRANSCRIPT
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Select topics from prior Eye on the Market Energy Papers
Table of Contents:
[1] The environmental impact of renewable energy (2020) ........................................................................................... 2
[2] Cost declines required to make the hydrogen economy a reality (2020) ................................................................. 3
[3] Measuring the climate benefits of reforestation (2020) ........................................................................................... 4
[4] How much energy is stored, and how? (2020) .......................................................................................................... 5
[5] The water intensity of hydraulic fracking (2020) ....................................................................................................... 6
[6] Geothermal energy: present and future (2020) ........................................................................................................ 7
[7] Germany and Energiewende: a dispassionate assessment (2019) ........................................................................... 9
[8] Wildfires: anthropogenic climate change and risks for utilities in fire-prone areas (2019) .................................. 15
[9] High voltage direct current lines: China leads, US lags (2018) ................................................................................ 18
[10] The Dream Team rebuttal of the Jacobson “100% renewable electricity by 2050” plan (2018) ......................... 21
[11] Better safe than sorry: sea level rise, coastal exposure and flood mitigation projects (2018) ........................... 25
[12] Hydraulic fracturing: the latest from the EPA and some conflicting views from its Advisory Board (2017)....... 31
[13] Forest biomass: not as green as you might think (2017) ...................................................................................... 38
[14] The myth of carbon-free college campuses (2017) ............................................................................................... 42
[15] US hydropower: how much potential for expansion? (2016) ............................................................................... 43
[16] Nuclear power: skyrocketing costs in the developed world (2014 and 2015) ..................................................... 45
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[1] The environmental impact of renewable energy (2020)
While environmental consequences of oil and gas on climate and groundwater systems have been widely studied, scientists are only just beginning to assess environmental impacts of a world highly reliant on renewable energy instead: • A renewable energy future will require massive amounts of cobalt, copper, lithium, graphite, cadmium and
rare earth elements for solar panels, batteries, electric vehicle motors, wind turbines and fuel cells. One study cited increases in materials demand of 87000% for EV batteries, 1000% for wind power, and 3000% for solar cells and photovoltaics by the middle of the century
• Even with modest production of these minerals to-date, their extractive and smelting industries have left a legacy in many parts of the world of “environmental degradation, adverse impacts to public health and biodiversity damage” (B. Sovacool)
The renewable waste issues of the future: • IRENA estimates that toxic solar panel waste (which contains lead, cadmium and chromium) could rise from
250 thousand tonnes in 2016 to 78 million tonnes by 2050 • By 2030, 11 million tonnes of spent lithium-ion batteries are projected to be discarded, with few systems in
place to recycle them • Fiberglass wind turbine blades are built to withstand hurricane force winds and cannot easily be crushed,
recycled or repurposed, at least not so far; retired ones mostly end up in landfills, or in Europe, burned. The US might face 720,000 tons of wind turbine blade disposal over the next 20 years
I have not seen anyone suggest that environmental consequences of a renewable energy future would be anywhere near as corrosive on the environment as one based on fossil fuels. Even so, a renewable energy world may be much less “green” than currently perceived. Sources: “Sustainable minerals and metals for a low-carbon future”, B. Sovacool, Science Magazine, January 2020 IRENA Solar Photovoltaic Panel End-of-Life Management report, 2016 World Economic Forum Global Battery Alliance “Global metal flows in the renewable energy transition: Exploring the effects of substitutes, technological mix and development”, Manberger and Stenqvist, Energy Policy, August 2018
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[2] Cost declines required to make the hydrogen economy a reality (2020)
The “green hydrogen” economy is based on the notion that hydrogen is a fuel that can be used to generate heat and power; that electrolysis can split water into its component molecules to produce oxygen and hydrogen; and that renewable electricity can be used to power the electrolysis required. However, due to the high costs of electrolysis, 95% of commercially available hydrogen is currently produced via steam methane reformation (SMR) of fossil fuels. Might that change one day, so that renewable-driven electrolysis could create “green” hydrogen?
• In February of this year, the US Department of Energy released a study1 on the potential for hydrogen production using electrolysis instead of SMR. They estimated possible future hydrogen costs by (a) varying the price of electricity, which is by far the largest component of electrolysis costs, and (b) assuming 30%-60% declines in upfront electrolyzer capital costs as production increases
• DoE future cost estimates range from $4.5 - $5.0 per kg of hydrogen assuming electricity costs of 7-8 cents per kWh, and assuming a large decline in electrolyzer capital costs. This would still be well above current state-of-the-art SMR hydrogen costs of just $1.15 per kg using current nat gas prices
• If electricity costs fell to 3 cents per kWh (i.e., in the range of current wind and solar PPAs but without incorporating utility costs for transmission infrastructure), the DoE estimated that hydrogen production costs could fall to $2.0 - $2.5 per kg of hydrogen, which is closer to but still above current SMR costs. This scenario would require co-located renewable energy dedicated to hydrogen production
• Bottom line: in the absence of a substantial carbon tax, further electricity and capital cost declines are required for green hydrogen costs to converge with fossil-fuel hydrogen costs2. In addition, to meaningfully impact energy consumption, existing turbines, engines, heating systems and other industrial equipment that now rely on natural gas would need to be replaced or upgraded to rely on hydrogen instead. That’s another real-life obstacle that hockey stick forecasts often fail to incorporate
1 DoE base case: electrolyzer capital costs decline by 30%-60% to $460 per kW ($342 for the electrolyzer stack and the rest for storage, compression and other auxiliary systems required). Source: “Hydrogen Production Cost From PEM Electrolysis”, US Department of Energy, David Peterson et al, February 2020. 2 A 2019 hydrogen analysis from IRENA came to conclusions that were similar to the US DoE. For green hydrogen to become competitive with SMR hydrogen, IRENA estimates that upfront capital costs would need to fall by 75%, and that electricity costs would need to be around 2 cents per kWh.
Steam Methane Reformation (state of the art)
Steam Methane Reformation, low estimate
Steam Methane Reformation, high estimate
Electrolysis, 7 cents/kWh, 30-60% decline in capital costs
Electrolysis, 3 cents/kWh, 30-60% decline in capital costs
$0
$1
$2
$3
$4
$5
Electrolysis vs Steam Methane Reformation as a means of producing hydrogen, $/kg
Source: US Department of Energy. February 2020.
Hydrogen blasts from the past Hydrogen economy: A practical answer to problems of energy supply and pollution (Science, 1972) Hydrogen: Its Future Role in the Nation's Energy Economy (Science, 1973) Clean hydrogen beckons aviation engineers (New York Times, May, 1988) Hydrogen economy in the future (International Journal of Hydrogen, 1999) Amory Lovins Sees the Future and It Is Hydrogen (Grist, May 1999) The Hydrogen Economy (Jeremy Rifkin, 2003)
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[3] Measuring the climate benefits of reforestation (2020)
US forests comprise roughly 750 million acres, which is one third of all US land area (including Alaska and Hawaii). This amount of forest acreage has not changed much over the last 100 years, and offsets ~10% of annual US GHG emissions each year. Reforesting areas cleared due to wildfires/insect outbreaks and planting trees in previously unforested areas (“afforestation”) will help, but be realistic about the achievable benefits. Assuming 2.5 metric tons of CO2 sequestered per year per acre of forest3, ~130 million acres would have to be planted to offset another 5% of US GHG emissions, bringing forested land area back to the level it was in 1850 (despite a 6-fold increase in US population since then). Reforesting that many acres of private and public land would be a major undertaking; as shown below, the US Forest Service has been reforesting just over 100 thousand acres per year, which is three orders of magnitude smaller.
Remember as well that some amount of reforestation is needed just to offset acreage lost to (a) aging US forests which absorb less carbon over time, (b) CO2 released from wildfires, which has averaged 60 - 80 million metric tons per year since 2013, and (c) the impact of severe hurricanes, one example being Hurricane Michael which destroyed 3 million acres of trees in Florida in 2018.
3 Obviously depends on the species and location; triangulated from Journal of Forestry, EPA and USDA reports.
-1,0000
1,0002,0003,0004,0005,0006,0007,0008,000
1990 1993 1996 1999 2002 2005 2008 2011 2014
Source: US EPA. 2017. Total emissions include agriculture, waste and industrial processes such as chemical, metal and mineral production.
US forests offset 10% of annual GHG emissionsMillion metric tons of CO2 equivalents per year
Carbon sink from forests and land use changes
GHG emissions from energy
Total GHG emissions
0
50
100
150
200
250
300
350
700
750
800
850
900
950
1850 1870 1890 1910 1930 1950 1970 1990 2010
Source: United States Department of Agriculture. 2019.
Forest area and population trends in the USMillion acres Million people
Forest area
Population
0
2
4
6
8
10
12
1989 1992 1995 1998 2001 2004 2007 2010 2013 2016 2019
Acres burned by wildfires per year in the USMillions
Source: National Interagency Fire Center. 2019.
0
50
100
150
200
250
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
Total USDA reforestation per yearThousand acres
Source: USDA Reforestation and Timber Stand Improvement Reports. 2019.
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[4] How much energy is stored, and how? (2020)
Some de-carbonization proposals for the grid entail substantial over-building of wind and solar power with the goal of storing excess electricity generation to draw upon later, allowing natural gas peaker plants to eventually be retired. However, long-term utility-scale energy storage via electrochemical batteries is an industry that is still in its infancy. Less than 1% of US electricity generation was stored in 2019, and almost all of this storage occurred in decades-old pumped hydro facilities (see below) rather than in batteries. A much larger storage buildout would be needed to displace natural gas peaker plant generation, which is currently 10x the amount of stored-and-then-dispatched electricity. There are plenty of “hockey stick” forecasts for electrochemical battery deployment, as there were for electric vehicles a decade ago and which turned out to be way too high. Due to the complexities around reimbursement and cost recovery allowances for utilities that invest in storage, some battery storage forecasts are likely to be too high as well.
Seneca pumped storage and hydroelectric facility, Warren County, Pennsylvania
99% Consumed
94% Pumped Hydro
1% Stored 6% Other storage (thermal, battery, compressed air, flywheels)
0%
20%
40%
60%
80%
100%
Electricity generation Electricity storagecapacity
Only 1% of US electricity generation is stored, and most storage is via decades-old pumped hydro storage
Source: EIA, EPA, JPMAM. 2019.
0255075
100125150175200225250275
Electricity generated, stored andthen consumed later
Electricity generation from peakerplants
Source: EIA, BNEF. 2019.
Much larger storage buildout needed to reduce peaker plant usage, TWh
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[5] The water intensity of hydraulic fracking (2020)
The word “hydro” is part of “hydraulic fracturing” for a reason. Water requirements for fractured wells are 8x-10x higher than for conventionally drilled wells. Water demand rose as the shale revolution unfolded, with only a modest decline from peak levels in 2014 to 2016. There are a lot of factors driving water demand, so it’s important to distinguish them. Water demand is a function of the number of wells drilled, and the lateral length of wells which increased by 20%-30% from 2011 to 2016. So, some degree of increased water demand simply reflects more wells and longer distances from the wellhead.
Since changing well numbers and wellhead distances affect water demand levels, our preferred measure of shale industry water intensity is “liters of water per gigajoule of energy”. As shown below, water intensity rose for many shale oil locations from 2011 to 2016, and also for shale gas wells in the Permian4.
4 While most electricity generation doesn’t take place in water-stressed areas, ~50% of natural gas extraction does occur in water-stressed areas. Natural gas water usage is at least less intense than for coal. From 2013 to 2016, for every MWh of electricity generated with natural gas instead of from coal, there was a reduction of 1 m3 in water consumption and 40 m3 in water withdrawal. In terms of toxicity, however, it’s a toss-up between produced water from fracturing and coal mine water drainage. The former is often toxic (see next page), and so is the latter: many coal mines are abandoned and not sealed, so they fill up with rain and continuously discharge acidic, polluted water. Furthermore, storage of coal combustion residuals in coal ash ponds can leach heavy metals and radioactive material into groundwater. Source: Environmental Research Letters, Kondash and Vengosh, Dec 2019.
0
50
100
150
200
250
2012 2013 2014 2015 2016
Permian (gas)
Marcellus (gas)
Haynesville (gas)
Eagle Ford (gas)
Permian (oil)
Niobrara (oil)
Eagle Ford (oil)
Bakken (oil)
Source: Kondash et al., Science Advances. August 2018.
Water use in select shale oil and gas basinsMillions of cubic meters of water
0
2
4
6
8
10
12
14
2012 2013 2014 2015 2016
Permian (gas)
Marcellus (gas)
Haynesville (gas)
Eagle Ford (gas)
Permian (oil)
Niobrara (oil)
Eagle Ford (oil)
Bakken (oil)
Source: Kondash et al., Science Advances. August 2018.
Number of new wells drilled in select oil and gas basinsThousands
10
20
30
40
50
2011 2012 2013 2014 2015 2016
PermianEagle FordNiobraraBakken
Median water use intensity for hydraulic fracturing of oilLiters/GJ, first 12 months of well production
Source: Kondash et al., Science Advances. August 2018.
0
10
20
30
40
50
60
2011 2012 2013 2014 2015 2016
PermianEagle FordMarcellusHaynesville
Source: Kondash et al., Science Advances. August 2018.
Median water use intensity for hydraulic fracturing of gasLiters/GJ, first 12 months of well production
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[6] Geothermal energy: present and future (2020)
Geothermal energy has been used in hot baths since antiquity, for space heating in Boise, Idaho since 1892, for virtually all houses in Reykjavik since the 1930s, and for electricity generation since 1904 in Larderello, Italy. Before getting into “ultra-deep” geothermal power, let’s walk through the footprint of existing geothermal energy today.
Geothermal energy has a small presence. Its output in 2018 was only 0.1% of global primary energy consumption, split roughly 50/50 between electricity production and heat (many sources don’t even break geothermal out as a separate category, and combine it with things like wave power)9F5. Around half a GW of new capacity came online in 2018, bringing the global total to 13.3 GW. Most additions occurred in Turkey and Indonesia, with the rest scattered about the US, Africa and Asia. There are two ways of generating electricity by using geothermal energy: binary cycle and dry-steam. In a binary cycle plant, geothermal fluid vaporizes another fluid with a lower boiling point than water that then spins a turbine, while in conventional dry-steam/flash plants, geothermal steam is used directly to power the turbine.
As shown below, the world’s largest geothermal plants have well depths of ~2 kilometers, and access reservoirs with average temperatures of 250-300°C.
5 REN21 Renewables 2019 Global Status Report
US
Indo
nesi
a
Phili
ppin
es
Turk
ey
New
Zea
land
Mex
ico
Italy
Icel
and
Ken
ya
Japa
n
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
Source: BP Statistical Review of World Energy. 2019.
Installed geothermal capacity by countryMW
The
Gey
sers
(US)
Cer
ro P
rieto
(Mex
)La
rder
ello
(Ita
)O
lkar
ia (K
en)
Mak
ban
(Phl
)Sa
lak
(Indo
)C
alEn
ergy
(US)
Saru
lla (I
ndo)
Hel
lishe
idi (
Ice)
Dar
ajat
(Ind
o)K
amoj
ang
(Indo
)Ti
wi (
Phl)
Way
ang
Win
du (I
ndo)
Palin
pino
n (P
hl)
Te M
ihi (
NZ)
0
200
400
600
800
1,000
1,200
1,400
1,600
Source: Proceedings from World Geothermal Conference, OpenEI, individual company releases. 2020.
Largest geothermal power plants by capacityMW
The
Gey
sers
(US)
Palin
pino
n (P
hl)
Cer
ro P
rieto
(Mex
)O
lkar
ia (K
en)
Mak
ban
(Phl
)H
ellis
heid
i (Ic
e)La
rder
ello
(Ita
)D
araj
at (I
ndo)
Saru
lla (I
ndo)
Tiw
i (Ph
l)W
ayan
g W
indu
(Ind
o)C
alEn
ergy
(US)
Te M
ihi (
NZ)
Sala
k (In
do)
Kam
ojan
g (In
do)
0.0
0.5
1.0
1.5
2.0
2.5
3.0
Source: Proceedings from World Geothermal Conference, OpenEI, individual company releases. 2020.
Well depths for largest geothermal power plantsMidpoint/average well depth, km
Mak
ban
(Phl
)O
lkar
ia (K
en)
Lard
erel
lo (I
ta)
Tiw
i (Ph
l)C
erro
Prie
to (M
ex)
Cal
Ener
gy (U
S)Sa
rulla
(Ind
o)Sa
lak
(Indo
)Pa
linpi
non
(Phl
)H
ellis
heid
i (Ic
e)W
ayan
g W
indu
(Ind
o)Te
Mih
i (N
Z)D
araj
at (I
ndo)
Kam
ojan
g (In
do)
The
Gey
sers
(US)
0
50
100
150
200
250
300
350
Source: Proceedings from World Geothermal Conference, OpenEI, individual company releases. 2020.
Average temperatures of geothermal reservoirs°C
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With that backdrop, let’s discuss “ultra deep” geothermal energy. At 5-7 kilometers below the surface of the earth, there are geothermal reservoirs measured at 400°-500° C and at 200+ bars of atmospheric pressure. In these locations, water exists as “supercritical fluid”. Such fluids in theory could deliver 5x-10x more power than traditional geothermal plants and rival the power derived from nuclear power plants. If so, the increased power could offset some of the increased drilling costs required to access such depths, if they were achieved. The concept has led to press articles such as “Supercharged Geothermal Energy Could Power the Planet”, which asserted that “heat contained in the upper three kilometers of the earth’s crust would be enough to meet the world’s energy demand thousands of times over”6. Yes, but….let’s take a closer look.
The most well-known deep geothermal projects in the world are Iceland Deep Drilling Projects 1 and 27. They are still in the exploratory field-test phase since development of valves, coatings, casings and sensors that can withstand the intense temperatures and pressures involved, and the corrosive materials surfaced during the process, are still ongoing.
• The first well, IDDP-1, had to be completed in 2009 before reaching supercritical fluid depths since molten magma flowed into the well at 2,100 meters. However, above the magma intrusion, superheated steam at 452°C and at 40-140 bars of pressure was measured during a 2-year flow test, capable of generating 35 MW of power (8x-10x higher than a conventional geothermal well). At the time, IDDP-1 was the hottest producing geothermal well in the world. Eventually, its master valves failed and the superheated steam flow had to be quenched with cold water. The flow was quenched, but the thermal shock caused the well casings to buckle beyond repair, and IDDP-1 was abandoned
• In 2017, the IDDP-2 project team drilled to depths of 4,500 m, reaching a different field that is recharged by seawater and which contained supercritical conditions of 600°C and 350 bars of pressure. This project represented the first of its kind in terms of drilling into geothermal reservoir rocks at these extreme temperatures. Flow tests have begun and will be carried out over the next few years, even through IDDP-2 has already sustained casing damage which could restrict certain development options at deeper levels
• The ultimate goal of the IDDP project: generate power from supercritical geothermal resources which would be used not just in Iceland but in Scotland as well. The IceLink plan entails a 1,200 km high-voltage underwater DC cable to Scotland to interconnect Iceland’s electric grid to those of the UK and beyond. Laying such a cable in deep Atlantic waters would be another unprecedented achievement: today’s longest underwater HVDC cable is 580 km in shallow waters between Norway and the Netherlands
In other words, deep geothermal power is in the very early stages of development. We’re intrigued about the concept of deep geothermal as baseload power, but are realistic about the physical materials and geological challenges ahead (including risks of seismic activity). We met with a company that’s trying to solve some drilling challenges via an “electric pulse plasma-based drill” designed to reach temperatures of 6,000° C. As the plasma drill descends, it would be followed by a continual casing that would conduct water on the way down, and supercritical steam on the way back up. The intense heat from the drill bit would presumably vaporize everything in its path, and the company developing it believes that drilling costs would remain linear with depth (in contrast to traditional deep drilling techniques whose costs rise geometrically with depth). However, its efforts are in their infancy, and their estimates of plasma drilling costs have to be taken with a giant grain of salt until proven in more than just early field studies.
6 New Scientist.com (a weekly science and technology publication), October 17, 2018 7 “The IDDP Success Story”, Proceedings of the World Geothermal Congress, Gudmundur Friedleifsson et al, 2020
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[7] Germany and Energiewende: a dispassionate assessment (2019)
If you look for opinions on Germany’s Energiewende transition, you’ll find articles that cite great success, and other articles like “Energiewende: A disaster in the making”8. The achievements and limitations of Energiewende are important to understand: Germany is seeking to generate 65% of its electricity from renewable energy without heavily relying on hydropower, as most countries with high shares of renewable power generation do (Denmark and Scotland are exceptions, and have among the highest ratio of coastline to land area in the world).
A few ground rules on what doesn’t matter to me about Energiewende: • I don’t consider strains on German utilities to be a problem unless they lead to blackouts, brownouts
or other substantial disruptions to the German economy (which aren’t happening so far, see page 19)
• GHG emission comparisons shouldn’t be established vs a year like 2009, when a global recession depressed output and associated emissions
• The fact that China’s GHG increases could offset annual Energiewende savings in a few weeks is not an indictment of Energiewende per se
• Citing the numbers of birds killed by wind farms should be done in a proper context, as fossil-fueled generation produces its own (broader) set of environmental impacts
Here’s what does matter to me in assessing Energiewende goals: • The cost so far, measured by household and corporate electricity prices, subsidies and taxes • What additional costs will be needed for transmission and/or distributed storage necessary to meet
the 65% goal, and whether such costs and land-use requirements are viable politically • What will Germany’s GHG emissions look like once they are based on the new system (wind/solar
backed up by coal plants, and without the nuclear power which once provided 30% of generation)
8 Examples of downbeat articles on Energiwende: • “Germany’s Energiewende: A disaster in the making”, Fritz Vahrenholdt, Global Warming Policy Foundation, 2017 • “Why aren’t renewables decreasing Germany’s carbon emissions”, Forbes, October 2017. • “Energiewende: A tale of increasing costs and decreasing willingness to pay”, IAEE Energy Forum, 2017. • “Germany’s Green Energy shift is more Fizzle than Sizzle”, Politico, October 2018.
Uru
guay
Icel
and
Cos
ta R
ica
Nor
way
Zam
bia
Ethi
opia
Ken
ya
New
Zea
land
Bra
zil
Aus
tria
Scot
land
Vene
zuel
a
Nep
al
Cro
atia
Can
ada
Col
ombi
a
Switz
erla
nd
Den
mar
k
Swed
en
Port
ugal
Ger
man
y
0%10%20%30%40%50%60%70%80%90%
100%Biomass/OtherWind/SolarGeothermalHydro
Source: IRENA, German Federal Ministry for Economic Affairs and Energy. Based on 2016/2017 electricity generation.
Countries with high renewable shares of electricity generally rely heavily on hydropower and geothermal energyPercentage of electricity generation from all renewable sources
10
What has Energiewende accomplished so far? Energiewende’s primary impact has been the substitution of solar and wind for thermal and nuclear power generation. When including all forms of renewables, Germany’s renewable generation reached 38% in 2017, which is quite an achievement for a country with only a 4% hydropower share.
Germany’s wind and solar footprint is the largest in the developed world when measured vs population and land area, and this is before Germany shoots for 65% renewable generation by 2030. High wind/solar penetration rates sometimes raise concerns about grid reliability, but so far, this hasn’t been a problem. German power outages are actually down since 2006, and Germany’s 15 minute average annual outage figure for 2017 was practically the lowest in Europe by a wide margin.
0%
10%
20%
30%
40%
50%
60%
70%
'91 '93 '95 '97 '99 '01 '03 '05 '07 '09 '11 '13 '15 '17
Renewables and the decline in thermal and nuclear generation, Share of total electricity generation, Germany
Solar and wind
Thermal (coal & gas)
Nuclear
All renewables
Source: German Federal Ministry for Economic Affairs and Energy. 2017. All renewables includes solar, wind, hydro, biomass and waste.
0
20
40
60
80
100
'91 '93 '95 '97 '99 '01 '03 '05 '07 '09 '11 '13 '15Source: German Federal Ministry for Economic Affairs and Energy. 2017.
Germany’s wind and solar capacity build-out now matches its thermal capacity, with more to come, GW
Solar and wind capacity
Thermal capacity (coal & gas)
US Can
Austria
Bel
Den
Fin
Fra
Ger
Ita
Nor
Spa
Swe
UKJpn
Austra
Neth
0
50
100
150
200
250
300
0.00 0.20 0.40 0.60 0.80 1.00 1.20Installed capacity, kW per capita
Germany has the largest wind/solar footprintInstalled capacity, kW per square km
Source: BP Statistical Review of World Energy. 2018.
Switz
erla
nd
Ger
man
y 20
17
Ger
man
y 20
06
Net
herla
nds
Aus
tria
UK
Fran
ce
Spai
n
Italy
Finl
and
Swed
en
Irela
nd
Nor
way
0
10
20
30
40
50
60
70
80
90
Source: Council of European Energy Regulators Benchmarking Report, 2018. The following countries had interruptions over 100 minutes per year: Bulgaria, Latvia, Greece, Estonia, Croatia, Poland and Romania. According to the EIA, the comparable US figure was 128 minutes.
Average annual power supply interruption2016 minutes (including exceptional events)
11
What about GHG emissions? Progress is slower than Germany was hoping for. The Energiewende goal is a reduction in GHG emissions of 40% vs a 1990 baseline by 2020; the decline plateaued at 28% instead. The primary reasons for the plateau: • While solar and wind generation capacity now matches thermal capacity, solar and wind
intermittency result in lower relative amounts of renewable electricity generation • The renewable share of electricity generation rose from 10% in 2001 to 38% in 2017, but GHG
emissions from electricity only declined by 14%. The explanation: during the same period, the nuclear share of generation dropped by 17%, slowing the decline in reliance on coal. Germany still has one of the highest coal shares of primary energy of all developed non-island nations, and its decline will continue to be gradual if Germany’s last 7 nuclear plants are de-commissioned as planned by 2022
• There was a large GHG decline following the collapse of East Germany’s inefficient power and industrial sectors; this process was mostly played out by the year 2000
• Electricity generation is only 40% of total primary energy use in Germany. Transportation emissions are roughly unchanged since 1990, as increased kilometers traveled offset improvements in vehicle efficiency, and since electric vehicles were only 1.5% of total German car registrations in 2017. Industrial and agricultural GHG emissions are also roughly unchanged since 2000.
• Germany considered a levy on coal plants emitting more than a certain amount of CO2, but backtracked after union and utility protests. Further GHG reductions may have to come from incentives for industry to invest in more efficient machinery (uncertain benefits and timing)
0
200
400
600
800
1,000
1,200
1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2020 2030 2040
Source: German Environment Agency (Umweltbundesamt). 2018.
German GHG emissions decline has stalled since 2008GHG emissions by sector, million tonnes of carbon dioxide equivalents
Energiewende targets
Electricity generation
Industry
Transportation
HouseholdsAgriculture/Buildings/Other 38% decline
by 2030
Sou
th K
orea
Ger
man
yFi
nlan
dU
SP
ortu
gal
Net
herla
nds
Spa
inD
enm
ark
Aus
tria
Italy
Can
ada
Bel
gium
Fran
ceS
wed
enS
witz
erla
nd
Taiw
anJa
pan
Irela
ndN
ew Z
eala
ndU
nite
d K
ingd
omIc
elan
d
0%
5%
10%
15%
20%
25%
30%
35%
Source: BP Statistical Review of World Energy. 2018.
Coal as % of primary energy in developed economies
Islands0.90
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1993 1995 1997 1999 2001 2003 2005 2007 2009 2011 2013 2015Source: German Aerospace Center Instititue of Transport Research. 2017.
Germany: more cars offset benefits from more efficient engines and more efficient use; Index, 1993 = 1.0
Kilometers driven per car
Vehicle kilometers traveled
Registered cars
12
The biggest Energiewende question relates to costs incurred so far, costs that still remain (due to transmission infrastructure and substitutes for nuclear power), and the political willpower needed to finance them. German household electricity costs are among the highest in Europe, and this is before additional transmission, nuclear substitution and higher renewable penetration costs are incurred. German household incomes are similar to France, Ireland and the UK, in which case higher German electricity prices are also higher in relative terms. However, Italian and Spanish household incomes are lower, so their real burdens are closer to Germany than they appear in the chart.
Here’s a visual of the supply-demand gap today, and the one that may exist in 2030. The growing purple supply deficit reflects the expected gap between wind supply in the North and energy demand from population centers in the South.
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Source: Eurostat, Q2 2018.
German regional power deficits expected to rise by 2030
Source: Ampriron GmbH. 2015.
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13
The current supply-demand gap has already resulted in a rise in discarded renewable production (which results in feed-in tariff payments to wind producers to compensate them anyway), and in “redispatch costs” required to compensate Southern power producers to generate electricity at times of low electricity prices. According to the German Federal Network Agency, annual tariff and redispatch costs due to grid stabilization efforts could rise to EUR 1 billion by 2020, and that’s before nuclear plants are shut down, and before increased EV penetration in Germany9.
German grid imbalances are not just a problem for Germany. German grid congestion is already putting pressure on Eastern European grids through unwanted power surges and blockages at the border. New cross-border connections to Belgium and Scandinavia may reduce some of these pressures. To reduce curtailed renewable generation and re-dispatch costs, Germany will need to upgrade its transmission infrastructure. This includes upgrades to large transmission lines, and also to the low and medium voltage distribution grid that incorporates storage capacity and electric cars. The latest estimates we have seen: a need for 4,650 km of transmission lines by 2025, only 900 km of which have been built so far. As in the US, this process has been bogged down by citizen protests affected by transmission line construction, as well as by German states (e.g., Thuringia) that are suing in an effort to have them relocated to neighboring states. Burying cables underground might reduce the political disputes, but at a substantial increase in cost. More wind turbines could be built in the South, but so far, this has been met with a lot of political resistance.
9 If 30% of Germans bought EVs and plugged them in to recharge when they get home from work, consultancy Oliver Wyman estimates that Germany’s electricity grid could collapse. Much greater grid management planning would be needed for EVs to function as electricity storage devices in connection with surplus renewable generation.
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Source: BDEW, Bundesnetzagentur Monitoring Reports. 2017.
Redispatches: grid shortages which require extra payments to above-market producers
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14
Energiewende’s goals are much broader than the electricity grid. One key objective is a 30% decline in primary energy use from 2015 to 2030. The challenge, as illustrated in the first chart: German primary energy use is basically unchanged since the year 2000, casting considerable doubt on this 2030 goal. German energy efficiency has improved (along with other developed nations), but overall energy use has been roughly constant.
In the latest self-assessment of Energiewende by the Federal Government’s Expert Commission, the lack of progress outside power generation is readily acknowledged. The assessment assigned the lowest grades (“unlikely to meet 2020 target”) to transportation energy use, changes in the fuel mix, expansion of transmission grids and overall primary energy use. So, here’s the bottom line on Energiewende: • Can Germany reach 65% renewable power generation by 2030? Sure, but it may require considerable
further increases in electricity prices and other economic costs10, and increased political will to build the transmission infrastructure necessary to get there. As a reminder, 80% of the necessary transmission infrastructure is still on the drawing board
• Will Germany be able to cut GHG emissions in half by 2040, which relies in part on a 30% decline in primary energy use? Highly unlikely, given the very slow pace of de-carbonization apart from the electricity grid, and the extent to which greater demand for energy offsets improvements in energy intensity, improved gas mileage in cars/planes, more energy efficient devices/machinery/buildings, etc
• Germany’s newly announced goal of phasing out all coal/lignite by 2038 seems completely unrealistic given all the issues explained above
10 German regulators may consider 35 cents/kWh as a resistance point for households in terms of what they would be willing to pay for electricity, particularly since energy taxes are regressive by nature. If so, Germany may have to increase electricity prices on its industrial users instead, whose prices are also close to the highest in the industrialized world at 12.5 to 15.5 cents per kWh. While nuclear decommissioning costs may not show up in electricity prices directly, they are also a large cost borne someplace in the energy ecosystem.
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'00 '02 '04 '06 '08 '10 '12 '14 '16 '18 '20 '22 '24 '26 '28 '30Source: BP Statistical Review of World Energy, JPMAM. 2018. Dotted line indicates pathway needed to reach 30% primary energy decline goal.
Germany primary energy consumption, Mtoe
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Energiewende goal:30% decline from 2015 levels by 2030
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Energy intensityMtoe of primary energy per unit of nominal GDP
Source: BP Statistical Review of World Energy, Haver, JPMAM. 2018.
15
[8] Wildfires: anthropogenic climate change and risks for utilities in fire-prone areas (2019)
Given the collapse in PG&E stock in the wake of two severe wildfire seasons, we wanted to assess risks that such catastrophic events recur in the future. In other words, were 2017 and 2018 anomalous fire seasons, or are such risks something that investors need to be mindful of in the future? Based on the latest research, owning utilities in fire-prone areas looks to be fraught with risk that isn’t going away.
Recent wildfire research attempts to identify the degree to which man-made climate change contributes to forest fire activity. The approach: use historical data to determine a “non-anthropogenic baseline”, which is the amount of hectares that would probably have burned anyway absent any climate change, and due to natural causes. One recent example comes from a 2016 paper from researchers at Columbia’s Lamont Doherty Earth Observatory and the University of Idaho. Their “natural burn area” baseline is shown in blue; the gray dots show the actual amounts burned; and the red line shows the estimated total burn area. As you can see, total hectares burned were roughly double their “natural” baseline estimate.
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Source: Bloomberg. March 13, 2019.
PG&E's market capitalization after two years of wildfiresUS$ billions
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Actual forest area burnTotal estimated burn areaNon-anthropogenic burn area baseline
Source: Abatzoglou and Williams. 2016. Shaded areas are 95% confidence intervals.
Climate change responsible for a doubling of burn areaMillions of hectares of US forest fires, cumulative
Forest area burned due to anthropogenic climate change
Forest area burned due to natural causes
16
Here’s another look. The first chart shows an estimate of the increase in temperature in Western forest regions due to human activities. The recent temperature increase corresponds to an increase in the “fuel aridity” of Western forests (fuel aridity is a blend of different combustibility measures that rise as climate impacts intensify11). As the fuel aridity of Western forests rose, the hectares of US forests that burned in wildfires rose as well, and by an exponential amount as the Y axis is in log scale (second chart). These charts illustrate the connection many forestry scientists see between man-made climate change (which drives up fuel aridity) and wildfire severity.
Climate change is not the only way that humans affect wildfire severity; humans also start a lot of fires, whether intentionally or not. When looking at the numbers of fires and at the number of hectares burned, humans account for 84% of the former and almost half of the latter. Natural causes such as lightning account for the rest. The table below is for the period 1992-2012; fire frequency peaked around 1980, and has been declining since due to fewer instances of arson, fewer controlled burns becoming uncontrolled, and fewer cigarette ignitions.
11 Fuel aridity is a composite based on 8 measures of potential forest fire risk and intensity: the energy release component, the Fire Weather Index, the vapor pressure deficit, the climatic water deficit, the Palmer drought severity index, the Forest Fire danger index, the Keetch–Byram drought index and reference potential evapotranspiration.
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Source: Abatzoglou and Williams. 2016.
Estimated temperature change in Western forest region due to human activities, Degrees Celsius
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Source: Abatzoglou and Williams. 2016.
US forest fire area versus fuel aridity by yearForest fire area, thousands of hectares
Fuel aridity vs. non anthropogenic baseline
Humans start most fires and account for almost half of all forest area burned
Human Lightning Human % Human Lightning Human %Mediterranean California 87,274 2,855 97% 2,143,282 253,210 89%Northern Forests 61,673 2,574 96% 302,561 82,721 79%Eastern Temperate Forests 815,499 44,859 95% 3,827,045 829,293 82%Marine West Coast Forests 14,586 925 94% 19,251 27,291 41%Great Plains 134,944 17,586 88% 3,992,557 2,564,955 61%Southern Semiarid Highlands 7,504 2,167 78% 340,873 254,418 57%Tropical Wet Forests 4,832 1,917 72% 357,150 350,477 50%North American Desert 55,422 52,044 52% 2,394,677 8,880,691 21%Northwest Forested Mountains 76,735 94,017 45% 1,895,622 5,731,733 25%Temperate Sierras 13,607 26,502 34% 754,393 1,152,064 40%Total Continental US 1,272,076 245,446 84% 16,027,412 20,126,852 44%Source: Balch et al University of Boulder, January 2017, for the period 1992-2012.
Area burned (hectares)Number of fires
17
Part of the reason for the increase in wildfires and the resulting economic damages: increased housing growth in fire-prone areas, and an increase in fire suppression policies. The number of US homes and land area prone to wildfire impacts has increased by nearly 1350% since 1940. The first chart shows the number of homes in the Western US deemed to have “medium to very high” fire risk. A recent study looked at California specifically and future housing settlement in fire prone areas. The authors estimate that California’s residential development will replace nearly 12 million acres of forests and agricultural lands by 2050, increasing the number of houses in “very high” wildfire severity zones by nearly 1 million.
On fire suppression: in some fire suppressed ecosystems, certain shade-intolerant and more fire-resistant species such as Ponderosa pine can be outcompeted by shade-tolerant and less fire-resistant species such as Douglas fir. The result: a less fire-resistant forest. And by contributing to buildup of woody debris, these ecosystems are at risk of high-intensity “catastrophic” fires and soil erosion. As shown below, some forests in Northern California have become much denser since the 1930’s, reflecting in part the impact of fire suppression approaches. To be clear, the 1940-1980 cool/wet period in the West also contributed to denser forests of smaller trees since there were fewer wildfires and more moisture for tree regeneration12.
12 Ponderosa pine and western larch may suffer 50% of their circumference damaged by fire and survive whereas other tree species such as Douglas fir may die with only 25% of their circumference damaged. Sources for this section include the University of Montana College of Forestry and Conservation, and the Montana State University Forest Ecology and Management department.
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Source: Public Policy Institute of California, UC Berkeley. 2017.Survey regions include Sierra Nevada highlands and southern Cascaderanges. Trees are categorized as small if they are 4-12 inches diameter at breast height, medium at 13-24 inches and large over 24 inches.
California Headwater forests have become denserTrees per acre
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[9] High voltage direct current lines: China leads, US lags (2018)
In China, the US, Brazil, India and Australia, there are long distances between wind/solar/hydro facilities and major population centers. How this power is transmitted is an important part of grid efficiency and renewable energy integration. Using standard AC transmission lines, longer distances tend to result in larger transmission losses and also in greater involuntary curtailment of wind/solar power (i.e., power that could have been generated but which wasn’t consumed).
While AC lines are usually best for short and medium distances, high voltage direct current lines (HVDC) can be more economic for longer distances. The tradeoffs involve the following:
• higher upfront capital costs for DC terminals given the need for voltage conversion equipment • lower per km line costs for DC due to fewer conductors, less metal for towers and lower land costs (a
3-conductor 500 kV AC tower is ~1.5 times larger than a 2-conductor 500 kV DC tower) • fewer transmission losses for DC lines over the project’s life as distances increase (see chart, left)
The chart on the right from the IEA puts all the pieces together: DC lines are usually cheaper once distances exceed 600-700 km13. Siemens and ABB report similar breakeven distances (both are working on the world’s first 1,100 kV HVDC transformers for use in Guquan, China).
13 For electricity aficionados only. For underwater or underground systems, HVDC tends to be used at distances over 50-80 km. Above that level, high capacity AC transmission systems become less feasible for reasons related to electrical capacitance, reactive power losses and the cost/feasibility of shunt reactor substations. Since polymer- or paper-insulated conductors in underground/underwater cables are located much closer to ground than conductors in overhead lines, their electrical capacitance per km is generally much higher. This causes long AC cables to generate significant reactive power, degrading performance over longer distances to the point where eventually less and less real power can be transmitted without some kind of expensive reactive power compensation.
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Source: IEA Energy Technology Systems Analysis Programme, 2014.
Transmission and distribution losses as a % of total generation
Involuntary curtailment ratiosWind/Solar
Country Obs Year CurtailmentDenmark 2014 0.0%Germany 2013 0.2%Ireland 2013 3.8%Italy 2014 0.3%Portugal 2014 0.0%Spain 2013 1.6%US-ERCOT 2014 0.5%US-MISO 2014 5.5%China 2012 17.1%China 2013 10.7%China 2016 17.0%Source: 2015 Wind Integration Workshop, Kansai University (Japan), NRDC.
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Transmission losses: HVAC vs HVDCActive power losses (MW)
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Comparison of HVAC and HVDC lifetime system costsCost
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China leads the world in the installation of HVDC transmission lines. While China has installed 30% of the world’s wind and solar capacity, wind and solar power account for just 5% of Chinese electricity generation. China has a “mandatory goal” of reducing coal’s contribution to primary energy from 62% in 2016 to 58% by 2020, and plans to add more wind, solar and hydro as part of this transition. However, the distance between wind, solar and hydro facilities and China’s urban centers has created challenges, including the high levels of renewable curtailment shown on the prior page. As part of the solution, China is building plenty of HVDC lines, with 20 in operation or under construction.
The table below shows announced HVDC projects of more than 400 kV for several countries. To put China’s HVDC development in context, we created a metric for each country that is equal to the kilometers of its HVDC projects per gigawatt of its total electricity generation capacity. China’s HVDC ratio is more than double that of the US. That’s worrisome enough, but as we discuss on the next page, some announced US projects might not even be completed.
Source: "Renewable Energy Transmission by HVDC Across the Continent: System Challenges and Opportunities", RPI, State Grid Corporation of China, China Electric Power Research Institute. December 2017.
HVDC transmission lines for transfer of renewable energy across China, Sold lines = in operation, dotted lines = to be completed by 2020
HydropowerPV and wind energy
Announced high voltage direct current line projects > 400 kVIn-country projects
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capacity (GW)
Total distance of projects / el gen
capacityMexico 2,740 67 40.6Brazil 4,640 156 29.8China 27,953 1,519 18.4Indonesia 876 57 15.3UK 1,187 95 12.5Germany 2,495 204 12.2USA 8,075 1,074 7.5India 2,021 325 6.2
Source: Global Transmission Research, 2017. Projects shown are in-country only and exclude cross-border HVDC interconnection projects, of which there are 2,500 km in Asia and 5,200 km in Europe.
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US HVDC lines: slower progress, more bottlenecks. A good way to understand challenges in the US is to track the experience of Clean Line LLC. This Houston-based company accounts for 50%-60% of all planned US HVDC development, according to data from Global Transmission Research14. Clean Line projects are all subject to complex regulatory approvals in multiple states. While certain legal rulings have gone in its favor, the length and complexity of the approval process has delayed some of their projects for years, with one rejected outright. We wrote about Clean Line’s Plains & Eastern project last year as an example of belated success, the first HVDC transmission line to be built in the US in more than 20 years after 11 years of planning. Now, that project is up in the air again since the Federal government has ended its partnership agreement with Clean Line.
Clean Line isn’t the only company experiencing delays. The 1 GW Northern Pass line connecting Hydro-Quebec to Southern New England was supported by Massachusetts regulators and its Department of Energy Resources. However, a New Hampshire siting committee rejected the proposal by 7-0, since it worried that the 192-mile system would disrupt streets and harm tourism, particularly in the northern portion of the state. Concessions by the Northern Pass group to bury 52 miles of the route and set aside 5,000 acres of preservation and recreation land have been insufficient to change the outcome so far; appeals are pending. There have also been delays on the New Mexico-based Tres Amigas project, which was supposed to link the three US regional grids with a 750 MW, 345 kV HVDC system costing $1.5 billion. In 2017, Tres Amigas was scaled down to 200 MW and $200 mm, and will no longer include the Texas grid. US HVDC lines are often mentioned as an integral part of a renewable energy future, but it would take a sea change in regulation and local practices to realize it. Researchers at the National Oceanic and Atmospheric Administration explored the possibility of a national US grid of interconnected HVDC lines overcoming wind and solar intermittency, and also reducing the need for storage. They found that by 2030, HVDC lines meeting at 32 nodes could add allow for enough wind and solar power to cut power sector emissions by up to 80% from 1990 levels. But if recent experience is any indication, a national grid of US HVDC lines will remain part of the renewable energy wish list rather than a reality.
14 The GTR database includes HVDC projects that are proposed, under development or under construction.
Name of Clean Line Project
Voltage (kV)
Distance (km)
% of total US
HVDC distance Comments
Centennial West 600 1,449 17.9% Environmental impact statement submitted, approval pending. States affected: New Mexico,
Arizona, and California
Grain Belt Express 600 1,256 15.6%
Approvals received in Kansas, Indiana and Illinois but waiting for approval in Missouri, where it has already been rejected twice since all affected Missouri counties must approve. Clean Line now appealing to Missouri Supreme Court
Plains & Eastern 600 1,160 14.4%
Approvals received in Oklahoma and Tennessee, but not from Arkansas. Clean Line appealed to US Federal Gov't for help in using Section 1222 of the Energy Policy Act of 2005 to override Arkansas objections. However, in March 2018, the Federal Government ended its partnership agreement with Clean Line, removing the possibility of Federal assistance with eminent domain. TVA recently withdrew as purchaser given lack of need and out of concern for costs of backup thermal generation. Clean Line then sold part of its ownership.
Rock Island 600 805 10.0%Illinois Supreme Court rejected Clean Line's application since as an out of state entity with no Illinois assets, it did not quality as a public utility, which is needed to engage in transmission line development. States affected: Iowa and Illinois.
Western Spirit 345 224 2.8% Approvals received from FERC and Bureau of Indian Affairs, negotiating with potential power end-user customers. States affected: New Mexico
Source: Global Transmission Research (2017), JPMAM.
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[10] The Dream Team rebuttal of the Jacobson “100% renewable electricity by 2050” plan (2018)
Some policy recommendations attain notoriety because they’re simple, and because they appeal to the hopes of people who support them. The thankless work of a “critic”, dating back to ancient Greece where the word was derived (κριτικός), is to judge if these policies make sense. Modern day energy critics separate innovations from illusions, and steer us towards actionable, achievable solutions. In 2015, Stanford’s Mark Jacobson and three other researchers published a paper on a low-cost solution to the US grid which would rely 100% on wind, hydro and solar power by 2050. Their 2015 paper is an updated version of an article they first published in Scientific American in 200915. You may have read about their all-renewable US grid idea, or their recent work applying the same concept to 139 countries. Many media outlets and energy blogs cite Jacobson’s proposal as a vision of a possible renewable energy future, if only we just would reach for it. In 2017, the battle began. A large team of scientists and researchers from US universities, think tanks and research labs published a paper in the Proceedings of the National Academy of Sciences16 which (there is no other way to put this) savaged the Jacobson proposal. It’s worth reviewing some of the arguments in their rebuttal, since they illustrate the challenges and complexity of designing real-world energy solutions. While 21 researchers participated in the PNAS paper, for simplicity, we refer to it here as the “Clack rebuttal”. Here’s their overarching conclusion on Jacobson’s proposal:
“The authors claim to have shown that their proposed system would be low cost and that there are no economic barriers to the implementation of their vision. However, the modeling errors described, the speculative nature of the terawatt-scale storage technologies envisioned, the theoretical nature of the solutions proposed to handle critical stability aspects of the system, and a number of unsupported assumptions, including a cost of capital that is one-third to one-half lower than that used in practice in the real world, undermine that claim.”
15 Even in 2009, Jacobson’s thesis came under fire. Physicist Michael Briggs at the University of New Hampshire wrote the following in response to Jacobson’s article: “As a physicist focused on energy research, I find this paper so absurdly and poorly done that it is borderline irresponsible. There are so many mistakes, it would take hours of typing to point out all of the problems.” [Source: M. Briggs, Letter to the editor, Scientific American, 2009]. 16 “Evaluation of a proposal for reliable low-cost grid power with 100% wind, water, and solar”, Clack et al, Proceedings of the National Academy of Sciences, February 2017. Sources for Jacobson’s original piece, the Clack rebuttal, the Jacobson response and another Clack rebuttal are found on p.33. In 2017, Jacobson sued Clack for intellectual defamation, but withdrew the lawsuit in 2018.
Affiliations of the 21 authors participating in the Clack rebuttal • Carnegie Institution for Science (Department of Global Ecology) • Carnegie Mellon University (Department of Engineering and Public Policy; Tepper School of Business) • Columbia University (Center for Global Energy Policy) • Lawrence Livermore National Laboratory • NOAA Earth System Research Laboratory • Stanford University (Department of Energy Resources Engineering; Management Science and Engineering
Department; Precourt Energy Efficiency Center) • UC Berkeley (Energy and Resources Group; Goldman School of Public Policy; Renewable Energy Laboratory) • UC Irvine (Department of Earth System Science) • UC San Diego (Department of Mechanical and Aerospace Engineering; School of Global Policy and Strategy) • Univ. of Colorado (Inst. for Research in Environmental Sciences; Renewable and Sustainable Energy Institute) • University of Vermont (Electrical Engineering and Complex Systems Center) • Uppsala University (Department of Physics and Astronomy) • Brookings Institution and the Council on Foreign Relations
22
The simplest way to illustrate the scope of Jacobson’s proposal is to compare it to the pace of prior capacity additions. The first chart shows annual electricity generation capacity additions from 1960 to 2015 for the US, Germany and China, measured per capita. Peak additions were associated with US nuclear and natural gas build-outs, Germany’s solar and wind era and China’s 21st century grid upgrade. Look at the red line: as per the Clack rebuttal, Jacobson proposed capacity additions are 14x larger than what took place over the prior 50 years, a staggering amount and pace of new generation.
Another look: according to the Clack rebuttal, Jacobson assumes that new US solar, wind, hydro, hydrogen and storage capacity (red bars) will each be built out on a scale that exceeds the entire US electricity generation system as it exists today (blue bar).
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Source: "Evaluation of a proposal for reliable low-cost grid power with 100% wind, water and solar," Clack et al. 2017.
Historical rates of installed electric-generating capacity per capitaCapacity additions, watts per year per capita
Coal and nuclear peak 2nd nuclear
peakNatural gas
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Source: "Evaluation of a proposal for reliable low-cost grid power with 100% wind, water and solar", Clack et al. February 2017.
Jacobson proposal: each of 5 renewable technologies are built-out to be larger than today's entire US electricity grid, GW
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If the scope/cost of Jacobson’s proposal were its only issues, I wouldn’t write about it. The implausible assumptions cited in Clack’s rebuttal are more concerning, and why such proposals should be evaluated based on substance rather than “vision”. If you’re interested, the next 2 pages get into the details. On Jacobson’s hydropower assumptions: • The Clack rebuttal claims that Jacobson assumes a huge 13x hydropower capacity build-out. However,
this is not based on new projects: instead, Jacobson proposes that existing dams be retrofitted with additional turbines to increase potential instantaneous generation.
• According to the Clack rebuttal, this is highly implausible. US hydropower facilities are generally already built over capacity, and already have priority on the grid over thermal power as well as wind and solar: “the primary factor limiting hydroelectric capacity factor is water supply and environmental constraints” rather than under-optimized dams. Clack’s rebuttal also states that Jacobson’s paper is undermined by a hydro modeling error17, and does not adequately incorporate the infrastructure cost of its assumed hydropower expansion.
On Jacobson’s assumed expansion of the hydrogen economy: • As per the Clack rebuttal, in Jacobson’s model, “hydrogen is produced at a peak rate consuming nearly
2,000 GW of electricity, nearly twice the current US electricity-generating capacity”. To understand how large this is: “Total worldwide production of hydrogen from electrolysis is approx. 2.6m tons/year, corresponding to an average electrolysis power consumption of ~16 MW. The US electrolysis build-out envisioned by Jacobson is thus at least a factor 100,000x increase over total world electrolysis capacity today”
• And the price tag? “The costs for electrolyzers necessary to produce hydrogen at a rate of 2,000 GW are at least 10-25 times higher than those reported, with the capital cost for these components totaling approximately $2 trillion”; this is “not appropriately accounted for in the cost estimates”.
• Jacobson’s proposal “includes a wide range of currently un-costed innovations that would have to be deployed at large scale (e.g., replacement of our current aviation system with yet to-be-developed hydrogen-powered planes)”.
17 Clack’s rebuttal cites a hydro modeling error in Jacobson’s paper that is “so large (and so obvious) that it by itself invalidates the entire effort”. In a rebuttal of his own, Jacobson refutes assertions of this error, and stands by the notion that hydroelectricity capacity that is larger than the current US electricity grid can be retrofitted on existing hydro plants. In our 2016 review of hydroelectric power, we cited research from Oak Ridge National Labs showing that US hydropower could increase from 6% to 9% of total electricity generation through development of existing non-powered dams and new stream development.
Understanding the bizarre implications of Jacobson hydropower assumptions: The Grand Coulee Dam If the Grand Coulee Dam in Washington state expanded by the same relative amount as Jacobson’s overall hydro expansion, it would have a new peak power rating of 101 GW: more than all hydropower in the US combined today, and 4.5x larger than the largest power plant of any kind ever constructed (the Three Gorges Dam in Hubei Province, China). The required flow rate through this upgraded Grand Coulee Dam at full power would regularly need to be 5.5x higher than the largest flow rate of its part of the river ever recorded in history, which occurred on June 12, 1948 during an historic Columbia River flood. This flow rate corresponds to 13x the average discharge rate of the entire Columbia river system, and 3.5x the maximum spillway capacity of the Grand Coulee dam itself. [Source: June 2017 Clack et al response to Jacobson]
24
One challenge for a grid with a lot of renewable energy is the mismatch between renewable generation and electricity demand. In this chart from our 2015 energy paper, we plot load and renewable generation for California in January, broken down by hour. We assumed a large build-out of wind and solar, enough to provide 70%-80% of annual generation. As you can see, there would still be long periods in January during which there is insufficient renewable generation to meet demand. Jacobson proposes that gaps like these be addressed through both energy storage and load-shifting (requiring businesses to adjust to when electricity is available rather than when they need it). But…. …On Jacobson’s assumed massive increase in underground thermal energy storage: • Current electricity storage systems store energy for a few hours at a time, and are not built to store
excess wind or solar power for weeks or months. Jacobson assumes this problem is primarily solved through underground thermal energy storage (UTES), which utilizes geothermal boreholes to store heat in the ground. As per the Clack rebuttal, Jacobson assumes that UTES would be “deployed in nearly every community to provide services for every home, business, office building, hospital, school, and factory in the United States. However, the analysis does not include an accounting of the costs of the physical infrastructure (pipes and distribution lines) to support these systems.”
• And this: “Jacobson assumes a total of 2,604 GW of storage charging capacity, more than double the entire current generation capacity of all power plants in the United States. The energy storage capacity consists almost entirely of two technologies that remain unproven at any scale: 515 TWh of UTES (the largest UTES facility today is 0.004 TWh), and 13 TWh of phase-change materials. Although both UTES and phase-change materials are promising resources, neither has reached the level of technological maturity to be confidently used as the main underpinning in a study aiming to show the technical reliability and feasibility of an energy system. Solar district heating with UTES on large scales and at high rates of deployment is rare outside of Denmark”.
…On Jacobson’s assumption of flexible load-shifting: Jacobson’s models assume “free time-shifting of loads at large scale in response to variable energy provision”, and assume that “somewhere between 65% and 80% of Jacobson’s daily loads are assumed to be flexible”. This includes 60% of industrial demand, which is assumed to be able to freely reschedule all energy inputs within an 8-hour window. “The authors do not provide evidence to justify this implausible scale of load flexibility. The idling of capital-intensive industrial facilities when intermittent energy sources are unable to meet demand represents a large cost that is not included”. And finally, on the underestimation of transmission investment According to the Clack rebuttal, Jacobson assumes that 45% of wind, hydro and solar generation will be sent through a new national long-distance grid. However, they found no explicit modeling, reference or cost information on transmission in Jacobson’s proposal, and believe that ”their analysis ignores transmission capacity expansion, power flow, and the logistics of transmission constraints”. While there are estimates of transmission costs in Jacobson’s proposal, Clack et al believe they are way too low. The mic has been dropped.
0
5
10
15
20
25
30
35
Jan 1 Jan 6 Jan 11 Jan 16 Jan 21 Jan 26 Jan 31Hydro/biogas/biomass/geothermal
Wind
California: January load vs. renewable generationHourly generation by source with load, gigawatts
Source: CAISO, JPMAM. 2015.
Load Solar
25
[11] Better safe than sorry: sea level rise, coastal exposure and flood mitigation projects (2018)
What if the earlier sections of this paper are correct about the gradual pace of grid and industrial sector decarbonization, electric vehicle penetration and HVDC transmission line adoption? Possible outcomes argue for flood mitigation projects in major coastal cities. Let’s begin with sea levels. In 2014, the Intergovernmental Panel on Climate Change estimated that sea levels could rise by 0.6 to 1.0 meters by the year 210018. Some newer estimates show higher levels, ranging from 2.0 to 2.5 meters of sea level rise instead19. In most of these models, sea levels keep rising after the year 2100, reaching 5 meters by the year 2200.
Why are new sea level rise estimates higher than the 2014 IPCC estimates? In scientific terms: “Underappreciated processes linking atmospheric warming with hydro-fracturing of buttressing ice shelves and structural collapse of marine-terminating ice cliffs”20. In layperson’s terms: Large areas of ice that are currently attached to the ocean floor and protruding above sea level (i.e., not floating) could cleave into the ocean as large blocks of ice fall from cliffs at the ice edge, thereby raising sea levels regardless of when/if they melt. The authors of this paper reminded me that their work is highly theoretical, but also based on observed processes now taking place in Antarctica and Greenland.
18 A January 2018 paper from researchers at the University of Colorado and the National Center for Atmospheric Research used a different approach and estimated future sea levels solely based on observed changes over the last 25 years. Their results were similar to the IPCC 8.5 scenario.
19 The chart shows projected sea level rise under the RCP 8.5 scenario, which is the most bearish assessment of future greenhouse gas emissions. Supplementary materials on page 28 illustrate how sea level rise estimates differ under RCP 4.5, and also include a chart on estimated sea level changes from the year 500 BC to today.
20 “Contribution of Antarctica to past and future sea-level rise”, DeConto (UMass) and Pollard (Penn State), Nature Magazine, March 2016.
0
1
2
3
4
5
6
7
8
9
0.0
0.5
1.0
1.5
2.0
2.5
3.0
IPCC(2014)Median
IPCC(2014)95th p
Levermann(2016)Median
Levermann(2016)95th p
Kopp(2017)
Median
Kopp(2017) 95th p
Le Bars(2017)Median
Le Bars(2017)95th p
Breakdown unspecifiedAntarcticaGreenlandMountain glaciersThermal expansion
Source: IPCC, Levermann et al, Kopp et al, Le Bars et al.
Sea level rise by the year 2100 based on Representative Concentration Pathway 8.5 Meters Feet
26
How much damage could be caused by 2 meters (~6.5 feet) of sea level rise in the US, incorporating additional heights associated with storm surges? The US Global Change Research Program21 estimated that this amount of sea level rise could put at least 6,000 square miles and $1 trillion (in 2014$) of property and structures at risk. Its Climate Assessment report also included the following stats which further illustrate the risks if sea level rise projections are accurate: • Each year, more than 1.2 mm people (the equivalent of nearly one San Diego) move to the coast, the
Great Lakes or open-ocean coastal watershed counties and parishes of the US • 164 mm Americans (more than 50% of the population) now live in these densely populated areas and
help generate 58% of US GDP. Economic activity in shoreline counties accounted for 66 million jobs and $3.4 trillion in wages
• Low-lying water-dependent infrastructure such as onshore gas and oil facilities, ports, thermal power plants and wastewater management/drainage systems are difficult and expensive to relocate
Here are some charts that make the point as well: the large contribution to the US economy from coastal and shore-adjacent counties; storm surge heights that render major NYC infrastructure inoperable; and the increasing number of tidal flood days per year in coastal states.
Tidal Flood Days per year, 1950-2015
Source: USGCRP Fourth Climate Assessment, Chapter 12. 2014.
21 The United States Global Change Research Program coordinates and integrates research from 13 different Federal agencies on changes in the global environment and their implications for the US. The program was launched by President George H.W. Bush in 1989.
0%
10%
20%
30%
40%
50%
60%
Employment GDP Population Land Area
Coastal Zone counties Shore-adjacent counties
Source: Middlebury, Nat'l Ocean Econ Program. 2016. Data as of 2014.
Coastal regions' share of US economy %
FDR
Driv
e
Met
No.
Hud
son
LaG
uard
ia A
irpor
t
A/C
/M/N
/R tr
ains
Hol
land
Tun
nel
Ver
raza
no B
ridge
Bkl
n B
atte
ry T
unne
l
LIR
R E
ast R
iver
Wes
t St
4, 5
and
6 tr
ains
Thro
gs N
eck
Brid
ge
Pen
n S
tatio
n
New
ark
Airp
ort
Linc
oln
Tunn
el
Que
ens
Mid
tow
n Tu
nnel
Gra
nd C
entra
l Sta
tion
JFK
Airp
ort
Trib
oro
Brid
ge
0
2
4
6
8
10
12
14
16
0
1
2
3
4
5
Source: US Army Corps of Engineers, FEMA, Nat'l Weather Service. 2000.
Critical storm surge elevations by location (at which New York City systems become inoperable)Meters above sea level Feet above sea level
27
Similar coastal exposures exist outside the US. A common feature of population exposure models is the assumption that more people will move from inland regions to the coasts, where the opportunities are. In recent years, coastal cities with major ports have seen faster growth rates.
One assessment of exposed populations comes from the Coastal Risks and Sea-Level Rise Research Group at Kiel University in Germany. Their analysis takes two approaches: how many people will live in “low coastal elevation zones”, and how many will live in the “100-year flood plain”22. The former is larger than the latter, but in either case, (a) their 2060 projections of exposed populations are at least 2x the year 2000 baseline, and (b) the largest affected populations live in Asia (mostly in China, India, Vietnam and Bangladesh).
22 The “low-elevation coastal zone” describes all coastal land adjacent to the sea (and hydrologically connected to the sea), and not more than 10 meters above mean sea level. The “flood plain” refers to land inundated in storm surge events that occur statistically every 100 years.
Coa
stal
citi
es w
ith m
ajor
por
ts
Inla
nd c
ities
Coa
stal
citi
es w
ith s
mal
l por
ts0%
2%
4%
6%
8%
10%
12%
14%
Source: Euromonitor. 2014.
Coastal port cities boast stronger growth vs inland citiesAggregate real GDP growth, 2008-2013, %
AsiaAsia
AsiaAfrica
Africa
Africa
Europe
Europe
EuropeLatAm/Carib.
North America
0
200
400
600
800
1,000
1,200
1,400
1,600
Baseline2000
Low Scenario2060
High Scenario2060
Source: "Future Coastal Population Growth and Exposure to Sea-Level Rise and Coastal Flooding - A Global Assessment", Neumann et al. 2015.
Flood exposure population by region based on Low Elevation Coastal Zones, Population, millions
AsiaAsia
AsiaAfrica
Africa
Africa
Europe
Europe
EuropeLatAm/Carib.
North America
050
100150200250300350400450
Baseline2000
Low Scenario2060
High Scenario2060
Source: "Future Coastal Population Growth and Exposure to Sea-Level Rise and Coastal Flooding - A Global Assessment", Neumann et al. 2015.
Flood exposure population by region based on 100-year flood plains, Population, millions
28
While modeling sea level rise is complicated, building flood mitigation infrastructure is not. The simplest projects involve land-based sea walls, dikes or sand dunes. The more advanced versions are sea-based, and involve a series of hydraulic locks, dams, gates, etc, and have been proven to work during severe storm and flooding events. Here’s a sampling of different kinds of sea-based barriers, including their existing locations and common maximum dimensions (in meters):
How are these projects paid for? When there’s a will, there’s a way:
Taxes A state-wide surcharge (tax) on property & casualty insurance premiums A “local option sales tax” levied by a local municipality to fund infrastructure Earmarked revenue streams connected to properties that benefit
Government funds
EPA federal funding through the Water Infrastructure Finance and Innovation Act Hybrid approach enlisting federal, state and local dollars Local municipal asset sales to fund construction
Bonds Issuance of “green bonds”, traditional private activity bonds or general obligation debt Privatization
Requires stream of revenues or an operating business to incentivize private capital, whether through outright privatization or via public private partnerships
Hydraulic sea barrier types
Type Rotary segment Inflatable Flap Barge gate Vertical risingMax W,H,WD 40 / 8 / 2 120 / 10 / 6 6 / 8 / 2 80 / 20 / 6 50 / 5 / 2Location Thames, Gandersum Ranspol Stamford, Venice New Orleans St PetersburgView shown Cross section Cross section Cross section Top view Cross sectionComments
Type Segment Vertical lift gate Rolling Segment gatesMax W,H,WD 100 / 8 / 6 60 / 12 / 4 60 / 20 / 6 360 / 20 / 2
Location
View shown Cross section Cross section Top view Top viewComments Double gates
swinging on vertical axis; stored in docks
Sources: "Multifunctional Flood Gates ", Dijk and van Ziel, Royal Haskoning DHV; and "Overview and Design of Storm Surge Barriers ", Mooyart and Jonkman, Delft University of Technology, Civil Engineering and Geosciences Dep't.
"Max W,H,WD" refers to the estimated maximum width, height and water differential for each barrier, measured in meters, and based on current materials limitations.
In recess, gate lies in a concrete sill on ocean floor
Synthetic rubber or laminated plastic, inflated with air or water
Pivoted on fixed axis Pivoted on vertical axis
Positioned largely under water in open and closed positions
Panama, Hamburg New Bedford, St Petersburg, New Orleans, Maeslant, Seabrook
Utrecht, Zeeland, Hull(UK), Gandersum, N. Orleans
Eider, Thames, St Petersburg
Rotates around horizontal axis
Tower-supported lift gates with overhead cables or hydraulic cylinders
Sliding panels stored adjacent to the waterway
29
The bigger challenge for policymakers: the cost. While recent estimates put the cost of simple coastal barriers (e.g., piles of sand or simple sea walls) at 15,000 to 20,000 Euros per meter, water-based storm surge infrastructure can be up to 100x more expensive. The table below is from a paper published in the New York Academy of Sciences in 2013; estimated costs range from $0.5 to $3.5 million per meter. A more recent paper from 2017 cites costs of 2.2 million Euros per meter, which is at the higher end of the figures shown in the table. One last observation: a storm surge barrier system protecting New York City and parts of New Jersey could cost $2.7 million per meter, assuming (i) a barrier across the 8 km gap between the northern tip of Sandy Hook, NJ and western tip of Breezy Point, NY combined with (ii) a smaller barrier across a 1 km area near the Throgs Neck Bridge. The larger barrier would consist of levees, rotating sector gates and vertical lifting gates, while the smaller barrier would incorporate flap gates. These proposed barriers are expected to be complemented by 2 meter seawalls along parts of Staten Island, Manhattan and Brooklyn to protect against potential surges from the Hudson River. Examples of sea-borne infrastructure barriers, with costs in 2012$
It might take more catastrophic storms to convince the public that cost-benefit ratios for flood mitigation projects make sense. Some studies already point in this direction, including an analysis of global coastal exposures by researchers at Berlin’s Global Climate Forum. They found that by protecting only 13% of the world’s coastline, positive benefit-to-cost ratios could be achieved on 90% of the global floodplain population and 96% of the assets23. While some of their benefit-to-cost ratios were 2:1 or 3:1, many were on the order of 100:1 and 300:1, reinforcing that the cost of inaction can be much greater than spending on infrastructure today24. These studies analyze simple sea walls rather than the hydraulic structures described above; there are fewer comprehensive cost-benefit analyses of the latter. In any case, competition for dollars is intense; flood mitigation project proponents will have plenty of convincing to do.
23 “Economically robust protection against 21 st century sea-level rise”, Jochen Hinkel and Daniel Lincke, Global Climate Forum, Pending.
24 Flood mitigation can also include nature-based engineering solutions to restore wetlands between rivers and human settlements. This could provide extra water storage, slow down flood propagation and reduce flood risks in populated parts of a delta. One example: a plan to divert sediment-laden rivers back onto the Mississippi delta plain. Natural wetland-building processes with sediment delivered through river diversions are estimated to cost about 10x less than projects with conventional sediment delivery by barge or pipeline.
Location Gate type CountryConstruction
YearsWidth
(m)
Gate height
(m)Head
(m)
Constr. costs
($ mm)
Constr. costs per meter($mm/m)
Operation & Maint. costs
($mm/yr)Thames Rotating sector UK 1974-1982 530 17 7.2 1,883 3.55 13Maeslant Floating sector NL 1989-1997 360 22 5.0 852 2.37 15Eastern Scheldt Vertical lifting NL 1974-1986 2,400 14 5.0 5,227 2.18 20Venice MOSE Inflatable flap Italy 2003-today 3,200 15 3.0 6,125 1.91 12.8Seabrook Vertical lifting/sector USA 2005–2011 130 8 4.0 165 1.26 2.1Hollandse Ijssel Vertical lifting NL 1954–1958 110 12 3.5 127 1.15 2Hartel Vertical lifting NL 1993–1996 170 9 5.5 185 1.09 2.4Ems Rotating sector Germany 1998-2002 476 11 3.8 376 0.79 6.3Ramspol Inflatable rubber dam NL 1996–2002 240 8 4.4 171 0.71 1.1IHNC, New Orleans Sector/vertical lifting USA 2005–2011 2,800 8 4.0 1,100 0.45 2.5Cardiff Bay Sluice/lifting UK 1994–2000 1,100 8 3.5 340 0.31 15Fox Point Vertical rotating USA 1961–1966 300 12 6.0 88 0.29 0.5St Petersburg Floating sector/vertical lifting Russia 1984–2011 25,400 24 5.0 6,953 0.27 N/AStamford Flap USA 1965–1969 866 11 5.0 82 0.09 N/ANew Bedford Horizontally moving sector USA 1961–1966 2,774 18 6.0 111 0.04 N/ASource: "Cost estimates for flood resilience and protection strategies in New York City," Aerts et al. 2013.
30
Flood Mitigation supplementary materials: carbon pathways, sea levels and storm surges
Most sea level rise analyses incorporate an assumed pace of global greenhouse gas emissions, referred to as “Representative Concentration Pathways”. The associated number refers to its GHG concentration relative to preindustrial values. Under RCP 8.5, sea levels are expected to rise by 2.0 to 2.5 meters by the year 2100. Under RCP 4.5, sea levels are expected to rise by 1.0 to 2.0 meters, as shown below. To be clear, RCP 4.5 assumes substantial progress in slowing the rate of GHG emissions over the next century.
The third chart shows a reconstructed estimate of sea levels since the year 500 BC. This chart appeared in the USGCRP Fourth National Climate Assessment, released in 2017. The last chart shows how the timing of storm surges can affect their severity, and the need to plan for surges which could happen at the worst times of the day.
0.00.20.40.60.81.01.21.41.61.82.0
IPCC(2014)Median
IPCC(2014)95th p
Levermann(2016)Median
Levermann(2016)95th p
Kopp(2017)
Median
Kopp(2017) 95th p
Le Bars(2017)Median
Le Bars(2017)95th p
Breakdown unspecifiedAntarcticaGreenlandMountain glaciersThermal expansion
Source: IPCC, Levermann et al, Kopp et al, Le Bars et al.
Sea level rise by the year 2100 based on Representative Concentration Pathway 4.5, Meters
200
400
600
800
1,000
1,200
1,400
2000 2010 2020 2030 2040 2050 2060 2070 2080 2090 2100
Source: "Fifth Assessment Report", IPCC. 2014.
Representative concentration pathways of GHGsCO2 equivalent (parts per million)
RCP 8.5
RCP 6.0
RCP 4.5
RCP 2.6
-15
-10
-5
0
5
500 BC 0 500 1000 1500 2000Source: US Global Change Research Program. 2017.
Global mean sea level risingChange relative to 2000, centimeters
-2
0
2
4
6
8
10
-0.6
0.0
0.6
1.2
1.8
2.4
3.0
6:00 9:00 12:00 15:00 18:00 21:00 0:00 3:00 6:00
Source: "Storm Surge Modeling and Climatology for the New York City Metropolitan Region", Brian A. Colle, Stony Brook University. 2009.
Hurricane Gloria (1985): the luck of the tidesWater level in meters Water level in feet
Actual storm surge
Storm surge if Gloria had hit at high tide
Generic normal
tide
Time (GMT) 09/27/1985 - 09/28/1985
31
[12] Hydraulic fracturing: the latest from the EPA and some conflicting views from its Advisory Board (2017)
In the US, oil and natural gas production are increasingly reliant on hydraulic fracturing. The EPA’s review of its impact on drinking water supplies, and the response by the EPA’s Science Advisory Board, are the basis for this section. A lot is at stake, since unconventional oil and natural gas reserves play a critical role in the energy future of the United States. Here are some of the more important benefits of US unconventional shale gas production: • The ability to rely more on natural gas and less on coal25, whose environmental footprint is worse than
natural gas on a variety of metrics (not just carbon), and which we wrote about here. As stated in the Executive Summary, fuel switching from coal to gas was the primary factor driving down US CO2 emissions faster than other large CO2 emitting countries from 2000 to 2015
• The ability to add more renewable energy to the grid, and respond rapidly with low-cost back-up power from natural gas when wind, solar and hydropower generation is low
• The ability to develop natural gas-powered vehicles and trains with lower fuel costs than gasoline or diesel-powered counterparts, and with greater geopolitical fuel security
• The ability to decommission certain nuclear power plants should their financial, security or environmental costs exceed tolerable levels (there is still no solution to spent-but-still-radioactive fuel rod treatment other than dry casks and above-ground immersion in storage pools)
The chart below shows the US electricity mix with EIA projections to 2040, with our added assumption that natural gas gradually substitutes for certain nuclear power plants, including those already scheduled to close over the next decade26. An electricity grid with less coal, less nuclear and more renewable energy would be highly dependent on abundant, low-cost natural gas.
25 Could “carbon capture and storage” effectively provide a lifeline to US coal reserves? I doubt it. I wrote about this in the 2017 Eye on the Market Outlook; see here.
26 US nuclear power plants scheduled to close within the next decade include Pilgrim (MA), Diablo Canyon (CA), Three Mile Island (PA), Palisades (MI), Indian Point (NY) and Oyster Creek (NJ).
0%
10%
20%
30%
40%
50%
'90 '94 '98 '02 '06 '10 '14 '18 '22 '26 '30 '34 '38
Source: Energy Information Administration, JPMAM. December 2016.
US: natural gas could provide a pathway for more renewable energy, less coal and less nuclear% of total electricity generation
Coal
Natural gas
Renewables
Nuclear
Natural gas CO2 comparisons
• electricity: natural gas emits 50% less CO2 per unit of energy when combusted in a natural gas plant compared with emissions from a typical coal plant
• transportation: natural gas emits 15%-20% less heat-trapping gases than gasoline per mile of travel when burned in a typical vehicle
32
Before getting into the EPA report on drinking water and the response by its advisory board, here’s some background on the rise in hydraulic fracturing, where shale gas and tight oil are located, water usage and the drilling depths of fractured wells. The rise of hydraulic fracturing. The technique of hydraulic fracturing is used for both unconventional natural gas extraction and unconventional oil extraction. The next two charts show the rise in tight gas, shale gas and tight oil, all of which depend on hydraulic fracturing:
The US represents ~20% of global natural gas production and ~13% of global oil production. However, the practice of obtaining natural gas from shale formations and oil from tight oil formations is almost exclusively a US phenomenon. As of a couple of years ago, only 3 other countries engaged in the practice, and to a much smaller degree:
0
5
10
15
20
25
30
35
40
'90 '92 '94 '96 '98 '00 '02 '04 '06 '08 '10 '12 '14 '16 '18 '20 '22 '24 '26 '28 '30
Source: Energy Information Administration. 2015.
US natural gas production by typeTrillion cubic feet per year
Conventional
Shale gas and tight oil plays
Tight gas
Coalbed methaneUnconventional
Conventional
0
2
4
6
8
10
12
'10 '12 '14 '16 '18 '20 '22 '24 '26 '28 '30
Source: Energy Information Administration. 2016.
US oil production by typeMillion barrels per day
Tight oil (unconventional)
Conventional
Shale gas Tight oilbn cu ft per day mm barrels per day
US 37.34 3.93 Canada 4.10 0.47 China 0.50 Argentina 0.07 0.02 Source: EIA. Shale data as of 2015. Tight oil data as of 2014.
Oil & Gas production from shale gas and tight oil formations
Our fracturing focus: horizontally drilled wells While many conventional oil & gas wells are also subject to hydraulic fracturing, our focus here is mostly on onshore horizontal hydraulic fractures. As shown on page 16, horizontal wells are highly water-intensive, using 10x-14x the volume of water per well than directionally or vertically fractured wells. Horizontal wells are also growing in number. In 2005, horizontally fractured oil and gas wells only represented 5% of the total fractures; by 2014, this had grown to 58%.
Source: USGS/IHS universe of 370,000 wells drilled from 2000 to 2014.
33
Shale gas and tight oil locations. Shale gas production and proven reserves are concentrated in a handful of states, with the greatest concentrations in Texas and Pennsylvania27. You can also click here for a map showing current and prospective shale plays. Tight oil production and proven reserves are primarily concentrated in two formations: Eagle Ford (TX) and Bakken (ND, SD, MT).
Hydraulically fractured well depths. The lowest drinking water depths are ~800 feet, and as shown in the next chart, fracturing generally occurs far below that level, with average well depths from 4,000 to 12,000 feet below the surface28. However, the chart also shows a small subset of shallower fractured wells at 2,000 feet and higher in states like Texas, Wyoming, Arkansas and Colorado. There were 1,200 of such shallow wells, equal to 3% of the observed sample. These wells could pose risks since fractures can propagate upwards. A 2012 paper29 found that the highest recorded upward propagation of a US hydraulically fractured well was ~2,000 feet (although this is unusual; the same paper estimated a 1% chance of a propagation over 1,200 feet due to natural protection from sedimentary rock).
27 In New York, due to a ban on hydraulic fracturing, there is no infrastructure or definitive development plan to extract natural gas resources in the state within five years. As a result, New York’s shale gas fails to meet the EIA’s definition of proven reserves. Some estimates place New York’s possible reserves as high as Ohio.
28 The data shown are based on 44,000 well depth observations reported to FracFocus from 2008 to 2013.
29 “Hydraulic fractures: How far can they go?”, Marine and Petroleum Geology, 2012, Davies et al, Durham University Energy Institute
Pen
nsyl
vani
a
Texa
s
Wes
t Virg
inia
Loui
sian
a
Okl
ahom
a
Ohi
o
Ark
ansa
s
Nor
th D
akot
a
Col
orad
o
All
othe
r sta
tes
0.00.51.01.52.02.53.03.54.04.55.0
Source: Energy Information Administration. 2015.
Where shale gas is producedUS shale gas production, billion cubic feet per year
Pen
nsyl
vani
a
Texa
s
Wes
t Virg
inia
Okl
ahom
a
Ohi
o
Loui
sian
a
Ark
ansa
s
Nor
th D
akot
a
Col
orad
o
All
othe
r sta
tes
0
10
20
30
40
50
60
Source: Energy Information Administration. 2015.
Where shale gas proven reserves existUS proven shale natural gas reserves, trillion cubic feet
WY
WY
TX
TX
COCO
PAPA
WVWV
LALA
ND ND
ARAR
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
Mean 1% 5% 10% 25% 50% 75% 90%
feet
bel
ow s
urfa
ce
Percentage of wells above indicated depthDepths of hydraulic fracturing wells
TX, WY, AR, CO: small subset of wells fractured closer to drinking
water aquifers
Source: Env. Science & Technology, Jackson (Stanford) et al. 2015.
34
Hydraulic fracturing and water usage. Fracturing starts with water (freshwater, brackish water, municipal water, etc) mixed with sand and chemicals. The mixture is injected at high pressure, creating small cracks in rock formations that allow gas and oil to escape and rise to the surface. What also comes back up is a lot of water: “flowback water” (original fluid injected into the well), and “produced water”, which is naturally occurring and released from rock formations. Over the lifetime of a fractured well, as much as 90% of returning water can be the produced water rather than the flowback water30 (see chart). This is important from an environmental perspective, since produced water can contain toxic substances: lead, arsenic, barium, chromium, uranium, radium, radon and benzene, and high levels of sodium chloride31. Due to its composition, wastewater is usually recycled or reinjected underground32.
The next chart shows water usage at some of the larger unconventional oil locations. The “mother of all produced water” locations is the Permian Basin, whose produced water-to-oil ratio was 6.5x in 2016, vs 1.1x in the Bakken and 0.9x in Eagle Ford. The final chart shows how horizontally fractured oil and gas wells account for an increasing share of water usage vs directionally and vertically fractured wells33.
30 “Quantity of flowback and produced waters from unconventional oil and gas exploration”, Duke, August 2016
31 “Chemical and Biological Risk Assessment for Natural Gas Extraction in New York”, SUNY Oneonta, 2011
32 In places like Texas and Oklahoma, wastewater is often reinjected into deep underground wells (unused saline aquifers), while in Pennsylvania, wastewater is often recycled for re-use or sent to water treatment facilities. Part of the disposal process involves solid material (“cuttings”) and not just liquids.
33 “Hydraulic fracturing water use variability in the United States and potential environmental implications”, U.S. Geological Survey, Water Resources Research (American Geophysical Union), July 2015
02468
101214161820
Bakken Barnett EagleF Gas EagleF Oil Haynesville Niobrara
Injected
Flowback
Produced
Source: Duke University Nicholas School of the Environment, 2016.
Injected, flowback and produced water per wellMillion liters
50,000
100,000
150,000
200,000
250,000
300,000
2013 2014 2015 2016
Source: Digital H20. March 2017.
Average water used per well in US unconventional oil plays, barrels of water
Permian Basin, Texas and New Mexico
Williston (Bakken),
Montana and North Dakota
Eagle Ford, Texas
02,0004,0006,0008,000
10,00012,00014,00016,00018,00020,000
'00 '01 '02 '03 '04 '05 '06 '07 '08 '09 '10 '11 '12 '13 '14
Horizontal GasHorizontal OilDirectional GasDirectional OilVertical GasVertical Oil
Source: US Geological Survey Earth Sciences Center, March 2015
Annual water volume injected per fractured well by typeCubic meters
35
What are the risks? As long as hydraulically fractured wells are properly cemented when they go through water tables and deeper aquifers, there should in theory be no contamination of ground water, assuming strict protocols for proper tank and pond storage of produced water and requisite on-site cleansing. However, given the number of wells involved (600,000 fractures in the US and Canada in 201434), instances of contamination are statistically unavoidable. Potential risks include a failure of cement surrounding the wellbore, and contamination of groundwater from accidents during transport, storage and disposal of fluids and wastewater. I have read peer-reviewed academic studies on specific instances of adverse environmental impacts from hydraulic fracturing, and to me as a layperson, they seemed conclusive and well-researched. However, these studies were generally deemed inconclusive, dated or in some other way flawed by industry people I showed them to. Similar differences are found in analyses of well failures and risks. A professor from the Colorado School of Mines estimated that only 10 of 17,948 wells drilled from 1970 to 2013 in the Colorado Wattenberg Field failed. In contrast, a 2017 study from UC Boulder found a 7% instance of wells in the Wattenberg field having critical well integrity issues. In this piece, I am not going to opine on environmental impacts and risks; that’s what the EPA is supposed to do, which is why we review their findings, first released in 2015. The original 2015 EPA draft report on hydraulic fracturing and drinking water35 The EPA examined hydraulic fracturing in depth and released a 998-page draft report in June 2015. The draft gave hydraulic fracturing a mostly clean bill of health; at least that’s how it was interpreted in news reports commenting on it. The section that received the most attention: the Executive Summary, where the EPA concluded that while there are mechanisms through which fracturing can impact groundwater, they did not find evidence of widespread, systemic impacts; and that while they did find instances of contamination, they were “small compared to the number of hydraulically fractured wells”. Some other observations from the EPA’s June 2015 report: • The EPA found that if their estimates were representative, spills could range from 100 to 3,700 spills
annually, assuming 25,000 to 30,000 new wells fractured per year • Most wells used in hydraulic fracturing have casing and a layer of cement to protect drinking water
resources. An EPA survey of wells hydraulically fractured by 9 companies in 2009/2010 estimated that 3% of wells (600 out of 23,000) did not have cement across a portion of the cement casing
• Of 225 produced water spills in one study, 8% reached surface water or groundwater
34 “Hydraulic fracturing”, C. Mark Pearson, Liberty Resources and IHS
35 The EPA’s focus in the report was on drinking water resources and not on GHG emissions. On the GHG issue, there’s a debate about methane leakage from natural gas wells. Most research I have seen concludes that methane leakage is well below levels that would negate its GHG benefits vs coal:
• The EPA estimates methane leakage of 1.5% - 2.5%. Recent studies concur with EPA findings, including a 2015 paper which found average methane leakage rates of 1.0% - 2.1% in Haynesville (TX), 1.0% - 2.8% in Fayetteville (AR), and 0.2% - 0.4% in Marcellus (PA)
• Richard Muller (Univ. of California, Scientific Director of Berkeley Earth): leakage rates are below the 5.3% and 12% levels that would negate GHG benefits of natural gas vs. coal when measured over 20 and 100 years
• A team from Harvard, Stanford, MIT, NREL, LBNL and the Environmental Defense Fund concluded that “assessments using 100-year impact indicators show system-wide leakage is unlikely to be large enough to negate climate benefits of coal-to-natural gas substitution”
36
The 2016 EPA Science Advisory Board response However, the story doesn’t end there. The EPA Science Advisory Board (SAB), composed of industry, academic and regulatory members, issued a 180-page review of the EPA draft in August 2016. Its findings were supported by all 47 members of the SAB. They raised issues and asked questions: • The SAB found the EPA draft report to be “comprehensive but lacking in several critical areas” • The SAB had concerns “regarding the clarity and adequacy of support for several major findings
presented within the draft that seek to draw national-level conclusions regarding the impacts of hydraulic fracturing on drinking water resources. The SAB is concerned that these major findings as presented within the Executive Summary are ambiguous and appear inconsistent with the observations, data, and levels of uncertainty presented and discussed in the body of the draft”
In response, the EPA released a final draft of its report in January 2017, which included point-by-point responses to the SAB. The EPA removed the sentence on the left and added the one on the right:
Original 2015 EPA draft, from Executive Summary
Final EPA report January 2017, from Executive Summary
“We did not find evidence that these mechanisms have led to widespread, systemic impacts on drinking water resources in the United States”
“This report describes how activities in the hydraulic fracturing water cycle can impact -- and have impacted -- drinking water resources and the factors that influence the frequency and severity of those impacts”
The EPA appears to have agreed with the SAB that its original conclusions weren’t sufficiently supported given the data gaps and uncertainties. In addition, the SAB pointed out that they would like to see more follow-up on widely reported issues in certain towns in Texas, Wyoming and Pennsylvania, and asked the EPA to do more work on: • the probability and significance of failure mechanisms and water quality impacts (from poor
cementation techniques, hydraulic fracturing operator error, migration of hydraulic fracturing chemicals from the deep subsurface and abandoned/orphaned oil and gas wells)
• an expanded list of toxicity factors • the consequences of water withdrawal in areas with low water availability and frequent drought • concentration of contaminants in wastewater during successive reuse cycles • a list of best practices to minimize impacts on drinking water resources
37
I don’t know where this all goes from here, particularly given changes at the EPA and other political shifts since the election (i.e., a proposed 30% cut in EPA funding in the President’s budget). One example: the House passed a bill36 (currently in the Senate) which in practice may discourage scientists from serving on the EPA Advisory Board. Why? Scientists that receive EPA funding for their research projects would no longer be allowed to serve on the Board. They also can not apply for EPA research grants within three years of the end of their service on the Board. These changes appear to reflect the view that scientists getting EPA research grants are somehow “conflicted”. The political balance between growth, employment and energy security on the one hand, and environmental safety on the other, has clearly shifted since the election. In the long run, the best outcome appears to be one in which: • the US retains the financial, geopolitical and environmental benefits of unconventional natural gas,
and financial/geopolitical benefits of unconventional oil • existing safeguards at multiple stages of the hydraulic fracturing process are applied more universally
to all operators • the EPA conducts additional research to highlight which practices entail the greatest degree of risk,
with the goal of further reducing potential adverse environmental impacts That makes sense to me, since broader restrictions would require the US to either rely solely on its smaller conventional oil and natural gas reserves, or import more oil and gas from abroad.
36 The EPA Science Advisory Board Reform Act, HR1431.
38
[13] Forest biomass: not as green as you might think (2017) Some universities claim to have reached carbon neutrality on campus (see topic #5 in this year’s paper). One aspect of their claim that caught my eye was the assertion that biomass is by definition “carbon-neutral”. Some members of Congress agree with them: an amendment introduced in 2016 by Senators Collins (R-ME) and Klobuchar (D-MN) called on the EPA as well as Agriculture and Energy departments to craft a policy to reflect "the carbon-neutrality of forest bioenergy". Well, forest biomass emissions are more complex than that37. There are things about biomass that should make you suspicious of blanket claims of carbon neutrality (source: Natural Resources Canada): • Wood combustion emits more CO2 than fossil fuels per unit of energy released • CO2 release is much faster when wood is burned than when wood undergoes natural decomposition • CO2 recapture by vegetation is not immediate and is usually achieved over many years/decades To sort things out, I contacted Jerome Laganiere at the Laurentian Forestry Centre in Quebec, whose biomass study was published this year. The CO2 footprint from biomass depends on the specifics38: • What biomass feedstock is used: harvest residue, salvaged dead trees or live trees? If the latter, what
is their growth rate? • Is biomass used to create heat or electricity? • Is biomass used to replace coal, oil or natural gas? • And perhaps most importantly, over what time frame are CO2 calculations performed? Scenarios in
which forest biomass replace fossil fuels and generate net CO2 benefits only after 70 or 80 years may not be that helpful, since many climate scientists believe that CO2 emissions need to be reduced in the next 30-40 years to avoid irreversible temperature increases
We’ll take a closer look at the results on the next page. To summarize, biomass is not always as green as many believe, and studies that raise questions about its carbon neutrality are gaining in prominence. In April 2017, a new EU study39 challenged the carbon neutrality of energy from wood after finding that forests can take centuries to re-absorb the CO2 generated through use of biomass. The report warned that a bias towards biomass energy could damage forest carbon stocks which are key to delivering the Paris Agreement, and proposed a “payback” rule to ensure that only energy uses that deliver CO2 reductions within a certain timescale should be considered renewable under EU law. Their conclusion: assuming all forms of biomass energy are carbon neutral is “highly simplistic”.
37 There’s so much confusion around forest biomass carbon accounting that in 2015, a Journal of Forestry article was dedicated to common errors, most prominent of which is failing to consider the fate of forest carbon stocks in the absence of demand for bioenergy. In other words, if trees aren’t cut down, they continue to absorb carbon; and if not used for biomass, harvest residue would release carbon over time, albeit slowly. 38 Laganiere’s analysis was based on Canadian biomass and fossil fuel conditions. The same analysis can be applied to other places, some of which have faster growing tree species such as South Carolina pines or Brazilian eucalyptus, and warmer temperatures that speed up decomposition of salvaged trees and harvest residue (which make biomass comparisons look better). However, even with faster growing trees and warmer temperatures, biomass is not a priori carbon-neutral; its net carbon impact should be carefully measured. 39 “Multi-functionality and sustainability in the European Union’s forests”, European Academies Science Advisory Council, April 2017. In February 2017, the UK’s Chatham House came to similar conclusions on short-term biomass impacts: “Overall, while some instances of biomass energy use may result in lower life-cycle emissions than fossil fuels, in most circumstances, comparing technologies of similar ages, using woody biomass for energy will release higher levels of emissions than coal and considerably higher levels than gas.” See “Woody Biomass for Power and Heat Impacts on the Global Climate”, Chatham House, February 2017.
39
Let’s get to the punchline. Scenarios involving the use of Canadian “harvest residue” to generate heat are estimated to produce cumulative net carbon benefits by year 50, regardless of which fossil fuel biomass replaces. These are the negative values in the chart below. Harvest residue refers to the debris from production of traditional wood products such as branches, tree tops and bark. However, almost all other scenarios we looked at involving the use of salvaged dead trees or live trees, and those in which biomass was used to generate electricity instead of heat, resulted in net carbon costs instead by year 50 (i.e., a net increase in atmospheric CO2 after switching from fossil fuels to forest biomass). Strikingly, even when comparing forest biomass to coal, salvaged and green tree scenarios still generally produced cumulative net carbon costs by year 50.
Source: Natural Resources Canada, Laganiere et al, JPMAM, 2017. Percentages = electricity conversion efficiency for biomass, currently 25%; we also analyzed hypothetical improved 35% efficiency scenarios. Years for green trees = time required to reabsorb carbon emissions from initial combustion and foregone sequestration. Based on some very rough estimates, our sense is that around 80% of Canadian and US biomass used domestically is used to produce heat rather than electricity; and that around 80% of biomass feedstock is derived from harvest residue from construction, demolition and harvesting activities. If so, both regions would primarily be using harvest residue to create heat, which has the best net CO2 outcome. But these are rough estimates, we don’t know what fossil fuels they’re replacing, and in Europe, biomass is used more often for electricity. As a result, forest biomass projects shouldn’t qualify for preferences and subsidies available for wind, solar and hydro unless it can be demonstrated that their decarbonization benefits are both real and timely. If you want to understand more about this analysis, see the Supplementary Materials that begin on the next page; we walk through it all in more detail.
Heat v NatGas
Elec 25% v NatGas
Elec 35% v NatGas
Elec 35% v Coal
Heat v Coal
Heat v OilElec 25% v Coal
-12
-9
-6
-3
0
3
6
9
12
15
18
Cumulative net carbon cost (benefit) in year 50 from Canadian biomass use vs fossil fuels1,000 kg of CO2 per gigajoule of energy in year 50
Harvest Residue
net c
arbo
n co
stne
t car
bon
bene
fit
Heat v NatGas
Elec 25% v NatGas
Elec 35% v NatGas
Elec 35% v CoalHeat v Coal
Elec 25% v Coal
-12
-9
-6
-3
0
3
6
9
12
15
18
Salvaged dead trees
Heat v NatGas
Elec 25% v NatGas
Elec 35% v NatGas
Elec 35% v CoalHeat v Coal
Elec 25% v Coal
-12
-9
-6
-3
0
3
6
9
12
15
18
Green trees @ 45 yrs
Heat v NatGas
Elec 25% v NatGas
Elec 35% v NatGas
Elec 35% v CoalHeat v Coal
Elec 25% v Coal
-12
-9
-6
-3
0
3
6
9
12
15
18
Green trees @ 120 yrs
40
Biomass supplementary materials: understanding the analysis Each chart shows the cumulative net CO2 cost or benefit40 from annual use of forest biomass instead of a specified fossil fuel. Negative numbers are beneficial since they indicate a net reduction in CO2 from switching to biomass. Let’s start with the wrong way, which unfortunately some people use: the first chart ignores the carbon footprint of forest biomass (in this case, harvest residue), and assumes that CO2 benefits are equal to foregone emissions from gas or oil. The second chart does it the right way: by also including the carbon footprint from combustion of harvest residue itself. There are still net carbon benefits, but by year 100, they’re only 50%-70% of erroneously computed benefits from the first chart.
What about using salvaged dead trees or live trees instead of harvest residue? As shown below (left), a much different story. Even when using faster-growing Canadian trees (i.e., trees requiring 45 years to reabsorb carbon emissions from combustion plus foregone sequestration), there’s a net carbon cost to creating heat with biomass rather than using nat gas, even out to 100 years. Eventually, after a long enough period of time, bioenergy from sustainably-managed green trees would show net carbon benefits vs fossil fuels, due to replanting and reforestation. But how compelling are scenarios with net carbon costs out to 100 years or more given the current focus on 21st century decarbonization?
“Silviculture” refers to strategies that accelerate tree growth rates relative to a naturally-regenerated forest: site preparation, optimized tree spacing, vegetation control and selection of optimal species. If Canadian tree growth rates were increased through such operations, green tree biomass could generate net carbon benefits vs fossil fuels, although benefits would still occur after 50 years passed (2nd chart).
40 The Canadian Forestry models compute best case and worst case outcomes. In all of our charts, we plot the midpoint of the two outcomes.
-12
-10
-8
-6
-4
-2
0
2
0 10 20 30 40 50 60 70 80 90 100
1,00
0 kg
of C
O2
per G
J of
ene
rgy
Year
Harv residue � Heat v NatGas
Harv residue � Heat v Oil
Source: Natural Resources Canada, Laganiere et al., JPMAM. 2017
Net carbon benefit
Net carbon cost
What are the carbon benefits of forest biomass if you erroneously ignore its carbon footprint?
-12
-10
-8
-6
-4
-2
0
2
0 10 20 30 40 50 60 70 80 90 100
1,00
0 kg
of C
O2
per G
J of
ene
rgy
Year
Harv residue � Heat v NatGasHarv residue � Heat v Oil
Source: Natural Resources Canada, Laganiere et al., JPMAM. 2017.
Net carbon benefit
Net carbon cost
What are the benefits of using biomass harvest residue to create heat rather than oil and natural gas?
-4
-2
0
2
4
6
8
0 10 20 30 40 50 60 70 80 90 100
1,00
0 kg
of C
O2
per G
J of
ene
rgy
Year
Green trees 120y � Heat v NatGasGreen trees 75y � Heat v NatGasGreen trees 45y � Heat v NatGasSalvaged trees � Heat v NatGasHarv residue � Heat v NatGas
Source: Natural Resources Canada, Laganiere et al., JPMAM. 2017.
Net carbon benefitNet carbon cost
What happens when green and salvaged trees are used instead to create heat compared to natural gas?
-10
-8
-6
-4
-2
0
2
4
0 10 20 30 40 50 60 70 80 90 100
1,00
0 kg
of C
O2
per G
J of
ene
rgy
Year
Green trees 45y � Heat v NatGas
Green trees 30y � Heat v NatGas
Source: Natural Resources Canada, Laganiere et al., JPMAM. 2017.
Net carbon cost
Assessing the impact of silviculture operations: faster growing green trees
Net carbon benefit
41
Biomass looks even worse when used to create electricity, since biomass electricity conversion currently averages 25% efficiency41 vs 45% for natural gas. Harvest residue net benefits seen in the prior chart have turned into net costs, and salvaged tree/green tree scenarios showed net carbon costs that are 3x-5x higher than when used to create heat. There is nothing green about this first chart. What if biomass electricity conversion efficiency improved? We re-ran the electricity analysis using 35% instead of 25%. Harvest residue generated small net CO2 benefits, but still showed net costs to year 50 vs nat gas. All salvaged/green tree scenarios still showed net carbon costs to year 100.
In our analysis, we assumed the most favorable circumstances for Canadian biomass: biomass chips used in local markets with no transportation requirement, and where mean annual temperatures are 4 degrees C. We also analyzed the impact of lower temperatures that delay natural decomposition (worsening biomass CO2 scenarios); pellets instead of chips (more energy-intensive to create); and exports to Asia (more energy for transport). When we added all three factors into the analysis, the net CO2 results for biomass vs natural gas were modestly worse whether using harvest residue, salvaged trees or green trees as feedstocks42.
41 While biomass electricity conversion rates are low, biomass co-combustion with coal, and biomass use in combined heat and power plants, can improve efficiency rates closer to natural gas-powered electricity. 42 The Canadian Forestry Service analyzed 3 different forest biomass feedstocks for heat and power. Sawmill byproducts are also used by the biomass industry, which have more immediate GHG benefits. However, sawmill byproducts are limited in scope and have other applications. In the US and Canada, forest biomass accounts for only 1% - 2% of total primary energy. For that to increase, sawmill byproducts would probably be insufficient, which is why the Canadian Forestry Service analyzed other feedstock sources.
-5
0
5
10
15
20
25
30
0 10 20 30 40 50 60 70 80 90 100
1,00
0 kg
of C
O2
per G
J of
ene
rgy
Year
Green trees 120y � Elec v NatGasGreen trees 75y � Elec v NatGasGreen trees 45y � Elec v NatGasSalvaged trees � Elec v NatGasHarv residue � Elec v NatGas
Source: Natural Resources Canada, Laganiere et al., JPMAM. 2017
Net carbon cost
What happens when biomass feedstocks are used to create ELECTRICITY when compared to natural gas?
Net carbon benefit-5
0
5
10
15
20
25
30
0 10 20 30 40 50 60 70 80 90 1001,
000
kg o
f CO
2pe
r GJ
of e
nerg
yYear
Green trees 120y � Elec v NatGasGreen trees 75y � Elec v NatGasGreen trees 45y � Elec v NatGasSalvaged trees � Elec v NatGasHarv residue � Elec v NatGas
Source: Natural Resources Canada, Laganiere et al., JPMAM. 2017
Net carbon benefitNet carbon cost
What if biomass electricity conversion efficiency improved from 25% to 35%?
(2)
(1)
-
1
2
3
4
5
Harvest residue Salvaged trees Green trees
Local mkt, chips, 4 deg C
Export, pellets, 1 deg C
Impact: pellets, exports and lower temperatures1,000 kg of CO2 per GJ of energy in year 50
Source: Natural Resources Canada, Laganiere et al, JPMAM, 2017.
Net carbon cost
Net carbon benefitScenario: biomass used for heat instead of using natural gas
42
[14] The myth of carbon-free college campuses (2017)
Many US colleges aim to be “carbon-neutral”. The American College & University Presidents Climate Commitment (ACUPCC) was launched in 2007. So far 606 schools signed the commitment and 477 submitted plans to be carbon-neutral as soon as possible. To get a sense for what these plans are all about, let’s look at some common components:
• Heating buildings with biomass, sometimes with on-site biomass gasification plants • The purchase of renewable energy certificates and carbon offsets to offset campus carbon use • On-site installation of wind and solar power generation • Reduction of electricity consumption in buildings through more efficient HVAC systems, fluorescent
bulbs, adaptive/optimized thermostats, reduced stand-by electricity loads, etc The good news: insulation and energy-efficient materials have reduced energy used in commercial and residential buildings since 1980. Lower building energy consumption is mostly related to heating rather than electricity, since modern computers, servers and telecom equipment (and all the devices required to ventilate/cool them) consume a lot of power. But still…how can campuses achieve “carbon-neutrality” while the US and the world at large still use fossil fuels to generate 80%+ of their primary energy? Is campus carbon-neutrality a template for the rest of us? Here’s a partial list of what’s missing from campus assessments of their carbon footprints: • Production of steel, cement and plastics needed to build and refurbish university buildings and other
infrastructure; highly dependent on fossil fuels, with no large-scale non-carbon alternative • Food consumed on college campuses, grown with heavy direct inputs of fossil fuels (for machinery) and
indirect inputs of coal and hydrocarbons (to produce ammonia for fertilizer), trucked across the country by diesel rigs and packaged in energy-intensive plastic materials
• Clothes students wear, most of which are produced in China (an economy which uses coal for 62% of its primary energy) and which is transported to the US via diesel-fueled container ships
• Cars, SUVs and planes students use to travel back and forth to college, fueled by gasoline/kerosene So, if we’re just tracking the energy used by students and faculty once they arrive on campus, live in pre-existing buildings, after they’re fed and clothed, and all they need is lights and HVAC, that carbon footprint can be small and reduced further through insulation and efficient building materials. Campus carbon-neutrality efforts also help raise awareness of climate issues. But as a template for the rest of society, which has to generate large amounts of steel, cement, plastics and ammonia to produce structures and food, and distribute them throughout the economy, it doesn’t really mean that much. Around 20% of energy used around the world is related to production of steel, cement, ammonia and plastics. If so, until there are mass-scale alternatives to fossil fuels for creating materials upon which modern society is based, we will live in a fossil fuel world.
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
1950 1960 1970 1980 1990 2000 2010Source: USGS, PlasticsEurope, CMS, World Steel. 2015. Mt = metric tons
The 4 industrial pillars of modern society and their primary carbon-based inputs, Production index, 1950 = 100
Steel (metallurgicalcoke, natural gas)
2015: 1,600 Mt
Ammonia (methane)
2015: 146 Mt
Plastics (methane, naphtha and ethane)
2015: 330 MtCement (coal,
petroleum coke)2015: 4,100 Mt
43
[15] US hydropower: how much potential for expansion? (2016)
Hydropower is a reliable, cheap form of energy with little to no CO2 impact from ongoing operations. In some countries, hydropower represents 50%+ of total electricity generation: Iceland, Norway, Switzerland, Canada, Brazil, New Zealand, Colombia and Austria. In the US, however, hydroelectric power accounts for just 6% of generation, a lower share than in 1990. The US has plenty of rivers, but hydroelectric power is heavily reliant on topography: the mass of flowing water and the gradient of the river. Mountain rivers have good hydropower potential, while rivers like the Mississippi do not. In this section, we look at a realistic case: US hydropower could rise from 6% to 9% of total US electricity generation.
There are two primary kinds of hydropower, one based on storage and the other on diversion:
• Reservoir impoundment dams create a reservoir of stored water. The water flows through a channel
(called a penstock) and spins a turbine, which in turn powers a generator. The penstock inlet is normally as high as the lowest likely water level in order to maximize the height of the water flow (“generating head”). The amount of energy a dam can create is the product of the mass of water flowing through the turbine, the generating head and a gravitational constant.
• Run-of-river facilities divert a river from its natural course into a channel. The water in the channel flows past a turbine, powers a generator and is then returned back into the river.
Could the US increase its hydropower footprint? The National Hydropower Asset Assessment Program at Oak Ridge National Laboratory (ORNL) examined the potential for US hydroelectric power. They looked separately at existing non-powered dams and at new stream development. The potential from existing non-powered dams. ORNL looked at over 50,000 non-powered dams and assessed their potential for electricity generation based on head-heights, average annual flow, seasonal weather patterns and run-off. ORNL assumed 85% efficiency (the % of potential energy converted into electricity), and excluded dams that were too low and streams with minimal flow. It’s a work in progress with a few assessments for Ohio, West Virginia and Kentucky still pending, but most of the work is done. ORNL estimates that the US could build another 5.6 GW of hydropower on existing non-powered dams, generating 32 TWh of electricity annually. This would help the US renewable energy transition, but only on the margin, representing just 1% of total US electricity generation in 2015 (4,071 TWh). The linked map shows where these sites are located, superimposed on maps of US wind speeds and solar irradiance. For the most part, non-powered dam sites are located in areas without the best wind and solar resources, which could help such states meet higher renewable energy targets.
0%10%20%30%40%50%60%70%80%90%
100%
'90 '92 '94 '96 '98 '00 '02 '04 '06 '08 '10 '12 '14
Source: Energy Information Administration. December 2015.
Continental US electricity generation by source% of total generation
Hydroelectric
Natural gas
Nuclear
Coal
Oil
Biomass/other
Wind/solar
Source: Xeneca Power Development Inc.
How a reservoir impoundment dam works
Headgate
Dam
PenstockGenerator
Turbine
Transformer
Electricity
Water intake
44
The potential from new stream development. ORNL scanned for suitable streams and rivers on which dams have not yet been constructed. This is a more complex process, involving physical, environmental and political obstacles that existing dam projects have already dealt with. ORNL used the flood high water mark from the last 100 years as a measure of the potential head height (by definition, a best-of-all-possible-worlds assumption) when estimating reservoir height and volume. ORNL excluded national parks, scenic rivers and wilderness areas; rivers with insufficient water flow; and areas with project incompatibility issues, environmental concerns or existing hydropower facilities. Their results: 61 GW of new potential hydropower, capable of generating 315 TWh of electricity annually. The linked map shows where ORNL sees the greatest potential for new stream development; sites are generally concentrated in mountainous regions. The chart below combines ORNL estimates for existing non-powered dams and new streams. In ORNL’s theoretical case, hydropower could increase from 6% of US electricity generation to 15%. However, ORNL conducted their assessment of more than 3 million undeveloped streams at a “reconnaissance level” which does not incorporate all issues arising from environmental impacts, local politics or cost. They see their paper as a rough road map for future study. As a result, we added a second scenario in which new stream development is 30% of ORNL’s estimate, and in which non-powered existing dam development is 75%. If so, hydropower would rise from 6% to 9% of US electricity generation43. This would be a welcome addition, but wind and solar would still represent the bulk of the US renewable effort.
The last table shows a cross-country comparison of current and potential hydroelectric generation from the World Energy Council and International Hydropower Association. Like the ORNL analysis, the potential amounts should be considered upper bounds given environmental, cost and local issues involved. The US is at the low end of the range; the comparison sends a similar signal to ORNL with respect to the modest incremental potential for US hydropower.
43 Separately, Idaho National Laboratory generated “theoretical” and “realistic” US hydroelectric power scenarios. The two scenarios cite a doubling in generation and an increase of 50%+, respectively, which are similar to the two projections shown in the chart above.
Existing hydro Existing hydro Existing hydro
New stream development
New stream development
0%
2%
4%
6%
8%
10%
12%
14%
16%
Current (Dec. 2015) Theoretical 75% NPD, 30% NSD& Current
Source: EIA, ORNL, JPMAM. April 2014.
Hydroelectric power: current vs. potential generationShare of continental US electricity generation
Non-powered dams
Non-powered dams
Current and potential electricity share from hydropower
Country Current Potential Country Current Potential Country Current Potential
China 19% 50% Mexico 10% 21% Ukraine 4% 14%
U.S. 6% 15% Italy 16% 33% Nether. 0% 0%
India 10% 43% Spain 10% 23% Venez. 60% >100%
Russia 16% 96% Australia 5% 17% Vietnam 39% >100%
Canada 61% >100% Turkey 26% 80% Belgium 0% 0%
Germany 3% 6% Thailand 2% 11% Kazakh. 9% 41%
Brazil 62% >100% S. Africa 0% 2% Sweden 44% 97%
France 9% 22% Poland 1% 5% Uzbek. 19% 45%
Indo. 7% 24% Argent. 29% 81% Norway 95% >100%Source: World Energy Council, International Hydropow er Association, BP. Countries selected represent largest overall energy consuming countries in 2015 for w hom the WEC projected hydropow er potential, sorted by 2015 consumption. Potential includes current generation.
45
[16] Nuclear power: skyrocketing costs in the developed world (2014 and 2015)
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 appeal of nuclear power: capacity factors [see box on page 10] of 80%-95% for US nuclear vs. 55-70% for coal44 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.
44 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 CO2, 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.
0%2%4%6%8%
10%12%14%16%18%20%
1971 1975 1979 1983 1987 1991 1995 1999 2003 2007 2011
Source: 2014 OECD Factbook. Data through 2011.
The rise, plateau and fall of nuclear energy's share of global electricity generation, percent of total generation
0
5
10
15
20
25
30
35
China Russia South Korea USA IndiaSource: World Nuclear Association. June 2014. Under construction: f irst concrete for reactor poured, or major refurbishment of a plant under way.
Asia leads the way in nuclear plant capacity currently under construction, Gigawatts of capacity
0
100
200
300
400
500
600
700
800
900
1965 1973 1981 1989 1997 2005 2013
Source: BP Statistical Review of World Energy. 2013.
World's biggest nuclear electricity generating countriesTerawatt-hours of nuclear electricity generation
US
Rus, Kor, Chi, Can, Ger
France
Japan
0%10%20%30%40%50%60%70%80%
Fran
ceB
elgi
umS
lova
kia
Hun
gary
Ukr
aine
Sw
eden
Sw
itzer
land
Cze
ch R
epS
love
nia
Finl
and
Bul
garia
Arm
enia
S. K
orea
Rom
ania
Spa
inU
SA
Taiw
an UK
Rus
sia
Can
ada
Ger
man
yC
hina
Indi
a
Source: World Nuclear Association. June 2014
Share of electricity generation from nuclear energy Nuclear generation as a % of total electricity generation, 2013
Increase after construction of 33 GW
of new capacity
46
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%.
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.
$0
$20
$40
$60
$80
$100
$120
$140
Nuclear WindSource: N. Boccard, "The cost of nuclear electricity: France after Fukushima",Energy Policy Journal, December 2013.
In France, nuclear looks more expensive than windUSD per MWh, levelized cost
$0
$20
$40
$60
$80
$100
$120
$140
Original Historical Cost (2000)
Updated Historical Cost (2012)
Current cost of new build
InsuranceDevelopmentBack-endFuelO&MCapital and Financing
Source: N. Boccard, "The cost of nuclear electricity: France after Fukushima", Energy Policy Journal, December 2013.
$131
The rising cost of nuclear power in FranceLevelized cost measured in 2010 $/MWh
$91
$35
47
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.
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.
$0
$20
$40
$60
$80
$100
$120
$140
Nuclear (PJM)
Nuclear (Lazard)
Nuclear (EIA)
Wind (Lazard)
Wind (EIA)
Nat Gas (Lazard)
Nat Gas (EIA)
Nuclear all-in costs are high in the US as wellUSD per MWh, levelized cost
Source: PJM, EIA, Lazard (as of 2014). Subsidies not included.
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.
48
Appendix: Nuclear power cost and future technology alternatives
Carnegie Mellon surveyed 16 nuclear industry participants regarding capital costs of large nuclear plants using existing technology, and of prototype small modular reactors. Note how wide the range of estimates is in the first chart; and these are just median estimates (the full range of the high and low estimates was even wider). These cost projections reflect the technology, regulatory, legal, environmental and political framework in which nuclear power is developed in the Southeastern United States. In other words, they are not a universal measure of nuclear power costs, since many of these items differ by jurisdiction. As explained earlier, nuclear power costs are 25%-30% lower in Asia.
Our FutCost1 estimate is meant to reflect possible cost increases in cost based on safety, spent fuel and containment issues raised by the accident in Fukushima. Our FutCost2 reflects decreases in cost due to possible standardization and streamlining of existing technology (along the lines of Asian costs), and/or an optimistic assessment of small modular reactors of the future (see below).
The future of nuclear power. The list of those who see nuclear power as a critical component of future grids is a long one. It includes the Clean Air Task Force, International Energy Agency, the Breakthrough Institute, climatologist/activist James Hansen of Columbia University, David Mackay of Cambridge, Robert Hargraves from Dartmouth, Ralph Moir from Lawrence Livermore National Laboratory, British environmentalist Mark Lynas, etc.). The industry itself is scrambling to find a better and cheaper way forward; the box shows nuclear technologies under development. But even if an economic and acceptable alternative emerges soon, how fast it could be scaled up to become more than a marginal contributor?
There’s enthusiasm in some circles for small modular reactors (SMRs). The idea: smaller design (10 MW to 100 MW capacity), factory-produced with higher levels of quality control, shipped to site by rail or barge. More than 20 companies are developing SMRs worldwide, with 3 in the US focused on “light water” SMRs. The problem: smaller units tend to have lower economies of scale, so it is not a foregone conclusion that SMRs would be cheaper than today’s plants. The same National Academy of Sciences paper cited earlier also looked at possible SMR costs; the low end of median projections for 45-225 MW SMRs ranged from $3,500 to $4,000 per kW, which is ~25% below EIA cost estimates for larger plants using current designs. To be clear however, the upper end of the median cost range was considerably higher, and even more tellingly, none of these units is under construction. It may be decades before we know just how much new nuclear power designs really cost.
$2,000
$3,000
$4,000
$5,000
$6,000
$7,000
$8,000
A B C D E F G H I J K L M N O P
16 nuclear experts interviewed by Carnegie Mellon
Source: EIA, Carnegie Mellon, JPMAM. 2015. Experts interviewed in 2013.
Median cost estimates of large nuclear plants in line with EIA estimates, Capital cost, USD per kW
Current EIA estimate
FutCost1 estimate
FutCost2 estimate
$2,000
$3,000
$4,000
$5,000
$6,000
$7,000
$8,000
A B C D E F G H I J K L M N O P
16 nuclear experts interviewed by Carnegie Mellon
Source: Carnegie Mellon, JPMAM. 2015. Experts interviewed in 2013.
Median cost estimates of small modular reactorsCapital cost, USD per kW
FutCost2 estimate
• molten salt reactors • fluoride salt-cooled high
temperature reactors • liquid metal-cooled fast reactors • high temperature gas reactors • pebble bed reactors • nuclear battery reactors • small modular reactors • thorium reactors • fusion reactors • floating offshore nuclear plant • super-critical CO2 reactors
49
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