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GLOBAL ENERGY OUTLOOK 2014
YEAR OF THE RFS
Post-RINsanity, where next?
THE REAL REVOLUTION
It’s not all about shale…
OPEC ANGST
Seismic shifts for the key producer group
THE PRICE DEBATE
After the 2008 spike, questions linger
PLUS: EUROPE’S REFINING MOMENT
BRAZIL’S SUBSALT PINCH
SHIFTING SHALE IN THE US
BIOFUELS BACKLASH, AND MORE…
December 2013
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insight
CONTENTS
4
YEAR OF THE RFS (AND THE LCFS)
A rollercoaster year for the RINs market leaves questions about
whether the assumptions US renewable fuels legislation is based on
have changed so much that it needs an overhaul. Meanwhile,
California’s experiment in fuel regulation is dividing opinion too.
10 THE REAL REVOLUTION
The massive expansion of shale oil and gas liquids in the US has
doused peak oil fever and apparently given a new lease of life to the
hydrocarbon economy. But it hasn’t brought the price of oil down.
Nor has the regulatory onslaught against high emission hydrocarbons
diminished. Substitution not shale is the real revolution.
38 OPEC ANGST
When Insight last looked at OPEC in late 2010, there wasn’t even
a hint of the wave of protests that would shortly begin its sweep
across the Arab world, unseating regimes that had been in power for
decades. Nor was the extent to which shale would revolutionize oil
production in the United States remotely apparent.
44 SHIFTING SHALE
The vast amount of oil and gas suddenly generated by the North
American shale revolution has driven a rapid change in the market,
not least in the way crude is transported around the continent.
49 MARGINAL SUCCESS
16 THE PRICE DEBATE
Concerns over transparency in oil markets have been stoked by high
prices, even though oil is the most tracked commodity in the world.
Efforts to manage markets can only interfere with the necessary
signals that prices transmit to both producers and consumers.
22 EUROPE’S REFINING MOMENT
After enjoying strong margins in the early part of the century,
Europe’s refining sector has wilted in the face of alternate fuels,
collapsing demand, engine efficiencies, overseas competition, health
and safety costs and, more recently, emissions legislation. Will a
review by Brussels offer any respite?
Capacity markets in the US, designed to spur investment in the
peakload capacity needed to keep the lights on, have so far achieved
their aim – but that doesn’t mean there aren’t plenty of people keen
to change them.
54 ... TILL THE WELL RUNS DRY
Rising energy demand is bringing with it an increase in water usage
at the same time as resources are dwindling in some areas – is
water scarcity a threat to the energy sector?
58 BIOFUELS BACKLASH
In the face of dwindling support from many former advocates, the
global biofuels sector has been shifting focus to second generation
biofuels that do not compete with food for their feedstocks. But the
outlook for first generation biofuels is not as bleak as it might appear.
28 SUBSALT PINCH
Brazil faces tough questions over the pace of its subsalt oil boom:
has it got the regulatory regime right; is state oil company Petrobras
up to the massive task at hand; what wider impact might OGX’s
spectacular fall from grace have?
33 ABBOTT’S CARBON GAMBIT
Internationally there is a clear momentum behind emissions trading
systems but Australia is going against the grain following the
election of Prime Minister Tony Abbott. If his new government
successfully repeals the Carbon Pricing Mechanism, the country will
become a test bed for alternatives to cap-and-trade systems in
other regions.
64 GRAYING AT THE EDGES
The upstream oil and gas industry’s technical innovations and
pioneering spirit have been pushing back the boundaries that once
seemed to place an upper limit on production, but it faces a potential
constraint of a very different kind – a shortage of the necessary skills
to keep the boom going.
84 PLATTS GLOBAL ENERGY AWARDS
Shale Takes Top Prize: a special section on this year’s
winners of Platts Global Energy Awards.
DECEMBER 2013
insight
iii
1
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December 2013
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insight
DECEMBER 2013
It’s something of a tradition, by which I probably mean cliché,
to start these editor’s notes with a quote about change, then muse
about how fast things are changing all around us. So this year, I said
to myself, let’s not have a quote, and let’s not talk about change.
But some things never change, so here’s a quote. “Death
and taxes are the only certain things,” Benjamin Franklin said.
To that can be added, in the modern world, regulations.
The word crops up often in this issue, typically not too far
away from phrases like “struggling under,” “burden of,” and
“crippling.” Everyone is wont to complain about regulations
placed upon them by government.
It’s generally accepted these days that markets provide
efficient solutions as far as they go, but they don’t deliver on
costs that are external to market factors, for example climate
change objectives, security of supply or even local air pollution
– without regulation.
The challenge is to find a regulatory path that achieves these
objectives without too many bad and unexpected economic
impacts. It’s a difficult balance to strike and sometimes it can go
wrong, as has been noted by many people, not least Karl Marx,
who wrote that “crack-brained meddling by the authorities in
its regulation may aggravate an existing crisis.”
So what of the other certainty, death? The energy industry lost
a true hero this year, and it would feel wrong not to acknowledge
him in this forum. That man is, of course, George Mitchell, the
pioneer of shale drilling, who passed away at the age of 93. The
revolution he started is still ripping up the old rulebook. In fact, it
may not be going too far to say that his pioneering work is partly
responsible for what could be era-defining shifts in the
geostrategic map of the world unfolding at the moment.
I’m referring to America’s shift of direction in the Middle
East, the logic of which is underpinned by its rapid swing
towards energy self-sufficiency. It’s too early to say exactly
where this will all lead, but the cards the US is holding in its
hand now look very different to just a couple of years ago.
Finally, it seems fitting to give the last word to Mr.
Mitchell, who had an interesting, perhaps somewhat
surprising attitude towards regulation of the shale drilling
industry in the US. “The administration is trying to tighten
up controls. I think it’s a good idea. They should have very
strict controls.” Why? “Because if they don’t do it right there
could be trouble.” Government also has to get it right though,
or there will be trouble ahead.
— Alisdair Bowles, Editor
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US FUELS
JOHN KINGSTON
Global Director of News
YEAR OF THE RFS
(AND THE LCFS)
A rollercoaster year for the RINs
market leaves questions about
whether the assumptions US
renewable fuels legislation is based
on have changed so much that
it needs an overhaul. Meanwhile,
California’s experiment in fuel
regulation is dividing opinion too.
When government regulations take hold,
measuring their success can take time.
But two key environmental measures
that are being introduced on a sloping
scale are providing indications on their
impact, in one case on a daily basis.
possession of which can be used by an
“obligated party” to meet the mandates
of the RFS. Similarly, LCFS credits can
be used by a refiner or importer to “buy
down” the carbon intensity of the fuels
they are putting into the state’s market.
The one with daily feedback is the
Renewable Fuel Standard, and as we
look back on the US fuels market in
2013, we might want to declare it the
year of the RFS. A conversation about
the state of gasoline or diesel trade
couldn’t go on for even 30 seconds
without the terms RFS, blendwall or
RINs popping up. For awhile back in
the spring and summer of 2013, the
price of those RINs was an indicator that
was signaling a major fail in the RFS.
The RINs market has generally been
more active and transparent than the
LCFS credit market, though the latter
is showing signs of increased activity.
For example, data released by the
California Air Resources board –
which administers the LCFS – showed
41 transactions of LCFS credits in the
second quarter of this year. For the
third quarter, the total was 66. And
those numbers are well above prior
years.
The second is the California Low
Carbon Fuel Standard, limited for now
to that one state, and still flying mostly
under the radar.
But it was the RINs market that soared
and plunged in 2013, raising significant
questions about whether the assumptions
behind the RFS legislation – passed in
2005 and then expanded in 2007 by the
US Congress and then-President George
W. Bush – have been so fundamentally
altered that the basic legislation, or at
least the implementation of it, needs to
be overhauled.
Both initiatives rely on a market for
credits to smooth out the rough spots. In
the case of the RFS, the credits are the
previously mentioned Renewable
Identification Numbers, RINs, the
4
insight
DECEMBER 2013
US FUELS
When that RFS was passed, the
assumption was that US gasoline
consumption would rise if not ad
infinitum – maybe there’d be some
breakthrough in hydrogen or battery
storage that would slow its growth –
then every year for a long time. So if
the government mandated a certain
number of gallons as part of the
ever-rising total, the mandate would
slide easily into that growth.
Courtesy: Getty Images
But that didn’t happen: EIA data showed
US finished gasoline consumption peaking
in July 2007 at 9.64 million b/d, dropping
to 8.8 million b/d in the corresponding
month of 2012, and rising only slightly to
9 million b/d in July 2013. (The recent
low point was 8.19 million b/d in January
2012, down almost 700,000 b/d from the
January 2007 figure.)
As this decline was occurring, a few voices
started predicting an ethanol train wreck.
The drop in outright consumption, they
predicted, would collide with two things:
the annual mandated rise in renewable
fuel usage, particularly ethanol, and the
fact that there was a widely-held
consensus that ethanol blends above 10%
in most cars would create engine
problems. (In fact, everybody agreed with
that, except one key interest group. More
on that later.) And, it was noted, when
that collision started to bite, you’d see it in
the price of RINs, which for most of their
history lingered near 1-2 cents per RIN,
possibly the dullest, most predictable
market in the world of petroleum.
It didn’t stay that way. As the refining
industry began 2013 and started looking
out to the future, it saw that the amount
of ethanol being used in US gasoline
consumption was getting close to the
10% level, begging the question: how
were they going to meet a rising outright
numerical mandate in a market of
declining volume while looking at a hard
stop percentage?
An immature market.
RINs is the answer to that question, and
as the accompanying chart shows, ethanol
RINs – known as D6 RINs – soared from
a few cents at the start of the year to Ź
DECEMBER 2013
insight
5
US FUELS
hit $1.02 per ethanol RIN in early March.
Then the market calmed to about 70
cents, roared back to peak at about $1.44
in early July, sunk back to another
stabilization near 70 cents and then began
a long slide which will probably mean that
while 2013 was the year of RFS and
RINs, 2014 definitely will not be.
Two things happened. First, in early August,
the Environmental Protection Agency, long
“
A government mandate that hasn’t evolved
with the market; an inability to easily generate new
supply; an immature market. That’s a formula for
huge volatility.
”
after it would normally be expected to do
so, finalized the 2013 mandates at a
previously announced preliminary level. It
also said it expected ethanol consumption to
be about 9.75% of gasoline consumption,
getting close to that 10% blendwall.
The EPA then said that blendwall would
probably be breached in 2014, given the
combination of mandates and
consumption, and that it would “use
flexibilities in the RFS statute to reduce
both the advanced biofuel and total
2013 RINS PRICES
160
140
renewable volumes” in setting the ’14
mandates.
Soon after that, a leaked document said
the EPA would set a mandate of 15.21
billion gallons of biofuels to be blended
in the US in 2014, down from 16.55
billion gallons in the 2013 mandate.
There would be changes in non-ethanol
biofuels as well, but most of the pressure
would be eased on ethanol.
Two-bit RINs
The leaked document was a big push in
sending RINs prices by late October
down to a level that Americans used to
describe as “two bits”: 25 cents. That
would mark a decline of more than 80%
from its July high, the sort of decline
that doesn’t seem all that odd when you
consider the various elements in this
market: a government mandate that
hasn’t evolved with the market; an
inability to easily generate new supply
(you can’t just make ethanol to create a
RIN – it has to be consumed to generate
one); an immature market. That’s a
formula for huge volatility.
Finally, the 2013 RINS bubble, if it was
that, came to a crashing end. In midNovember, the EPA finalized its 15.21
billion gallons rule, and what was
interesting is that the RINs market
dropped further; the prospect of easier
rules was not baked into the price already.
The first trading on RINs after the
announcement took levels down near 16
cents; they rebounded to about 20 cents
and for the 2013 ethanol RINs, stood at
about 22 cents on November 22.
120
100
80
60
40
20
0
Jan
Feb
Mar
Source: Platts
6
insight
DECEMBER 2013
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
In the background of all of this was a
debate, led by the Renewable Fuels
Association, the ethanol producers’ trade
US FUELS
group. It rejected the basic idea that
there’s a blendwall, noting that the EPA
had approved E15 use in cars of model
year 2001 and beyond. It also noted that
flex-fuel vehicles had the capability of
using E85, which is 85% ethanol.
The group also noted these things with a
full heap of conspiracy theories, charging
that the only reason that the limited use of
these fuels – which would help make the
blendwall obsolete – was that evil/greedy
oil companies didn’t like ethanol and were
working against its consumption by not
putting enough E85 and E15 pumps in
stores they didn’t own anyway. In essence,
they were being told to meet their
“responsibilities” to help the mandate be
reached through these “10-plus” ethanol
blends, ignoring the fact that such
“cooperation” was never seen as a required
part of the original plan for growing
ethanol consumption; a rising level of total
fuel use would take care of that.
California teethin’
The conspiracy theories have yet to hit
the California LCFS, probably because
it’s too early in the game. The goal there
is a 10% reduction in the carbon
intensity (CI) of the state’s fuel mix by
2020, with incremental increases in the
standard each year as 2020 approaches.
The LCFS is different from previous
fuels regulations in two key ways. First
of all, it is not requiring any “bad
things” to be taken out of the fuel, like
lead or sulfur. Those can be removed;
carbon can’t be.
Second, the LCFS does not have tight
mandates, e.g., you must use X amount of
a certain type of fuel. In fact, the standard
of reducing carbon intensity by 10%
applies to the entire state and is not on a
LCFS CREDITS
Q2 2013
Q1 2013
Q4 2012
Q3 2012
Q2 2012
Q1 2012
Credits generated
Deficits generated
802
560
430
390
310
340
617
550
250
250
240
230
Source: Platts
refinery-by-refinery basis. That raises the
free-rider possibility that some importer
or refiner might just choose to skate by,
and allow its brethren to cut their carbon
emissions. But when asked about this
anomaly, CARB officials repeatedly have
said that they have specific information
on those parties, and can find ways to try
to modify those carbon hogs’ behavior.
In the same way that the RINs price is a
barometer of the industry’s present
ability to meet standards, there are some
LCFS numbers that send signals also,
though not as frequently as the daily
occurrence of RINs assessments. Several
months after each quarter, CARB
releases a document that has several key
numbers. One is the number of LCFS
credits generated during the quarter, as
well as the deficits.
That number, through the second
quarter of this year (the most recent data
available at this publication’s deadline),
had been running solidly in favor of
credit generation. That’s what is
supposed to happen; one report, by ICF
International, said credit generation
would exceed deficit generation into
2016-2017, and then the surplus could
be drawn down to help make the target.
So at the end of the second quarter,
CARB reported that there was a Ź
DECEMBER 2013
insight
7
US FUELS
net surplus of 1.64 million metric tons of
credits. In the first quarter, credit/deficit
generation was virtually flat; that’s a lot
sooner than the 2016-2017 timeline laid
out by ICF. CARB officials queried about
it said … don’t worry. The rules were
tighter at the start of 2013, and it took
some time to adjust.
“
In the same way that the RINs price is a
barometer of the industry’s present ability to meet
standards, there are some LCFS numbers that send
signals also.
”
And in the second quarter, the data
made them look prescient. There was
significant credit generation in excess of
deficit creation, which basically meant
that the crude inputs into refineries,
combined with the use of various
low-carbon fuels – like less carbonintensive ethanol – was feeding a larger
portion of California petroleum
demand than that from higher carbon
intensity sources.
It can show up in different ways. Some
of it was obvious: a company called
Clean Energy announced a plan that
would put low-carbon natural gas from
landfills into vehicles, an action it
conceded was driven in part by a
substantial number of LCFS credits
generated by that activity.
Others are less obvious. For example,
when a major refiner in the state was
said to be backing out Alaskan North
Slope crude in favor of Brazilian crude
– which carries a lower CI rating than
the Alaskan oil – was that LCFSdriven? Brazilian oil is not a rare
commodity in California, according to
8
insight
DECEMBER 2013
EIA data, but the clear substitution of
one for another could be one of the
small steps that the state hopes it will
incentivize not just through its
regulatory power, but by LCFS credit
prices that companies want to be able
to get their hands on.
This may all sound benign, but it isn’t to
the state’s oil industry. Catherine
Reheis-Boyd, president of the Western
States Petroleum Association, which
represents both upstream and
downstream players in California, wrote
a blog piece in which she likened the
LCFS to the final scene of Thelma and
Louise, with the Geena Davis and Susan
Sarandon characters driving their car off
a cliff.
But the plans of the state’s two biggest
refiners show a sharp difference in the
outlook for the future. Valero, in October
2012, was reported to be shopping its
refineries in California: Benecia, near San
Francisco, and Wilmington, near Los
Angeles. The state’s regulatory structure
– presumably including the LCFS, but
not exclusively – was said to be a key
reason for looking to exit the state,
though Valero has not confirmed any sale
attempts. (But its CEO, William Klesse,
has described California as a “tough place
to do business.”)
Meanwhile, Tesoro in June closed on the
purchase of BP’s Carson refinery, also
near Los Angeles, with the refinery (net
of working capital and inventory) valued
at a little more than $1 billion. If the
people at Tesoro, which has been
operating in California a long time,
agree with the characterization of the
LCFS as driving off a cliff, buying a
refinery for a billion dollars is a strange
way of showing it. Ŷ
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HYDROCARBON ECONOMY
ROSS MCCRACKEN
Editor,
Platts Energy Economist
THE REAL
REVOLUTION
The massive expansion of shale
oil and gas liquids in the US has
doused peak oil fever and apparently
given a new lease of life to the
hydrocarbon economy. But it hasn’t
brought the price of oil down.
Nor has the regulatory onslaught
against high emission hydrocarbons
diminished. Substitution not shale is
the real revolution.
Tesla, the US electric car maker, announced
over the summer that it had achieved
record sales of 5,150 Model S vehicles in
North America in the second quarter and
that it was on track to achieve a gross
margin of 25% in the fourth, excluding
zero emission vehicle credits. The company
reported almost $750 million in cash and,
notably, no government debt. It also
opened this summer its new European
assembly plant at Tilberg in the
Netherlands, having rolled out a substantial
supercharging network in Norway.
Tesla’s share price has rocketed as a result,
hitting a peak of $193 in late September,
nearly five times its level in April, when it
announced impressive first-quarter
results. Despite its small production run,
the company momentarily achieved an
eye watering $20 billion market
capitalization. To put that in context,
GM Motors, whose dealers delivered
more than 275,000 units in August alone
in the US, had an early September
market cap of about $50 billion.
Forecasts for the penetration of plug-in
electric vehicles have so far proven
over-optimistic, and Tesla released
disappointing earnings results for the third
quarter. Its market cap had dropped to
just below $15 billion in mid-November,
hit also by the potential ramifications of a
National Highway Traffic Administration
investigation into the safety of its cars.
Nevertheless, the company’s latest earnings
report did show revenues up eight-fold,
even if costs proved higher than expected.
Courtesy: Getty Images
10
insight
DECEMBER 2013
Tesla’s performance suggests that in fits
and starts the electric car sector may be
moving beyond the initial phase of the
hype cycle that dogs new technologies, in
HYDROCARBON ECONOMY
which expectations run far ahead of the
capacity to meet them. Instead, the sector
is slowly gaining a base in manufacturing,
servicing and recharging infrastructure,
which is sufficient to attract new capital,
allowing movement down the cost curve.
The scene is being set for future, possibly
exponential, growth.
Shale shadow
Such enthusiasm for the maker of
expensive luxury electric cars may seem
strange in a country where cleantech
investment has been overshadowed to
some extent by the lack of federal climate
change legislation and a revolution in
domestic oil and gas output. More widely,
huge reserves growth in unconventional
resources would appear to have put paid
to concerns over peak oil and US import
dependencies.
The US’s hydrocarbon economy now
appears “sustainable” – at least beyond the
time horizons of the current generation.
Importantly, exposure to global oil and gas
supply chains is supposedly no longer part of
the price of America’s petroleum addiction.
However, the unconventional oil and gas
boom has not diminished the threat of
climate change, nor the regulatory impetus
for demand reduction and emissions
control measures. If anything, by dispelling
the idea that the hydrocarbon economy is
heading imminently towards the edge of a
supply precipice, it has raised
environmental concerns that hydrocarbons
will in fact be much harder to shake off, or
worse may gain a new lease on life. From a
climate change perspective, greater
availability of unconventional oil and gas is
a reason for greater activism.
There has indeed been a sea-change.
World proved oil reserves have seen large
“
The real sea-change has not been the end of
peak oil, nor the change in US security interests
abroad, but in the relative value of the different
hydrocarbons.
jumps in size in recent years rather than
incremental growth, driven not by
statistically suspect leaps in Middle
Eastern reserves, but by the inclusion of
unconventional resources elsewhere that
now appear economically recoverable.
”
In the US, this has delivered a welcome
discount to domestically-produced crude
as seen by the enduring differential
between US marker West Texas
Intermediate and international
benchmark Dated Brent. This has proved
a huge bonus to those US refiners
positioned to take advantage and helped
rejuvenate the US petrochemicals
industry.
However, critically, the North American
shale boom has not delivered for the
end-consumers of oil. International oil
prices remain historically high,
supported, as ever, by instability in the
Middle East. The price of gasoline in
the US has continued to climb,
reaching for all grades in the densely
populated East Coast an average of
$3.695/gallon in 2012, its highest ever
level on an annual basis.
Relative values
The cross-commodity impact of
unconventional oil and gas has been
much greater than its impact on the oil
market alone, and it is this impact that
may have the most far-reaching
consequences. The real sea-change has
not been the end of peak oil, nor the
change in US security interests
Ź
DECEMBER 2013
insight
11
HYDROCARBON ECONOMY
abroad, but in the relative value of the
different hydrocarbons.
Prices in the coal market have also
moderated, while oil has remained high.
In the US, low gas prices depressed the
demand for coal from the power sector
leading to the lowest level of coal
consumption in 17 years in 2012. With
demand growth for electricity low, new
capacity being added in the renewables
sector and a drop in feedstock prices for
thermal power generation, electricity
prices have been depressed. In fuel cost
terms, both electric cars and Natural Gas
Vehicles look like a good deal compared
with gasoline or diesel.
In the US market, the unconventional oil
and gas boom has delivered both low coal
and gas prices. The ratio of gas ($/
MMBtu) to oil prices ($/b) was 9.47 in
2006 and rose steadily to a huge 33.26 in
2012. The small recovery in US gas prices
in 2013 and a halt in oil’s rise had reduced
this ratio to about 27 as of mid-October,
but oil’s comparative price in relation to
gas is still much higher now than in the
past, in the US market at least.
US NATURAL GAS TO OIL RATIO ($/b DIVIDED BY $MMBtu)
35
Price outlook
This change in relative values is likely to
be sustained. The global coal market, like
oil, has seen a huge rise in investment
over the past decade, taking its part in
the commodity super cycle, but it now
appears to have over-reached itself, with
supply catching up with demand.
It does not suffer the same political risk
profile as oil in terms of the stability of
its major producers, nor the presence of
a cartel powerful enough to influence
global prices, nor, indeed, is it as large in
terms of the amount of internationallytraded coal volumes compared with the
amount of coal that is produced and
consumed domestically.
30
25
20
15
10
0
2006
2007
2008
2009
2010
2011
2012
2013*
There are concerns about future coal quality
and a rise in extraction costs, but these are
more localized than global. Coal’s challenge
is its emissions, both in terms of local and
global pollution, not its market structure or
supply. As a result, coal burn is likely to
continue to provide relatively low-cost
electricity to those countries that use it.
*Year-to-date
But it is clear that being cheap and
reliable is no longer enough. China is the
world’s largest producer and consumer of
coal, but even there the regulatory tide
has turned against coal. Dangerous levels
of air pollution have led to a change in
energy strategy as outlined in the
Chinese State Council’s Airborne
Pollution Prevention and Control Action
Plan 2013-2017, published in
September. New coal plant construction
has been banned in three key urban
regions and the government now wants
to reduce the proportion of coal in its
energy mix to less than 65% by 2017.
Source: Platts
US EAST COAST RETAIL GASOLINE PRICES, ALL GRADES, ALL FORMULATIONS
(ANNUAL AVERAGES)
$/gallon
4
3
2
1
0
1994
1997
Source: EIA
12
insight
DECEMBER 2013
2000
2003
2006
2009
2012
In the United States, the world’s second
largest market for coal, new proposed
HYDROCARBON ECONOMY
emissions and air quality regulations
appear so stringent that they would make
the construction of new coal plant
uneconomic. In addition, under any
economic scenario, the sizeable, aged tail
end of the US coal fleet is unprofitable
and slated for retirement. Both in Europe
and the US, coal for power generation is
caught in a process of long-term
structural decline, which is being
accelerated by emissions regulation.
TESLA SHARE PRICE, WEEKLY
$
200
150
100
50
0
07-Jan
04-Mar
29-Apr
24-Jun
19-Aug
14-Oct
14-Nov
Source: Nasdaq
The situation for gas is different and
more complex because the “global”
market for gas – represented by spot
LNG trade – remains small. Gas pricing
remains regional rather than global. This
highlights the fact that the benefits of the
North American shale boom have largely
been contained within the continent. The
advent of US LNG exports can be
expected to have some impact, but most
likely a modest one in the short term.
Moreover, the extension of shale gas
technology beyond North America has
been slow to produce results. Despite
early optimism, nowhere appears likely
in the short term to replicate the rise in
US oil and gas output to such an extent
that it might seriously challenge existing
import dependencies. But even if
unconventional gas does not result in US
style changes in domestic production, it
will act to moderate growth in imports.
At the same time, substantial increases in
global LNG production for export
should provide security for importing
countries looking to raise natural gas’
share of the domestic energy mix.
The oil market, by contrast, looks much
more problematic. The specter of peak oil
may have lost its menace, but that does
not reduce the challenges faced by an
industry with mature assets that has to
GLOBAL PROVED OIL AND GAS RESERVES
BILLION BARRELS
TRILLION CUBIC METERS
200
1800
Natural gas
Oil
1640
180
1480
160
1320
140
1160
120
100
1000
1996
2000
2004
2008
2012
Source: BP Statistical Review of World Energy, 2013
meet continued rises in demand. Even if
the extraction costs in some countries,
such as Iraq, and for some
unconventional liquids are low, compared
with current prices, they do not make up
a significant enough share of the market
to impact the marginal price.
Unlike coal or gas, the unique,
international structure of the oil market
leaves it vulnerable to supply shocks, the
price effects of which are felt worldwide.
High oil prices mobilize capital in support
of new production, but they also sustain
the investment conditions for substitution.
Other key segments of future output
growth – Canadian oil sands and
carbonate plays, Brazilian and West
African pre-salt, deep and ultra deepwater,
Venezuelan heavy oil, the Arctic and
Russian shale oil – are all at the high end
of the cost spectrum. All are expected to
be needed to meet future demand and
replace declines from maturing fields.
Linked processes
There are two major processes in train. A
shift in the current and future availability
of oil and gas, and the substitution of
hydrocarbons for low carbon sources of
energy. Both are supportive of oil
substitution because there is considerable
doubt that the increased availability of
economically recoverable oil Ź
DECEMBER 2013
insight
13
HYDROCARBON ECONOMY
reserves will deliver significantly lower oil
prices in the future. As a result,
alternative transport modes and fuels are
growing, as is distributed and renewable
electricity generation, even if the impact
in terms of oil demand for the moment
remains small.
The number of Natural Gas Vehicles
jumped from 500,000 to over 2 million
between 2004-2008 and is now around 3
million. Although the sector is in the grip
of a crisis, driven by gas shortages and the
government’s prioritization of natural gas
for power generation, Pakistan’s experience
“
High oil prices mobilize capital in support of
new production, but they also sustain the investment
conditions for low-carbon substitution.
Brazil’s use of ethanol in transport is
long-standing and although it has not
been replicated elsewhere, biofuels now
make up about 3-4% of global oil
demand. Other countries have adopted
Compressed Natural Gas as an
alternative fuel source.
Unusually for a developing economy,
Pakistan’s oil consumption was lower in
2012 than in 2009, despite averaging
GDP growth of about 3% a year during
the period. Part of the reason is the huge
growth in CNG use for transport, which
saw over 3,000 CNG filling stations built
between 1993-2013, with most growth
coming between 2005-2010.
”
remains an important model for developing
economies seeking alternatives to oil.
Encroachment on oil’s dominance of the
transport sector can also been seen in the
growing use of LNG in ships. Driven by
emissions control regulation, the number
of LNG-powered ships is rising as the
infrastructure for refueling spreads slowly
along the world’s major sea lanes.
Classification society DNV estimates that
under the right conditions by 2018-2020
some 35% of newbuild ships could be
powered by LNG.
Change in transport technologies and
major shifts in power generation mixes
NGV VEHICLES WORLDWIDE
MILLIONS
16
12
8
4
0
2001
2003
Source: NGV Global
14
insight
DECEMBER 2013
2005
2007
2009
2011
are generally measured in decades rather
than years. Disruptive technologies tend
to follow an S-curve, in which rates of
adoption are low in the early years as
delivery infrastructure is built out and
manufacturing costs reduced, allowing a
later, steeper acceleration in uptake. The
example used by the US Natural Gas
Vehicle industry is the displacement of
gasoline by diesel from the heavy duty
class 8 truck market in the US, a process
which took 40 years.
However, the potential for exponential
growth of new technologies has been
demonstrated in Germany, which now
has some 30 GW of solar PV installed.
If electric vehicles also expand, it would
represent a major shift in the delivery
and consumption of energy towards
electrification. Looking even further
forward, Germany has a number of pilot
projects based on power-to-gas, which
effectively uses existing gas
infrastructure as a storage and delivery
mechanism for excess electricity output,
intelligently combining the trends
towards electrification and the increased
use of gas.
CNG users in Pakistan, Tesla Model S
drivers in the United States, German
householders with PV panels and
Norwegian ship owners building
LNG-powered vessels may seem like a
disparate bunch, but they all have one
thing in common; they are early
adopters. At some point, and again the
measurement is likely to be decadal, the
oil industry may have to confront the
possibility that even if it has the
capacity to cope with the supply-side
issues that dominate pricing in the
international market, it is the slow-burn
demand-side revolution that proves
their real undoing. Ŷ
OPINION
JORGE MONTEPEQUE
Global Director of Markets
$DEBATE
THE
Concerns over transparency in oil
markets have been stoked by high
prices, even though oil is the most
tracked commodity in the world.
Efforts to manage markets can
only interfere with the necessary
signals that prices transmit to both
producers and consumers.
PRICE
The 2008 oil price spike, which was
accompanied by similarly sharp price
rises for coal, iron ore, food and many
other commodities, sparked a debate
which still resonates five years later.
Countless articles, commentaries,
analyses, conferences and all sorts of
learned discourse have chewed over
whether the market was working well
and providing the right price signals or
just plainly dysfunctional or, worse yet,
willfully distorted.
That debate can essentially be summed
up in three key questions: Was the price
rise really “real”? What, or who, was
behind the spike? What can, or should,
be done about it?
In some cases, solutions – increased
regulation and oversight – were being
devised even though the nature of the
problem, such as it may be, was not fully
understood.
The issue
Prices for Dated Brent, the global
bellwether for crude oils, reached a peak
of over $145/barrel in June 2008, then
tumbled all the way down to nearly
16
insight
DECEMBER 2013
$35/b in the same year as markets
corrected in the aftermath of the
Lehman Brothers collapse in midSeptember that year and a confluence of
negative macroeconomic events, to
which sky-high commodity prices were a
major contributory factor.
The surge to an all-time high crude price
and the ensuing volatility shocked
consumers, producers and governments.
But the spike, the correction and the
recent tenuous price stability at around
the $100/b mark are all signs not of a
dysfunctional market, but of market
forces at work delivering messages –
some of which affected parties may not
want to hear.
Price is a function of supply and
demand and provides the signals to
invest in production, or not, as the case
may be. Above all, price modifies
behavior. However, some of the signals
can be very painful – to both consumers
and producers. It is therefore
understandable that people should look
for ways to dampen volatility, trying to
find a “price” that is simultaneously
comfortable for buyers and sellers. But
OIL PRICES
when measures are put in place that
distort the free-market price signal,
incongruence occurs and the necessary
investment or adaptation by consumers
and producers will not occur.
Experiments to manage price are as old
as history, with examples of price
controls from Roman times. In the
current era, there are plenty of cases of
countries trying to shield their final
consumers from market prices and
suffering runaway budgets and/or retail
shortages as a result, like the US in the
1970s when it tried to control the price
of gasoline and other products, or India
in recent years.
The precipitous rise to close to $150/b
caught everyone unawares; the likelihood
of prices rising above $100/b had seemed
remote before it actually happened. But
in retrospect, we can clearly see that
demand for oil was growing at a faster
pace than supply.
China and other emerging economies
were enjoying rapid growth fueled by a
low interest rate policy, underpinned
globally by the US Federal Reserve. And
economic growth needs energy, loads of
energy. Chinese oil demand jumped
nearly 50% from 4.8 million b/d in
2000 to 7.5 million b/d by 2007,
according to the US Energy Information
Administration, accounting for close to a
third of the rise in global oil demand
from 76.8 million b/d to just under 86
million b/d over the period.
Dated Brent prices in 2000 were at
nearly $30/b but by 2007 had jumped to
nearly $75/b, reflecting those demand
pressures. At first glance it may seem
counterintuitive that prices would
double if demand had not risen by a
WHEAT FRONT MONTH FUTURES
1200
1000
800
600
400
200
2004
2005
2005
2007
2008
2009
2010
2011
2012
2013
Source: FT
similar amount. However, in any market
with low spare capacity, a relatively small
change in demand can trigger a
disproportionate change in price to
ensure that production plus changes in
inventories equal demand. Caution: the
opposite is also true.
While the reason for the price rise –
sharp increases in demand – appears
obvious in retrospect, the debate
continues. In a panel discussion at the
World Energy Congress conference in
South Korea this year, one pricing expert
opined that markets had been
dysfunctional in 2008 and that the
$147/b price did not reflect the true
market.
But it is worth noting that similar if
not higher prices were observed the
world over, in the US, Canada, Africa,
Europe, the Middle East and Asia. The
high price was global and detected by
price reporting agencies and exchanges.
And similar price developments were
also evident in other commodity
markets from grains to metal ores as
China and other emerging
Ź
DECEMBER 2013
insight
17
OIL PRICES
The contraction
economies consumed ever greater
amounts.
Prices needed to rise almost across the
board to send the signals that would
ensure supply met demand without
shortages or surpluses. A dispassionate
assessment, which has thankfully become
more common, leads to the conclusion
that markets were working, and the
result of the higher prices was a thinning
of the herd of buyers.
4-WEEK AVERAGE US GASOLINE DEMAND
MILLION BARRELS/DAY
10.0
The price reversal in late 2008 turned
into a stampede, with a thinner herd
galloping the other way. Prior to this
period, energy was considered to have a
low price elasticity, that is to say that
consumers’ buying patterns would not be
modified greatly by increases in prices.
But the behavior of consumers in the US,
where changes in the wholesale price of
gasoline were transmitted almost
instantaneously and fully to the end
consumer due to relatively low gasoline
taxation around this time, explodes that
theory. Demand started to contract as
high prices bit.
9.5
9.0
8.5
8.0
7.5
7.0
6.5
6.0
Mar-91
Mar-93
Mar-95
Mar-98
Mar-99
Mar-01 Mar-03
Mar-05
Mar-07
Mar-09
Mar-11
Mar-13
Source: EIA
The retreat was fast and furious starting
in early July 2008, with prices
descending to $35/b by the end of the
year. A rapid output cut by OPEC,
monetary easing and sociopolitical
upheavals such as the Arab Spring and
other instability in the Middle East
subsequently moved prices back up to
the $100 mark, with occasional jumps
towards $120/b. But the main point had
been demonstrated: prices can move
violently both ways, not just up but also
down, as producers and consumers
respond to market forces.
DATED BRENT
150
130
110
90
70
50
30
Jan-07
Nov-07
Sep-08
insight
Jul-09
May-10
Mar-11
Jan-12
Nov-12
Sep-13
Perhaps it is worth noting that China
also had a downward demand correction
Source: Platts
18
US gasoline demand peaked in the
summer of 2007 at 9.6 million b/d
having historically followed a near ruler
straight line of year-on-year increases.
But then consumers began voting with
their feet, figuratively speaking, and a
process began where medium to small
size vehicles started to see their market
share grow. And again, a relatively small
change in demand had a
disproportionately large impact on prices.
DECEMBER 2013
OIL PRICES
in 2008, but the trend of oil demand in
the world’s second largest economy has
continued to move up with China now
being the largest importer of waterborne
oil in the world.
CHINA’S APPARENT CRUDE OIL DEMAND
MILLION BARRELS/DAY
10.4
9.9
9.4
So far, we can conclude that the price
was, and continues to be real, with rather
prosaic forces behind the sharp moves
such as rising consumption in key
developing economies.
8.9
A disconnect emerges, though, between
the data showing what drove the price
up in the new millennium and various
measures debated to address the price
issue. Countless hours have been spent
trying to find more interesting reasons
than just mere supply-and-demand
forces being at play.
6.4
8.4
7.9
7.4
6.9
5.9
Jan-05
Nov-05
Sep-06
Jul-07
May-08
Mar-09
Jan-10
Nov-10
Sep-11
Jul-12
May-13
Source: Platts
US CRUDE OIL PRODUCTION
MILLION BARRELS/DAY
8
Concerns over transparency in oil
markets have grown even though oil is
the most tracked commodity in the
world, with numerous service providers
compiling and publishing information
covering production, inventories, ship
tracking, arbitrages, but most
importantly trade data on who bought
and who sold and at what price.
7
6
5
4
3
Jul-05
Jul-06
Jul-07
Jul-08
Jul-09
Jul-10
Jul-11
Jul-12
Jul-13
Source: EIA
Nonetheless, the lack of hard data
demonstrating malfunction in the market
has not stopped well intentioned proposals
and measures being put forward.
Meanwhile, the market continues to work.
High prices are not only supposed to
modify buyers’ behavior. Prices also
influence sellers’ behavior, their
investments and exploration and
production plans. Coincidental with
high prices, a new round of investments
financed by high prices took over in the
US with the advent of technology that
enabled the exploitation of shale reserves.
US crude production has increased by
more than 50% since 2008 to nearly 8
million b/d, the highest in over 25 years,
while oil imports have hit an 18-year low.
It is easy to conclude that the sharp
increase in production is a direct function
of recent high prices. The American
experience is remarkable: output in 2013
has been running at 17% year-on-year,
and in terms of total liquids production
the country is vying to become the largest
producer globally. It is churning out
roughly 7.8 million b/d of crude plus Ź
DECEMBER 2013
insight
19
OIL PRICES
nearly 2.5 million b/d in natural gas
liquids and over 800,000 b/d of biofuels.
Other geographical areas have not
benefited as much as the US from the
afterglow of the price boom for various
reasons. Either they do not have the
resources or the infrastructure to exploit
them, or they have high taxation regimes
“
has been depleting at the rate of about
7% per annum, while at the same time
the major construction of refineries in
Asia and Middle East points to more
refinery closures in Europe over the
coming years if current economic
conditions do not perk up. Europe’s
importance in the global oil market
could diminish due to a combination of
These changes point to a shift to greater
Middle East-Asian crude pricing prominence at the
expense of the traditional Western benchmarks.
that discourage investment or policies
halting shale development outright.
”
falling crude oil output and demand and
a trading environment being increasingly
burdened with regulatory exposure.
The ‘solutions’
While classical economists would look to
address prices through measures that
influence demand or supply, efforts on the
“soft” side of pricing continue. There are
various initiatives to improve transparency
and/or implement new procedural or data
recording processes. These proposed changes
or principles, though, do not add or subtract
one single barrel of oil supply or demand.
One area of concern in the wider
industry is the potential for unintended
consequences for the integrity of pricing
processes from these initiatives, all the
more so because the energy industry is
undergoing major fundamental changes.
We are seeing many inflection points – sharp
changes in direction – in the oil industry
currently. Not least among these is the US no
longer being the largest waterborne importer
of crude oil, ceding the top spot to China.
There is also the ongoing decline in
production from the North Sea, which
20
insight
DECEMBER 2013
These changes point to a shift to greater
Middle East-Asian crude pricing
prominence at the expense of the
traditional Western benchmarks, with a
likely growing reliance on the still young
Dubai benchmark – although some
expect Europe to become more businessfriendly if the slowdown or production
decline is too steep. As an emerging sign,
the UK is undergoing a deep review of
investment in the country and looking at
what needs to be changed to arrest the
production decline.
Nevertheless, Middle East and Asian
participants understandably question
their reliance on Western systems as the
structural weight of demand moves
east. There are signs of this emerging
already, with some evidence of
balkanization in Western markets as
non-US domiciled entities seek to trade
only with similarly incorporated entities
to avoid Dodd-Frank or any other
transnational issues.
But the core market concern is liquidity.
There are fears that growing requirements
from the trade will naturally raise costs
and cause players to exit the market or
shift their business to areas less burdened
by regulation. The declining liquidity in
the natural gas futures market is held up
by some as evidence of a retreat.
Liquidity is also declining in derivative
markets, with some noting a loss of
market depth that is leaving participants
with fewer counterparties to trade with.
Platts’ tracking of derivatives versus
physical markets trading reveals some
significant recent changes in the
composition of the market, with the
share of derivatives instruments shrinking
on a year to year basis. The share of
derivatives declined from 55% to 51%
on a year-to-year basis in the first 10
months of 2013.
Whether one believes that energy
markets are providing completely
unbiased price signals, few would
disagree that a free-market price provides
the correct triggers to influence demand
and supply. And this price message
should not be managed or guided, even if
the message is not welcomed.
After all, if there is a concern over high
prices, one should not forget the maxim
“There is nothing like high price to cure
high prices,” as seen in the downward
correction in US natural gas prices and the
emerging behavior in the US crude oil
market. High prices brought about
innovation and supply in those countries
open to energy development and if prices
were to fall by natural causes, such decline
will spur the seeds for more consumption,
bringing about another upward cycle. Ŷ
The views expressed in this article are those
of the author.
cpsenergy.com • facebook .com/cpsenergy • @cpsenergy
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DECEMBER 2013
insight
21
REFINING SECTOR
STUART ELLIOTT
Senior Managing Editor,
Europe & Africa Oil News
EUROPE’S
REFINING MOMENT
After enjoying strong margins in the
early part of the century, Europe’s
refining sector has wilted in the
face of alternate fuels, collapsing
demand, engine efficiencies,
overseas competition, health and
safety costs and, more recently,
emissions legislation. Will a review
by Brussels offer any respite?
The startup in September of the 400,000
b/d capacity Jubail refinery in Saudi Arabia
was good news for the Middle Eastern oil
giant and its ambition to become a major
exporter of high value oil products.
But it represents yet another significant
setback for Europe’s flailing refining
sector, already reeling from the effects of
falling demand since the global economic
crisis in 2008 and continued overcapacity.
Jubail – and other planned refineries in
the Middle East set to come online this
decade – could start sending a lot of
diesel Europe’s way, eroding the already
slim refining margins in the region.
Europe also faces competition from
refiners in the US looking for export
markets to cash in on the surplus of
cheap crude in the country and Russia,
which is midway through a major
refinery modernization program designed
to boost volumes of high-end products.
European refineries are closing all the
time – the latest being the 55,000 b/d
Mantova refinery in Italy – with more
expected to shut as margins stay low. The
warnings for Europe continue to come
22
insight
DECEMBER 2013
thick and fast from refiners, governments
and traders alike: they all agree that it is
difficult to see how European refining
can compete in a global industry when
demand is tight, newer plants are far
more complex and EU environmental
laws continue to threaten European
refineries’ profitability.
Total’s CFO Patrick de la Chevardiere in
late October said there was still a refining
overcapacity of 1.5 million b/d in
Europe. The European Commission
recognizes there is a problem. It is
carrying out what it almost fondly called
a “fitness check” of the industry –
ostensibly a study to find out what
Brussels can do to fix the sector that
looks increasingly broken. It plans to
report back in September next year.
This could be too late though. According
to the International Energy Agency, 15
refineries have shut between 2008 and
2013, and the EU’s combined refining
capacity has dropped by 8%. And that
could just be the start. Refiners in Italy
are struggling, the UK’s industry has
been decimated, and the French sector
remains under heavy pressure.
REFINING SECTOR
Keep an eye on Total. A partner at Jubail,
the French giant has often said European
refineries will have to fight to survive. It
vowed in 2010 not to shut any more
plants in France for five years following
the closure of its Dunkirk plant. But come
2015, it’s free to get started again. De la
Chevardiere in September assured that
Total would honor its pledge, but said
nothing about what it might do after that.
Courtesy: Shell
‘Real vulnerability’
One of the major issues facing the sector
is current and proposed European
legislation. Brussels over the summer
held its first refining forum to look at
how it would affect the sector and
another in late November.
BP’s regional vice president for Europe,
Peter Mather, said in April that the
Commission needed to review its
policies to help the sector survive its
current competitiveness crisis. The EU
refining sector has “a real vulnerability,”
caught in a global market between the
US with its low fuel costs and Asia with
its low labor costs, Mather said.
At the same time EU refiners are having
to invest to meet increasingly stringent
EU controls, for example on industrial
emissions, which is eroding already
narrow margins, he added.
EU refining trade body Europia estimates
that there is around $30 billion of
investment already announced for EU
refinery projects to 2020, but that another
$21 billion would be required to meet the
changes in demand and new specifications.
That $51 billion total equates very roughly
to $1/b on the refining margin in Europe,
which makes it “massively significant” as
the normal margin ranges from $0 to
$5/b, Mather said. “A lot of this
investment is just to stay in business –
there’s no obvious return,” he added.
Shell’s Pernis refinery, the biggest in Europe.
Industry group CONCAWE has warned
that refiners across Northwest Europe
could face a bill of up to Eur25 billion
($33 billion) just to meet requirements of
European Union legislation in the
coming years. The newly elected
president of CONCAWE, Michel
Benezit, estimates that costs could
amount to anywhere between Eur15
billion and Eur25 billion, “just to comply
with legislation, without any competitive
improvement in our operations.”
Speaking to Platts in September, Benezit
said that refiners in the EU “will have to
make choices, because it is such a huge
amount of money, it is going to be
difficult.” He noted that refiners in
Europe are under very heavy pressure
“because of decreasing demand as a result
of more energy efficient engines,” but he
also identified the diesel versus gasoline
imbalance, the burden of EU
Ź
DECEMBER 2013
insight
23
REFINING SECTOR
legislation and global competition as
other factors providing a substantial
challenge.
The uncertainty surrounding the precise
requirements of EU emissions and
sustainability legislation has had a
chilling effect, he said, with the lack of
clear direction making it difficult to raise
cash. “The current investment framework
does not always offer long-term
perspective given that this industry has
long investment cycles,” he said.
EUROPEAN REFINERY CLOSURES SINCE 2008
Refinery
Owner
Capacity (’000 b/d) Status
Period
“A coherent EU legislative framework
with clear and demonstrated benefits for
sustainability and competitiveness is
needed to create a clear investment
environment over time,” Benezit said. “It
is impossible to mobilize the capital
which is required without the clear
framework.”
“Some say that petroleum products are
available [to import] and that no [refining]
in Europe is better than [coping] with the
difficulties of our industry, which is said to
be a burden,” he said. “We do believe that
security of supply is important and that to
have in-house refining capacity helps
Western Europe to be safe and have a
healthier economy in the long term.”
Italy
Mantova
Gela
Rome
Falconara
Cremona
Porto Marghera
MOL
Eni
TotalErg
API
Tamoil
Eni
55
105
86
83
90
80
To close permanently
10 month closure
Permanent closure
6 month closure
Permanent closure
Permanent closure
January 2014
June 12-April 13
September 2012
January-June 2013
October 2011
Q3 2013
Petroplus
Petroplus
LyondellBasell
Total
162
85
105
140
Permanent closure
Permanent closure
Mothballed
Permanent closure
December 2012
November 2010
January 2012
September 2009
France
Petit Couronne
Reichstett
Berre l’Etang
Dunkirk
Germany
Harburg
Wilhelmshaven
Shell
Hestya Energy
110
260
Permanent closure
Permanent closure
April 2013
October 2009
Petroplus
Petroplus
220
117
Permanent closure
Permanent closure
July 2012
May 2009
70
Permanent closure
January 2012
UK
Coryton
Teesside
After enjoying strong refining margins in
the early part of the 21st century,
Europe’s refining sector has been beset by
a combination of challenges including
alternate fuels; collapsing demand; rising
engine efficiencies; fierce overseas
competition; sluggish investment; the
extensive burden of health and safety
worker conditions; and, more recently,
emissions legislation.
“If EU refiners want to remain key players
in the international market, they have to
become more competitive. This can be
achieved by improving our efficiency in
our operations through investment but,
again, the impact of EU legislation is
critical in this perspective,” Benezit said.
Romania
Arpechim
Petrom
Czech Republic
Paramo
Unipetrol
20
Rosneft
160
Permanent closure
May 2012
Indefinite closure
March 2012
Ukraine
Lisichansk
Source: Platts
24
insight
DECEMBER 2013
‘Killer regulation’
The Commission’s “fitness check” for the
sector will look at the quantitative and
qualitative impacts of relevant EU
legislation on costs and productivity. But
whether it can actually achieve anything
is open to question. It’s hard to see what
Brussels can do that wouldn’t undermine
REFINING SECTOR
other goals related to climate change and
environmental pollution.
The EU legislation includes the
industrial emissions directive, which
requires refineries to meet best available
technology benchmarks, and the fuel
quality directive, which sets targets for
cutting greenhouse gas emissions from
fuels. BP’s Mather said meeting the EU’s
draft best available technology
benchmarks alone could require $300
million invested in each EU refinery.
The refining sector is also impacted by EU
legislation on renewables, emissions trading,
strategic oil stocks, marine fuels, energy
efficiency, energy taxation and chemicals.
“We believe the European Commission
must look hard at what measures can be
revised or suspended,” said Mather. “This
is such a hard time for industry that we
need to press pause on some things as we
carry out the fitness check,” he added.
Mather said he would like to see this
pause particularly on the industrial
emissions and fuel quality directives.
Chris Hunt from the UK Petroleum
Industry Association told the Brussels
refining forum in April that if there is no
change in the timing of the “key bits of
killer regulation” in the industrial
emissions and fuel quality directives,
then the fitness check will be finished
too late to be of use. Inevitably, then,
more refineries will be forced to close.
Buyers wary
There is, of course, one alternative to
shutting refining capacity in Europe,
and that is selling it. But buyers have
not been exactly climbing over one
another for European assets when
they’ve come up for sale.
A good example is the bankruptcy of
independent refiner Petroplus in 2012
when suddenly five European refineries
appeared on the market. Interest was not
high for the plants, and those who did
show interest were not traditional
refiners. Only three were bought, all of
them by global trading houses.
Trader Vitol took the 105,000 b/d
Antwerp plant in Belgium and the small
68,000 b/d Cressier plant in
Switzerland, while rival Gunvor bought
the 100,000 b/d Ingolstadt refinery in
Germany. The others – the 162,000 b/d
Petit Couronne in France and the
220,000 b/d Coryton plant in the UK
– were shut. Petroplus had already
closed the 117,000 b/d plant in
Teesside, UK, and the 85,000 b/d plant
at Reichstett in France.
It’s unlikely traders want refineries to
make money as a stand-alone
operation. Gunvor, on its website, says:
“Refineries complement Gunvor’s
trading function, which can create
greater operational efficiency across the
supply chain. Gunvor is leveraging its
expertise and excellent relationships
with crude suppliers to gain access to
the types of crude oils processed at its
refineries.”
Vitol emphasizes its “global access to
crude and feedstock” which can provide
attractive crude input options. “The
products produced can be made
available to our product trading teams.
Vitol continues to look for
opportunities to work with crude oil
producers to access our owned refinery
system and with other refiners to
optimize their investment by accessing
the best possible crude oil and feedstock
alternatives.”
Ź
IMPORT DEPENDENCY IN THE UK
There were 18 refineries in the UK in the late
1970s – now there are only seven, the most
recent closure being the 220,000 b/d Coryton
refinery near London in early 2013.
At least two other plants have been up for
sale. The US’ Murphy Oil has been trying to
offload the 135,000 b/d Milford Haven
refinery for years, and Total only recently gave
up on finding a buyer for the 220,000 b/d
Lindsey refinery. The future of Scotland’s
210,000 b/d Grangemouth refinery was also
up in the air until operator Ineos unveiled a
survival plan in October that involved some
serious cost-cutting.
Others are trying different strategies. India’s
Essar, which bought the Stanlow plant in
2011 from Shell, has switched to using
“opportunity crudes” – oil from West Africa,
the Mediterranean and Canada, as well as
some Russian M-100 straight-run fuel oil –
instead of traditional North Sea crude. It
claims to have reaped a $1/barrel lift to its
refining margins in 2012, but it’s not exactly a
stellar performance.
Like the EU, the UK is carrying out a review of
the sector, due by the end of 2013. Junior
energy minister Michael Fallon said the review
would look at “the balance between importing
product and refining product [ourselves], in
terms of the obligations of stocking, the
difference in duty treatment, not the duty
itself, but the way the duty is applied, but also
the central question of how much refinery
capacity we need.”
The future looks decidedly bleak, however. A
recent study by IHS Purvin & Gertz
suggested that the UK faces further refinery
closures in the coming years as the industry
is forced to deal with “immense” costs.
From 2013 to 2030, UK refineries face an
additional GBP11.4 billion ($17.5 billion) in
capital and operating costs. The required
capex over the period is estimated at
GBP5.5 billion – most of which would not
generate any return on investment – to pay
for new emissions abatement equipment,
processing capacity, and storage
improvements, the report said.
continued over page...
DECEMBER 2013
insight
25
REFINING SECTOR
...continued from page 25
Additional operating costs are seen at GBP5.9
billion, reflecting the cost of running the new
equipment, plus a bill of around GBP 1 billion
for carbon allowances. Further costs would
also likely come from new processing capacity
needed to address a growing surplus of
gasoline and a deficit of middle distillates in
the UK. Yet-to-be-finalized EU directives on
the carbon intensity of fuels and energy
efficiency will add significant further costs.
“It would be highly likely that when faced with
such a large mandatory capital expenditure
requirement that provides no return on
investment, UK refiners could be forced to
close more refineries,” the report said.
On costs, Purvin & Gertz said that while UK
refineries are globally competitive, enjoying
average net cash margins of around $2.60/b,
long-term investment in diesel production
capacity is required. “To simply keep pace
with current demand trends, UK refineries
would need to invest some GBP1.5 to GBP2.3
billion over the next 20 years,” it said.
Based on an approach used by the International
Energy Agency, the UK is already at a high risk
level for supply of diesel and jet fuel, according
to the Purvin & Gertz report. Overall, the UK is
projected to have a total refined product cover
of 83%, a net deficit of 17%, which would put
the UK in the low risk category. However, it has
a jet fuel deficit of 55%, a diesel deficit of 47%
and a kerosene deficit of 44%. The southeast
of England is particularly at risk, with low supply
cover for all fuels, and no spare capacity in
import logistics to meet any future shortfall in
the event of supply disruptions. The southern
region is even short on gasoline, having an
import dependency of 60% and a jet fuel
import dependency of 91%.
insight
Russian companies have also been in the
market for refining assets in recent years.
Lukoil bought the 320,000 b/d ISAB
refinery in Sicily, and Rosneft bought a
stake in the 300,000 b/d Sarroch refinery
in Sardinia.
But that may well be it. Didier Casimiro,
Rosneft’s vice president of commerce and
logistics, said in September it would be
sticking with its existing assets in
Germany and Italy. “We are not, at this
moment, looking into further expansion
in this part of the world,” Casimiro said.
Casimiro also acknowledged that life for
independent refiners was likely to
become tougher in the current refining
climate because investment would be
harder to attract in the face of
increasingly integrated rivals.
“Standalone refining is likely to face even
greater pressure,” he warned.
This leaves some companies without a
traditional background in refining such
as Libya’s little-known Murzuq Oil,
which has made repeated bids for the
Petit Couronne plant. Created in 2011
and describing itself as a marketer of
refining products and provider of oil
facility securities, Murzuq Oil says it
Courtesy: MOL
26
Who else might be interested in a
European refinery? Sovereign
investment funds have certainly been
sniffing around. The Libyan Investment
Authority (LIA) was the French
government’s favored bidder for the
Petit Couronne refinery. This suggested
that producers from outside of the
region may look to take over refineries
as a way of gaining a foothold in
Europe. But that never materialized,
Tripoli saying it would not bid for Petit
Couronne after all.
DECEMBER 2013
has signed crude oil and gasoline supply
agreements with Libyan distributor Al
Mahari Oil Services and that the
Libyan government would take a 20%
stake in the Petit Couronne assets,
through the Commerce &
Development Bank of Libya.
The French government would be offered
a 5% capital stake through its public
investment bank BPI, as well as a seat on
the board. The offer includes the
construction of above-ground storage
facilities for butane and propane, as the
previously used underground storage
facilities are insufficient for the
company’s needs. Murzuq Oil has also
offered to re-employ all the site workers
who were made redundant, which
amounts to almost 500 workers,
reinstating their employment terms from
before the plant’s closure.
What’s the catch then? Well, it’s not the
first time Murzuq Oil has tried to buy
the plant – each time previously, the
French court tasked with deciding the
refinery’s fate has rejected its offers,
saying the bids “did not have the
financial and technical capacity to ensure
the restart of the plant.”
All in all, the future of European
refining looks bleak. When it’s cheaper
to import products from elsewhere in
the world than it is to refine products on
your own soil, there is clearly a major
problem. But it’s not just about
economics – if more European refineries
close, there are bound to be supply
security ramifications.
It remains to be seen what the EU’s fitness
check will reveal. The chances are it will not
make for especially comfortable reading for
anyone involved in the industry. Ŷ
BRAZILIAN UPSTREAM
ROBERT PERKINS
News Correspondent
SUBSALT
PINCH
Brazil faces tough questions over the
pace of its subsalt oil boom: has it
got the regulatory regime right; is
state oil company Petrobras up to
the massive task at hand; what wider
impact might OGX’s spectacular fall
from grace have?
A few years ago the swift transformation
of Brazil into a New World oil
powerhouse seemed all but assured. The
subsalt bonanza in Latin America’s
biggest economy heralded a new
promised land, full of boundless riches
set to propel the country and its lucky
upstream players to new heights.
Brazil is still set to become the unrivalled
leader in deepwater output over the
coming years, with its subsalt
developments accounting for almost
80% of the world’s overall 4.4 million
b/d growth in deepwater oil supplies by
Courtesy: EBX
28
insight
DECEMBER 2013
2035, according to the International
Energy Agency.
But a spate of project delays has certainly
taken the shine off initial hopes, with
state-controlled Petrobras trimming its
optimistic output targets, and more
recent developments raise the question
of whether those expectations were
overblown from the outset.
Some investors caught up in the hype
have already paid dearly as those who
banked, and then lost, billions over Eike
Batista’s failed OGX can already attest
(see box page 31). And in October,
Brazil was faced with the uneasy
question of why the biggest oil field
among its offshore giants didn’t attract
more interest in an auction.
The massive Libra field, which holds
8-12 billion barrels of recoverable oil,
attracted only one bid and deeppocketed players such as ExxonMobil,
BP and BG did not even bother to turn
up. Only 11 foreign companies signed
up to bid, far fewer than the 40 that
Brazil’s oil agency had originally
expected, and only four made up the
BRAZILIAN UPSTREAM
sole final offer. With no competing
bids, the government got the minimum
42% share of profit oil allowed for the
project.
The National Petroleum Agency (ANP)
claimed BP, for one, held fire due to
legal and financial uncertainties over its
ongoing US spill settlement battle in
the US courts. It seems likely though
that BP – like others – may have been
less keen to tie up capital in complex
projects without greater control of the
outcomes.
In the absence of generous terms,
players such as BP and ExxonMobil
prefer to create value on their own terms
through the drill-bit rather than take
minority stakes in pre-packaged assets.
With state-backed Petrobras as the
operator with strategic oversight for
Libra, it is not surprising that oil
companies had reservations about
political control of the project.
“
Brazil now has to vie for upstream investment
with new players on the global energy scene.
”
“Muted primary interest in Brazil’s first
subsalt round is triggering doubts that
the country’s below-ground potential
could be limited by associated aboveground risks,” UK-based Business
Monitor said in a recent report.
Libra, Brazil’s largest-ever discovery
(although the ANP said recently the
Franco field may be as big or even
bigger), was also the first deal under a
three-year-old legal framework which
gives the government via Petrobras the
central role in deciding how the $50
billion needed to develop the field is
spent. Under the regulatory framework,
Petrobras must be the operator and have
a minimum 30% stake in all projects in
the subsalt blocks, a floor it
Ź
BRAZILIAN OIL FIELDS
Exploration blocks
Golfinho
BRAZIL
Oil fields
Pre-salt region
Vitoria
Espirito Santo
Basin
Sao Paulo
Oil is stored in the pores
of the reservoir rock layers
in the pre-salt layer.
Rio de Janeiro
Marlim
Ocean
2km
Post-salt
1km
Salt
2km
Campos
Basin
Curitiha
Franco
Libra
Iara
Lula (Tupi)
Sapinhoa (Guara)
Florianopolis
Santos Basin
Pre-salt
Atlantic
Ocean
5-7km
below
surface
Source: Carrie Cockburn/The Globe and Mail, Petrobras, Wood Mackenzie, Graphics News
DECEMBER 2013
insight
29
BRAZILIAN UPSTREAM
surpassed at Libra after ending up with
40% of the project.
Now Petrobras’ 40% stake in the project
only adds to the burden of its own
financial commitments in the coming
years, to the tune of $3 billion upfront
and a further $6 billion for its share of
expected development costs. The
winning consortium, made up of
CNOOC, the China National
Petroleum Corporation, Total and Shell,
will need to operate up to 18 floating
production vessels to develop Libra,
whose output is expected to exceed 1
million b/d.
Creeping costs
Certainly the creeping costs of
developing large deepwater finds in
recent years have put players off. The
contract terms are also tough with the
government’s total take from the field,
including taxes, one of the highest in the
world at about 80%.
The IEA estimates that Brazil requires a
massive $1.34 trillion in cumulative
investment in the oil sector over the next
two decades, or $57 billion per year on
average. Including gas, the IEA sees the
requirement for upstream spending in
Brazil averaging $60 billion per year, on
par with Russian and higher than the
whole of the Middle East.
BRAZIL’S OIL PRODUCTION GROWTH
And now Brazil has to vie for upstream
investment with new players on the
global energy scene. Expensive
deepwater developments have fastgrowing competition from booming
shale oil plays, and the new rift plays of
West and East Africa may also have
diverted attention from Brazil’s prolific
offshore prize.
MILLION B/D
6
5
4
3
2
2012
2015
2020
2025
2030
2035
Source: IEA's Medium Term Oil Market Outlook and World Energy Outlook 2013
PETROBRAS GROSS DEBT
BILLION $
120
Net debt
Adjusted cash and cash equivalents
100
Indeed, it may be the global shale liquid
potential that raises the biggest question
marks over future returns from Brazil’s
deepwater oil. If the US shale revolution
story is replicated on a significant scale
around the world, sliding oil prices in
the longer term could render heavilytaxed earnings from Libra and its like
lackluster by comparison.
80
60
40
20
0
Dec-10
Jun-11
Source: Petrobras
30
insight
DECEMBER 2013
Dec-11
Jun-12
Dec-12
Jun-13
Local equipment and labor shortages
have been part of the reason why
Petrobras has been forced to scale back
production targets and lower its earnings
expectations. Since late 2010, Petrobras
has seen its shares shed over 60% of their
value while over the same period
BRAZILIAN UPSTREAM
ExxonMobil, for example, has risen by
20%. This year alone the company has
lost 14% of its value while Exxon has
gained 4%.
Saddled with debt and strapped for cash,
concerns are that Libra could overburden
the group financially. Its current portfolio
of offshore assets is already overstretching
the company as it scrabbles to fund its
$237 billion five-year investment plan,
mostly by selling assets abroad. Petrobras
plans to shed some $9.9 billion worth of
assets in 2013 alone.
At home, the company’s enforced
leadership in the subsalt is being diluted
by the financial, managerial and political
demands of its vast asset base both
upstream and downstream. While
integrated oil companies might typically
sell off less profitable assets in order to
focus their resources on high-earning
projects, Petrobras must allocate its
capital across a wide range of projects
new and old.
The strain on resources threatens efforts to
arrest declining production from mature
fields in the Campos Basin, for example, a
key requirement for it hitting a production
target of 4.2 million b/d in 2020.
Petrobras last year posted its first yearly
output decline since 2004 and the first
quarterly loss in 13 years. More recently
the company missed Q3 analyst earnings
forecasts by almost 50% after growing fuel
imports, the impact of heavy asset sales
and higher exploration charges crimped its
bottom line. Moody’s Investors Service
downgraded Petrobras’ debt on October 3
and the outlook is negative.
Still run largely as a government agency,
government fuel subsidies are squeezing
its margins and have already cost it
billions of dollars in lost revenues.
Despite planned investment to boost
Brazil’s refinery capacity, the country is
expected to remain dependent on fuel
imports for years to come.
As a result, Petrobras is seen continuing
to import fuels that it has to sell for a
loss domestically, although this could
begin to change with the government
set to consider soon a new price increase
mechanism which will allow the
company to narrow its losses from fuel
sales. Implementing a fuel pricing
formula targeting international parity
pricing would bring a welcome increase
to Petrobras’ cashflow and likely
reassure investors. The local gap to
international fuel prices currently stands
at around 3% for gasoline and 13% for
diesel.
Subsalt challenges
Brazil’s technically challenging, superdeepwater subsalt fields have cost a lot
more than first expected to produce and
lifting costs have soared over the last
few years.
With the cost of drilling a subsalt
development often representing more
than half of its total capex, timely access
to reasonably-priced rigs has become a
key problem. The UK’s BG Group in
particular has suffered from costly
slipped project milestones on the massive
Guara/Lula development due to
contractor holdups.
The bloated costs of doing business in
Brazil, often referred to as the ‘Custo
Brasil’, have been well documented with
disgruntled investors pointing variously
to poor infrastructure, red tape, high
taxes and low productivity.
Ź
OGX BURNS UP
Since Petrobras discovered the first of Brazil’s
giant subsalt oil fields in 2007, investors have
pumped billions of dollars into domestic oil
start-ups keen to tap into the market
exuberance that followed. This year some of
those bets began unraveling at a scale and
pace that have taken many by surprise.
At the top of the pile is the spectacular decline
of Brazil’s OGX; essentially a story of a
debt-laden start-up which overpromised and
under-delivered.
The flagship of a business empire run by
Rio-based tycoon Eike Batista, OGX banked
$4.1 billion from a 2008 public offering less
than a year after it was set up.
Then the biggest IPO in Brazilian history, OGX
backed up its promises of future offshore oil
wealth with estimates that its blocks in the
Campos and Santos basins held 4.8 billion
barrels of oil equivalent of reserves.
But Tubarao Azul, its first development, failed
to live up to company’s ambitious output
targets and the company also soon racked up
debts of over $5 billion buying more
exploration assets to fuel future growth.
Earlier this year, OGX hit the markets with
news that most of the fields it has explored
aren’t economically viable and its only
producing oil wells were flops.
After wiping further millions from the company’s
market value, the bombshell also set in motion
a chain of events culminating in OGX defaulting
on its interest payments and then filing for
bankruptcy protection at the end of October. At
that point it was valued at $190 million; just
three years earlier it had a stratospheric market
capitalization of some $45 billion.
A thick cloud now hangs over the future of OGX.
Documents on OGX’s website indicate that the
company will run out of cash in December and
that it needs $250 million in new money to
continue operations through April 2014.
Ultimately, OGX’s survival hinges on whether it
can generate cash from its most promising oil
field, Tubarao Martelo, and if can hold on to its
remaining licenses.
continued over page...
DECEMBER 2013
insight
31
BRAZILIAN UPSTREAM
...continued from page 31
OGX’s woes have already fuelled a growing
crisis of confidence in Brazilian startups and
other oil industry players have suffered.
Brazilian independent HRT has seen its own
market value decimated this year after dry
wells in Namibia and the Amazon Solimoes
Basin left it short on liquidity.
The company, which intentionally shunned
Brazil’s offshore bonanza when it set out its
own stall to investors, is scrabbling to sell
assets to refocus on producing fields able to
generate cash flow to stay in business. With
little debt and reports of interested buyers for
some of its assets, HRT looks well placed to
avoid the fate of OGX. The firm is currently
waiting for approval to take over the
operatorship of Brazil’s cash-generating Polvo
field from BP.
But many now expect the fallout of OGX’s
demise to cast a broader shadow over Brazil’s
upstream industry. Some have suggested that
future entrepreneurs will face much tougher
hurdles getting oil industry startups off the
ground as selectiveness of projects ramps up.
Calls have already begun for Brazil to tighten
controls over reserves reporting and legislative
difficulties could also take their toll on future
production offshore Brazil. Greater scrutiny
over assets portfolio means fewer pure-play
explorers will be allowed to go public,
according to market watchers.
Courtesy: Juliana Coutinho/Wikimedia
Eike Batista: the writing’s on the wall
32
insight
DECEMBER 2013
Petrobras alone requires more than 50
FPSOs and other production units to
meet its production targets, meaning
the country’s timely resource
development is likely to face more
delays. At the same time, stringent local
content requirements are overwhelming
Brazilian shipyards, and delays at the
swamped yards have already slowed the
construction of its key production
units. Hold-ups with construction of
some planned shipyards themselves
have also exacerbated the delays
Petrobras faces.
capital efficiency is improving and that
the flexible, modular nature of the
development can deliver on projected
timetables.”
“The risk involved in a local content
policy is that local suppliers develop in a
way that is not internationally
competitive, with a resulting increase in
costs and delays,” the IEA said in a recent
report noting rising unit costs of
manufacturing labor since 2009.
Given the high levels of cash consumed
by drilling subsalt fields, this cost area is
one which offers the greatest scope for
reductions. Subsalt drilling costs have
fallen about 40% over the past five
years, and Citi sees the potential for
5-10% cost deflation in the Brazilian
subsalt by 2018.
Project cost deflation will come through
drilling efficiency gains and more
competitive pricing as local supply chain
capacity builds within the country,
according to Citi. Greater
standardization in FPSOs and other
subsea supplies as well as advancements
in subsea technology will also play a role,
it predicts.
Some believe, however, that concerns
over Brazil’s cost and infrastructure
constraints may be overplayed. In a
recent report, Citi analysts said they
believe that production delays to the
Guara/Lula oil developments may reflect
more teething problems for the country’s
fast-expanding supply chains to the
domestic oil industry rather than
endemic limitations.
Increasingly it seems the fortunes of
Brazil’s economic health are tied to
Petrobras and the success of its oil and
gas industry. Certainly, the pressure on
Petrobras to fulfill its role as a national
oil champion, develop a huge raft of
upstream projects and fill government
coffers for public works is considerable.
Brazil’s subsalt developments can still
break even at $40-45/b, Citi estimates,
putting it firmly among the world’s top
25% of field developments in terms of
breakeven cost.
Given the sheer scale of the challenge, it
seems likely that Brazil may make things
a little easier for foreign investors. Some
now expect the contractual terms and
bidding fees imposed by the country to
be relaxed before the next subsalt round,
expected in 2015.
“We think the market fails to
differentiate the value of investment
across the industry,” Citi said in a
September study into BG, Repsol and
Galp’s Brazilian projects. “Our analysis of
the supply chain gives us confidence that
By coincidence, that is also the year
when Brazil’s subsalt oil revenues will –
by all accounts – really take off as it
gains entry to the global club of net oil
exporters. Ŷ
GLOBAL CARBON TRADING
FRANK WATSON
Managing Editor,
Emissions Markets
ABBOTT’S
CARBON
Internationally there is a clear
momentum behind emissions
trading systems but Australia is
going against the grain following
the election of Prime Minister Tony
Abbott. If his new government
successfully repeals the Carbon
Pricing Mechanism, the country
will become a test bed for
alternatives to cap-and-trade
systems in other regions.
GAMBIT
Australia’s plans to launch a carbon
market in 2014 look destined for the
scrapheap after the Liberal party – led
by Tony Abbott, who in 2011 famously
swore a “blood oath” to repeal
legislation putting a price on
Australian industry’s carbon dioxide
emissions – beat Kevin Rudd’s ruling
Labor party in national elections in
September 2013.
But the underlying reason for the
Carbon Pricing Mechanism has not
gone away: governments want to
control greenhouse gas emissions to
keep global warming limited to levels
that scientists believe will avoid
dangerous interference in the global
climate system – the stated goal of the
United Nations Framework Convention
on Climate Change.
Australia’s emissions could be 20%
higher than 2000 levels by 2020 if the
country takes no action, according to the
previous government, instead of 5-25%
lower as intended. Whether through capand-trade, or more direct action,
Australia has agreed to cut its greenhouse
emissions by at least 5% from 2000
levels by 2020, a target the new
government remains wedded to.
Making the transition from opposition
to government may provide a golden
opportunity for Prime Minister Abbott
to demonstrate that emissions can be
dealt with using methods other than
carbon trading, analysts say. If he
succeeds, he’ll deal a sharp blow to hopes
of developing internationally-linked
carbon markets. But if he fails, he may
unwittingly become an advertisement for
carbon trading.
Abbott wants to deal with the country’s
carbon emissions through a Direct
Action Plan – a set of policies that
includes, among other elements,
measures to cut emissions by penalizing
under-achievers and rewarding those that
clean up.
Little detailed information about the
detail of the DAP, for example on how
such a baseline penalty and credit
scheme might work, had been made
public by the time Insight was going to
press. Consultations on the DAP were
scheduled to take place, with
Ź
DECEMBER 2013
insight
33
GLOBAL CARBON TRADING
Courtesy: Chevron Australia
The Gorgon Project, a joint venture in carbon
sequestration, is expected to become operational in
2015.
implementing legislation expected to be
ready by February 5, 2014.
Broadly, Abbott’s short-term focus
appears to be an effort to reboot
Australia’s decade-long mining boom to
get the economy going again – a move
that seems to make sense in the short
term, and has popular appeal. But
long-term global trends suggest he may
do well to also keep an eye on the
horizon, clean energy and carbon market
advocates say.
If the mining industries that have been
the engine of Australia’s economic
success story face long-term decline, the
34
insight
DECEMBER 2013
challenge for the country’s politicians is
to create a policy framework that gets the
most out of those industries – and
prolongs their viability – while
supporting new sectors that could carry
the country to further success in the 21st
century global economy.
Those challenges have to be met against
a backdrop of increasing global action to
limit greenhouse gas emissions, as more
than 190 countries seek to strike a global
climate protection deal with legal force
in 2015.
America’s massive push into shale gas
stands as one example of how a major
GLOBAL CARBON TRADING
industrialized economy can deliver
cheaper energy, boost energy
independence, and cut emissions, by
reallocating resources and exploiting new
opportunities – and all without cap-andtrade at federal level.
Australia could have significant
recoverable shale gas reserves – around
437 trillion cubic feet, according to the
US Department of Energy – ranking it
seventh largest in the world, with the
Cooper Basin seen by some as one of the
best shale gas prospects outside of North
America.
But shale gas alone cannot provide the
answer. Aside from uncertainties over
the extent to which it can be
commercially exploited in Australia, and
how quickly, it remains unclear how
much impact shale gas might have on
Australia’s national emissions, which
sooner or later are likely to be capped
under new international agreements
driven by limits set out according to
climate science.
Besides, shale gas development in
Australia, as in many other countries,
would also need to overcome significant
public opposition.
Assuming Abbott succeeds in repealing
the CPM, Australian businesses will still
face policies intended to control
emissions – in line with the country’s
internationally-agreed commitments.
A key plank of the new government’s
Direct Action Plan involves sequestering
carbon in soils, although it remains
unclear whether such an approach can
play a long-term role in decarbonizing
Australia’s economy. Major efforts are
already under way in the country to
sequester CO2 emissions, such as the
Gorgon joint venture, which alongside a
vast gas project is developing what is
billed as the largest carbon capture and
storage project in the world.
The $55 billion project – a joint venture
between Chevron Australia, Shell,
ExxonMobil, Osaka Gas, Tokyo Gas and
Chubu Electric Power – seeks to inject
3.4 to 4.1 million mt of CO2 per year
into a deep saline formation 2.3 km
beneath Barrow Island off Australia’s
northwestern coast. Conceived in
expectation of a CO2 tax in Australia,
the project is expected to become
operational in 2015 and run for about
40 years. Onshore processing plants will
separate CO2 content from natural gas
extracted from the Greater Gorgon
Fields, lying 130-200 km offshore, and
store it under pressure in the saline
formation.
The DAP also includes a capped
government fund which will purchase
“lowest cost abatement” from projects
that reduce or avoid greenhouse gas
emissions, alongside measures to impose
financial penalties on businesses that
exceed their business-as-usual emissions
baselines.
The Emissions Reduction Fund aims to
purchase lowest cost emissions
abatement through projects approved
under the existing Carbon Farming
Initiative, or by companies cutting
emissions below a business-as-usual
baseline.
If the new government does successfully
repeal the Carbon Pricing Mechanism,
Australia’s new direct approach on
carbon management will be closely
watched by countries currently
Ź
THE FATE OF THE CPM
The Carbon Pricing Mechanism – part of
Australia’s Clean Energy Act – imposed a
fixed price of A$23.00/mt (U$21.28/mt) on
CO2 emissions from July 1, 2012, rising to
A$24.15/mt in 2013, and was originally
intended to switch to a cap-and-trade system
with a floating price by July 2015.
The fixed price left Australian businesses
facing the highest carbon price in the world
– much higher than the cost of around
Eur5.00/mt to buy CO2 allowances in Europe,
where prices have fallen from as high as
Eur30.00/mt, in line with lower economic
growth.
Ahead of the elections, former PM Kevin
Rudd brought forward by a year the start date
for the floating price, in a bid to quell
opposition. But with Australia’s decade-long
mining boom showing signs of fading, it
wasn’t enough to secure a win for Rudd in
the face of industry and voter concerns about
jobs and growth.
The government on October 15 started the
process to repeal the carbon tax by
launching draft legislation – Tony Abbott’s
first order of business as PM – but the move
away from carbon pricing may be more
difficult and protracted than the new
government hopes.
“If Labor does not support the Repeal Bill,
then the government’s ability to pass [it]
through Parliament will depend on the final
composition of the Senate,” said Elisa de Wit,
a Melbourne-based environmental legal
specialist with international law firm Norton
Rose Fulbright.
“If the government does not achieve the
required numbers, it has committed to call a
double dissolution election,” she said, in
reference to Australia’s procedure designed to
resolve deadlocks between the House and
Senate.
“The fastest possible time frame for repeal via
a double dissolution is likely to be
approximately eight to nine months from the
election, but the repeal could potentially take
several months longer than this,” she said.
DECEMBER 2013
insight
35
GLOBAL CARBON TRADING
planning their own emissions control
measures, such as Canada and Japan.
Since Abbott’s Direct Action Plan
includes a capped budget to achieve the
required emissions reductions, its costs are
by definition contained, advocates say.
But if the DAP policies fail to achieve
the targets, the government will face a
stark choice between admitting failure or
“
If Abbott succeeds, he’ll deal a sharp blow to
hopes of linked carbon markets. If he fails, he may
become an advertisement for carbon trading.
”
providing more money, playing into the
hands of carbon trading advocates, who
say cap-and-trade offers better value for
money and a more certain
environmental outcome.
Critics say the costs of the DAP could
ultimately be far greater than cap-andtrade. Christiana Figueres, executive
secretary of the UN Framework
Convention on Climate Change, said in
October the new government’s approach
could be “a lot more expensive” than
pricing carbon.
“They are going to have to pay a very
high political price and a very high
financial price because the route they are
choosing to take to get to the same target
agreed by the last government could be a
lot more expensive for them, and for the
population.”
Abbott has said that he believes the DAP
will meet Australia’s targets, but if it does
not, no more money will be allocated.
36
insight
DECEMBER 2013
How things unfold over the coming
months and years will become an
interesting test bed for alternative
policies to cap-and-trade systems in
other regions – notably the EU
Emissions Trading System, the world’s
largest international carbon trading
program, which regulates around 2
billion mt of CO2 per year across 31
countries.
Europe, which aims to link up its
Emissions Trading System with
compatible systems around the world to
form the backbone of an expanded
international carbon market, and had
agreed in principle to link the ETS with
Australia’s system in stages from mid2015, is fully committed to cap-andtrade, and any Australian success with
alternative measures is unlikely to hold
back similar efforts that China launched
in 2013.
Cap-and-trade vs tax-and-hope
In Europe, policy makers chose cap-andtrade because they could find no other
policy that guarantees a specific
emissions reduction, over an agreed
timeline, while driving lowest cost
emissions abatement.
A direct tax on CO2 emissions was
rejected in Europe because it cannot
guarantee an environmental outcome,
and is not supported by industry.
Tax is an effective tool for generating
revenue for governments, but would do
little to help the environment if polluters
simply pay the tax and broadly continue
on a business-as-usual emissions
trajectory.
China – historically a “command-andcontrol” economy, and one of Australia’s
GLOBAL CARBON TRADING
largest trading partners – is also
experimenting with the free-market
approach of cap-and-trade, at regional
and city level, with a view to launching a
nationwide system by 2015.
In America, cap-and-trade failed at
federal level due to a lack of support in
the Senate, forcing President Obama to
deal with emissions under the existing
Clean Air Act and other legislation,
coupled with regional state-level marketbased initiatives such as in California and
the Regional Greenhouse Gas Initiative
on the east coast.
Abbott’s tough stance against domestic
carbon pricing may have kept some
sections of Australia’s industry on-side.
But the move is risky, particularly
given emerging long-term trends
affecting the physical climate and
policy responses to it. If governments
are going to have to cut emissions,
they are likely to have more success if
they do so in a way that works closely
with the main emitting industries,
analysts say.
“There remains bipartisan agreement on
the targets and conditions of adopting
up to 25% reductions and this remains
the credibility test for strong and
effective climate policy,” said John
Connor, CEO of the Climate Institute,
a Sydney-based independent research
group.
“The Australian parliament needs to very
carefully consider why it would allow
Australia to be the first country in the
world to dismantle a carbon market,
particularly when leading financial
institutions such as the OECD, IMF and
World Bank are strengthening their
advice that carbon pricing is the
“
The American experience with shale gas
development and green legislation has shown that
in the global low-carbon race, cap-and-trade is not
the only game in town.
”
cornerstone of effective climate policy,”
he said.
Europe has powered ahead with cap-andtrade, and China looks set to follow. But
the American experience with domestic
shale gas development and green
legislation has shown that in the global
low-carbon race, cap-and-trade is not the
only game in town.
Prime Minister Abbott now has a chance
to demonstrate in Australia whether
there are viable alternatives to carbon
trading that can control industry’s CO2
emissions while safeguarding jobs and
boosting economic growth.
Since building industrial plants costs
money and carries risk, what industry
hates most of all is regulatory
uncertainty. Getting investments wrong
now raises the probability of stranded
assets down the line.
Australia’s new prime minister Tony Abbott swore a
blood oath to repeal the CPM.
If Australia is committed to removing
carbon pricing, the best outcome for the
country’s industrial companies would be
a quick end to the current debacle, and
the development of a credible framework
that allows them to invest with
confidence.
If such a policy fails over the next few
years, attention is likely to focus back on
carbon markets as the most cost-effective
way to manage CO2 emissions. Ŷ
Courtesy: Getty Images
DECEMBER 2013
insight
37
OPEC
MARGARET MCQUAILE
Senior Correspondent
OPECANGST
When Insight last looked at OPEC in
late 2010, there wasn’t even a hint
of the wave of protests that would
shortly begin its sweep across the
Arab world, unseating regimes that
had been in power for decades. Nor
was the extent to which shale would
revolutionize oil production in the
United States remotely apparent.
As a result of the so-called Arab Spring,
the political landscape of the Middle
East – OPEC’s heartland – is still
undergoing a series of seismic shifts, the
consequences of which have yet to reveal
themselves fully and which may yet turn
out to be the biggest challenge for the oil
producer group in the years ahead.
Another shift of epic proportions still
playing out also has implications for the
balance of power within the region and
within OPEC: the changing relationship
between Tehran and Washington.
A seismic shift of a different nature is
taking place several thousand miles away
in the United States, where the shale
boom is rolling back the tide of oil
imports. Indeed, such has been the
impact of both shale gas and shale oil
that the US Energy Information
Administration reckons that the United
States will be the world’s top producer of
petroleum and natural gas this year,
surpassing Russia and Saudi Arabia.
But, back at the tail end of 2010, OPEC
had much to be happy about. Not only
was it still up and running fifty years after
its foundation in September 1960 but it
38
insight
DECEMBER 2013
had also come through yet another oil
crisis, one spurred by the 2008 financial
markets collapse. Having plunged from
more than $147/barrel in July
2008 to less than $40/barrel by the end
of that year, crude prices seemed to have
stabilized around $80/barrel.
Still, even as the oil producer group was
congratulating itself on reaching its half
century, some officials were already
concerned about a new set of challenges,
some from outside OPEC and some
from within. Consumer countries were
demanding security of supply–which
would necessitate huge investment in
developing and maintaining spare
capacity–while working to reduce their
own dependency on fossil fuels.
Within OPEC itself, the challenge was
seen as coming mainly from Iraq, which
was rebuilding an oil sector decimated by
years of UN sanctions and a US-led war,
and now outlining capacity expansion
plans that would directly challenge OPEC
kingpin Saudi Arabia as the Middle
East’s top producer. Having awarded
long-term service contracts to a host of
OPEC
Courtesy: OPEC
foreign oil majors in two bid rounds,
Baghdad was targeting a production
capacity increase to more than 12
million b/d from just 2.5 million b/d.
Iraq has since tempered its capacity
ambitions and is now aiming for
something closer to 9 million b/d by the
end of this decade, although analysts are
far from convinced that even this volume
is achievable in view of the problems the
country faces on several fronts. As recent
events such as unrest at the camps of
service companies at the Rumaila field
and Baker Hughes’ subsequent decision
to stop operations in Iraq have shown,
not the least of these problems lie in the
areas of politics and security.
In the meantime, Baghdad is trying to
tackle the various infrastructural
bottlenecks that have held back southern
exports in particular. In September, work
began on linking a new metering system
to the Gulf export facilities. This,
however, resulted in Iraqi crude exports
falling by an average of more than
500,000 b/d over the month.
Continuing work to link the new system
to all the jetties and terminals is expected
to keep exports running at reduced levels
through the first quarter of next year,
although not necessarily anywhere near
the September volume drop.
Nevertheless, Iraq has undoubtedly made
progress on the production front in
general and, according to officials,
expects to boost output to 3.5 million
b/d from current levels of around 3
million b/d by the end of this year. It has
already overtaken its former foe, Iran,
both in terms of crude production and
exports and is currently OPEC’s second
biggest producer after Saudi Arabia,
while Tehran, burdened by a raft of
international sanctions imposed over its
nuclear program, has seen its
Ź
DECEMBER 2013
insight
39
OPEC
production slide from pre-sanctions
levels of 3.6-3.7 million b/d to around
2.65-2.7 million b/d and its exports crash
by more than half to just 1 million b/d.
program for several years, but the summer
of 2012 brought a new raft of sanctions
directly targeting the Islamic Republic’s
economic life blood–its oil revenues.
Iraq has made huge inroads into Iran’s
Asian markets, overtaking the Islamic
Republic to become Turkey’s top supplier
and already setting its sights on becoming
the number two supplier to China after
Saudi Arabia and ahead of fellow OPEC
member Angola. South Korea presents a
similar picture, with crude imports from
Iraq far outpacing those from Iran.
The European Union imposed an oil
embargo on the roughly 500,000 b/d of
Iranian crude imported by its member
countries. It also banned the provision of
EU-linked insurance for any shipments of
Iranian oil, regardless of destination – a
move that had immediate consequences
for Iran’s big Asian customers. At the
same time, the United States brought into
force a set of financial sanctions from
which Iran’s Asian customers could obtain
waivers and continue to have access to the
US financial system only by pledging
“significant” cuts in their imports of
Iranian oil.
But Iraq is in a parlous state politically,
as evidenced by the relentless violence
that threatens to plunge the country into
all-out sectarian strife, with obvious
implications for the oil sector. Baghdad
also has problems with the Kurdistan
Regional Government, which refuses to
export crude produced in the
autonomous governorate through the
main pipeline system linking Iraq’s
northern oil fields with Turkish
Mediterranean port Ceyhan.
Courtesy: OPEC
40
insight
DECEMBER 2013
Mending fences
Instead, the KRG is working to build
independent export pipelines from the
region to Turkey, a development that
threatens to sour Baghdad’s relations
with Ankara. Kurdish officials hope to
begin sending crude oil via Turkey to
international markets independently of
Baghdad by the end of 2013. The Iraqi
government’s response to such a move
could be decisive in the evolution of
Kurdish oil exports in 2014.
This year’s presidential election in Iran,
however, resulted in a surprise victory for
moderate cleric Hassan Rouhani, who swept
to power with nearly 51% of the vote on
the back of a pledge to mend Iran’s fences
with the outside world and a determination
to reach a deal on the nuclear issue and
have the sanctions lifted. The first step
towards an eventual full lifting of sanctions
was made in Geneva on November 24,
when Iran and six world powers – Britain,
China, France, Germany, Russia and the
United States – struck a preliminary deal
giving Tehran limited sanctions relief in
exchange for concessions on its nuclear
program while negotiations continue
towards a comprehensive agreement.
Iran, on the other hand, may be in sight
of a reversal of the international
sanctions that have crippled its oil sector
in particular and its economy in general.
Tehran has been under one form of
sanction or another over its nuclear
The Iranian president has appointed a
cabinet of technocrats, including oil
minister Bijan Zanganeh who held the
same job under former reformist president
Mohammad Khatami. Zanganeh, credited
with attracting billions of dollars of
OPEC
investment into Iran’s oil and gas sector
during his previous tenure in the job, has
already begun a review of the upstream
contracts, known as buybacks, under
which foreign oil companies worked in
Iran and which were criticised for their
poor rates of return.
Of course, the full lifting of sanctions may
be some way off, but the prospects must
be far from gloomy in view of fact that
Washington and Tehran are now speaking
directly to each other. If sanctions are
removed, the way will be open for Iran to
attract the kind of investment needed not
only to compensate for the high decline
rates in its ageing fields but to develop
further its considerable reserves of oil and
gas. Another consequence of sanctions
being lifted would be a strong marketing
effort by Tehran to recover its share of
world markets that could bring Iran head
to head with Baghdad in a battle for
market share just as OPEC is expected to
lose ground to non-OPEC producers over
the next few years.
Painful revolutions
Two other major developments are still
playing out, the tragically misnamed Arab
Spring and the shale oil revolution in the
United States, but their effects have already
caused considerable pain to some in OPEC.
The unrest that began in Tunisia in early
2011 swiftly spread to Libya and, over
the following months, sent crude
production plunging from close to 1.6
million b/d in January to virtually nothing
by the summer. The regime of Libyan
strongman Moammar Qadhafi was
ousted and Qadhafi himself killed, and a
new interim administration took control.
By January 2012, crude output had
recovered to around 1 million b/d and
“
One consequence of sanctions being lifted
would be a strong marketing effort by Tehran that
could bring it head to head with Baghdad in a
battle for market share.
”
later appeared to stabilize around 1.4-1.5
million b/d. But the interim authorities’
control over the country has been feeble,
to say the least, and the past few months
have seen the country descend further
and further into lawlessness, the extent
of which became clear in October when
prime minister Ali Zeidan was briefly
abducted, allegedly by a militant group
close to a faction within the government.
Libya has a long way to go before it will
be able to build the kind of institutional
infrastructure that enables a country to
function in the most basic manner, but
people’s hopes for better lives have been
high. And, in the meantime, rival
militias continue to vie for position. This
combination of desires has proved a
dangerous one for the oil sector, where
production and exports again fell back in
recent months to as little as 200,000 b/d.
The Libyan authorities say some issues
have been resolved and that volumes will
recover. But production is still well below
pre-uprising levels and confidence in Libya
is far from high, as is clear from the
reluctance of foreign oil companies to
commit to drilling programs that should
have been well under way by now.
The security concerns that have become
a big worry for international oil and gas
companies involved in upstream projects
in North Africa came home to roost in
January this year when Jihadist
Ź
DECEMBER 2013
insight
41
OPEC
terrorists launched a deadly attack on
Algeria’s In Amenas gas complex, operated
by BP in partnership with Norway’s Statoil
and Algerian state oil and gas company
Sonatrach. Neither BP nor Statoil has
returned workers to the facility, and
analysts have suggested that Statoil may be
looking to pull out of Algeria altogether.
Back in 2010, few people in the global oil
industry or in OPEC could have predicted
the shale oil revolution in the United States
that would slash US demand for imported
crude. But in 2012, US crude production
averaged 6.49 million b/d, which
represented a jump of more than 1 million
b/d in just two years. Between 2011 and
2012 alone, US crude production
increased by 790,000 b/d. This, according
to the US Energy Information
Administration, was the biggest annual
output increase since commercial crude
production began in the United States in
the middle of the 19th century.
OPEC crude exports to the US fell by
some 520,000 b/d over the two years, to
4.03 million b/d in 2012 from 4.55
million b/d in 2010, but the biggest
impact was felt by Nigeria, whose main
market for years has been the United
States. In 2012, Nigeria exported just
406,000 b/d of crude to the US, less than
half the 983,000 b/d of 2010. Yet between
2004 and 2007, Nigerian volumes to the
US had averaged more than 1 million b/d.
In January this year, refiners Valero and
Phillips 66 said they were no longer
taking in light sweet crude imports at
their Gulf Coast plants, replacing them
with domestically-produced barrels.
Valero’s Gulf Coast refineries had typically
imported light sweet crude from Brazil,
Nigeria and North Africa; now they are
running crude from Eagle Ford, Bakken
42
insight
DECEMBER 2013
and Louisiana. In late October, Phillips
66 said its goal was eventually to use only
domestic crude at all its US refineries.
Interestingly, US crude imports from the
Persian Gulf rose by close to 450,000
b/d between 2010 and last year, the bulk
of which – 270,000 b/d – came from
Saudi Arabia. The kingdom’s relationship
with the United States has become
difficult to read in these latter months of
2013. In October, Saudi Arabia turned
down a temporary seat on the UN
Security Council. At the same time,
various media reported that the head of
Saudi intelligence had told European
diplomats that Saudi Arabia was scaling
back cooperation with the US on Syria.
Much has been written about these two
developments and whether they should be
seen as an expression of Saudi frustration
and anxiety over US policy, not only on
Syria but also on Iran. Undoubtedly, the
relationship between Saudi Arabia and the
US is changing. Aside from Israel, Riyadh
has been Washington’s main ally in the
Middle East for more than three decades
and it would be strange, to say the least,
if the Saudis were not apprehensive about
the consequences of a rapprochement
between the US and Iran.
What these developments mean for the
oil relationship remains unclear. The
shale oil explosion means that US
reliance on imported oil is falling, in any
case. And like other Middle Eastern
producers, Saudi Arabia has been
increasingly focusing on the growth
markets of Asia. Nevertheless, Riyadh has
always been confident of its importance
to the US as a producer that can bring on
spare capacity at short notice in times of
need. In these changing times, however,
that confidence may have diminished. Ŷ
The New Energy Economy
As natural gas production soars, North America is set
to become a net energy exporter for the first time
NORTH AMERICAN EDITION
ISSUE DATE:
CLOSE DATE:
MATERIAL DATE:
ON SALE:
JULY 21, 2014
MAY 28
JUNE 16
JULY 7
Note: Dates subject to change
50+
Platts
conferences per year
covering energy policy
and trends
73%
of Fortune
readers noted seeing
Fortune special sections
and
66%
took action
after noting the ads that
ran within them
OPPORTUNITY
North America’s massive shale gas/oil and liquefied natural gas deposits are
transforming world energy markets. The U.S. is the world’s number one
natural gas producer, and rapidly expanding shale gas and oil production is
predicted to make North America a net energy exporter by 2025. Yet despite
safer, more regulated extraction methods and the advent of globally
transportable liquefied natural gas, the environmental debate still rages. How
far—and how fast—can shale gas development grow?
Source: Platts; Starch 2011-2012
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US OIL MARKET
STARR SPENCER
BRIDGET HUNSUCKER
Managing Editor,
Markets
Editor,
Oil News
SHIFTING SHALE
The vast amount of oil and gas
suddenly generated by the North
American shale revolution has driven
a rapid change in the market, not
least in the way crude is transported
around the continent.
What a difference a year has made in
relation to oil pricing in North America.
After the wide and wildly see-sawing
spreads between West Texas
Intermediate, the standard inland US
benchmark crude, and European
benchmark Brent and also other crudes
that characterized 2012, prices now
appear a lot more disciplined.
The unruly differentials that kept oil
cheap in one part of the continent and
hiked its price in another were reined in
Courtesy: Getty Images
44
insight
DECEMBER 2013
by billions of dollars worth of
infrastructure: pipelines, rail loading/
offloading terminals, and barges and
related installations which have allowed
upstream producers to get their crude to
coastal refining centers with relative ease
at costs that don’t break the bank.
No question about it, shale and
unconventional resource plays have
transformed the North American energy
landscape in the last few years. Although
the shale boom started in the early 2000s
with natural gas in the North Texas
Barnett Shale, eventually a glut of gas
output there and in other gas plays such
as the Fayetteville Shale in Arkansas and
the Haynesville Shale in Louisiana
caused gas prices to plummet later in the
decade and, after the 2009 recession, set
in motion a massive shift among
producers from gas to oil operations.
Once producers discovered that the same
techniques that had allowed them to
scoop oodles of gas out of the ground
could also be applied to crude operations,
the race was on to discover the next big
shale oil field, cheered on by climbing oil
prices. The Bakken Shale in North
US OIL MARKET
Dakota and Montana was the first such
unconventional oil operation, followed in
short order by the Eagle Ford Shale in
South Texas, which began as a gas
discovery in 2008 but was soon found to
also contain sizeable liquids and oil
“windows.”
At the same time, mature fields in places
as diverse as Utah’s Uinta Basin and West
Texas’ Permian Basin – the latter
producing conventionally for nearly a
century – got caught up in “shale fever”
that also saw scads of other old fields
turned into unconventional plays
through the use of technologies such as
horizontal drilling and multi-stage
hydraulic fracturing at intervals along
the increasingly lengthy horizontal legs
of oil wells.
That last technique – informally known as
longer laterals – involves drilling the
horizontal legs up to 10,000 feet in some
cases and is a way to access more
hydrocarbons from the reservoir. At the
same time, oil companies are looking to
optimize well spacing – meaning, to find
the maximum distance between wells that
can best drain the reservoir. Upstream
operators, while in full production mode
for most of these unconventional plays,
continue experimenting to find the ways
to best extract the most value from the
field in the shortest time frame.
In any case, there is no question that all
this activity has led to some fairly hefty
investment which has translated into
rapid results on the US production
ledger. In July 2013, the US produced
7.487 million b/d of crude, according to
the US Energy Information
Administration, the statistical arm of the
Department of Energy; that was a level
not seen since 1991 and was up a
remarkable 17% over the previous 12
months and a dazzling 38% increase
over the previous 24 months.
But even more mind-boggling than the
amount of oil production generated by
the shale revolution is the change, over a
relatively short period of time, in the
way crude is moved to arrive at the best
market at the best price for producers.
Historically, producers would sell oil to
area refiners, or pipe it someplace – many
times, to the Cushing, Oklahoma hub
where it would wait in large storage
terminals until it could find a refinery or
other destination. But a couple of years
ago, Cushing filled up – a consequence of
the sheer volumes of crude gushing from
inland shale fields and the ensuing lack of
enough pipeline capacity to deliver it to
refineries in a timely manner. While
differentials always existed between
basins, now, with gluts in several areas,
crude spreads began to widen.
More pipeline capacity was planned,
both new and expansion of existing lines,
but getting them on stream would take
years. The real problem was what to do
in the meantime.
Enter rail and barges, as interim solutions
that could very well be around for a lot
longer, according to analysts and producers.
The somewhat antiquated shipping
method of sending crude on railcar has
re-emerged in recent years as a creative
way to connect growing light sweet crude
production in North America with
coastal refiners. And the popularity of
what is now commonly termed “crude by
rail” picked up great speed once market
participants realized the potential for fast
shipments and wide profit margins. Ź
DECEMBER 2013
insight
45
US OIL MARKET
To facilitate the new railcar movements,
terminal developers, including railroad
companies, went gangbusters building out
the necessary infrastructure for loading and
unloading crude from trains. In North
America, about 140 crude-by-rail terminals
have been built in recent years, including
about 86 for loading and 50 for unloading.
Altered slates
Seeing the potential to unload more crude,
shippers soon shifted away from sending
manifest cars, or only a few at a time on a
single train. They began loading unit
trains instead. On a unit train, railcars all
carry the same commodity. A crude unit
can consist of up to 120 railcars.
Courtesy: Getty Images
President Obama said he won’t approve Keystone XL
unless there is clear proof it would not “significantly
exacerbate” carbon pollution.
Consequently, a growing number of
North American refiners have altered their
crude slates to accommodate the relatively
cheap and high quality crude. Those
refiners now have contact with almost
every crude sourced in North America. At
the same time, crude-by-rail shippers have
gained access to essentially every
destination market in North America
through an extensive railway network.
For example, a slew of US East Coast
refiners have revitalized their facilities from
a nearly idled state with the help of
relatively cheap Bakken crude. It was the
bargain price of Bakken and other relatively
low-cost crudes that helped to offset
crude-by-rail’s costly shipping expenses.
In addition, the once ample price spread
between ICE Brent and NYMEX WTI,
which is the key benchmark used by traders
moving crude inside the US, allowed for
the healthy shipping margins for crude by
rail. In essence, the wider the spread, the
larger the profit margin for barging or
railing low-cost crudes to coastal markets.
As production ramped up, Bakken crude
prices dropped to as low as NYMEX
NORTH AMERICAN OIL PIPELINE PROJECTS
Edmonton, AB
Hardisty, AB
CA NA DA
Energy East Project
500-8020 Mb/d
TransMountain
(590 Mb/d) 800 Mb/d
Line #5
(50 Mb/d) 540 Mb/d
Alberta Clipper
(120 Mb/d) 570 Mb/d
Line #6B
Line #61
(260 Mb/d) 560 Mb/d
(160 Mb/d) 560 Mb/d
(640 Mb/d) 1200 Mb/d
Keystone XL
508 Mb/d
Guernsey, WY
U NI T E D S TATE S
Southern Trails
120 Mb/d
Pony Express
210 Mb/d
Line #62
260 Mb/d
Whiting
Phase 1- Coker
Niobrara Falls
Phase 2 - Hydrotreater
Cushing, OK
125 M/d
105 Mb/d
Keystone Gulf Coast
White Cliffs
508 Mb/d
Permian Express
80 M/d
Trunkline
2013 - 90 Mb/d
420 - 660 Mb/d
2014 - (60 Mb/d) 150 Mb/d
Flanigan South
600 Mb/d
Permian Express
Phase 2
200 Mb/d
Seaway Expansion
(450 Mb/d) 800 Mb/d
BridgeTex
278 Mb/d
ME XI CO
46
insight
DECEMBER 2013
Cactus Pipeline
200 Mb/d
Westward Ho
300 Mb/d
Longhorn
225 Mb/d
Ho-Ho Pipeline
250 - 500 Mb/d
Line #9
Phase 1
240 Mb/d
Line #9
Phase 2
60 Mb/d
2013 2014 2015 >2015
Pipelines
Expansion
New build
Reversal
Gas-oil conversion
Capacities shown as:
(Incremental Mb/d)
New Total Capacity Mb/d
US OIL MARKET
WTI front-month average minus
$26.50/barrel at the beginning of 2012.
In contrast, coastal Brent-based crudes
stayed at a healthy premium to WTI.
Shipping costs for crude by rail average
near $13.5/b from the Bakken to the
Gulf Coast or from $15.5/b to the East
Coast from the North Dakota Shale.
The US Association of American
railroads estimates that railroads today
transport roughly 11% of US crude oil
production, up from virtually none a
few years ago.
Barge up
As crude by rail gained momentum, crude
by barge rode in behind its tracks.
Quickly, crude-by-barge markets emerged
in new areas, mostly from the Port of
Corpus Christi in Texas. Barge shippers
began moving Eagle Ford crude to refiners
all along the US Gulf Coast and beyond.
Those shipments have grown substantially
from two years ago, when they were about
7,000 b/d, to more than 500,000 b/d,
according to industry sources.
As in Corpus Christi, North American
ports are expanding docking capabilities
to pave the way for more crude-by-barge
shipments. And in many cases, investors
are seeking ways for crude by rail and
barge to work in tandem.
On the US West and East coasts, crude
can be railed to a terminal, where it is
then loaded onto a barge. Many US East
Coast refiners have already implemented
this method. Along the West Coast,
terminal operators and refiners are
making big plans to replicate the process.
For example, US refiner Tesoro plans to
send price-advantaged crude by barge to its
California and Alaska facilities after railing
the crude to the Port of Vancouver,
Washington. There, Tesoro is constructing a
unit train unloading and marine operating
terminal expected to start operation in
2014. The initial capacity will be 120,000
b/d, but the refiner envisions a near-term
expansion to as much as 300,000 b/d.
Crude-by-rail has faced a number of
obstacles, not least a series of derailments.
Most recently, a train carrying 2.7 million
gallons of crude derailed and exploded in
Alabama. In July, a crude train derailed in
Lac-Megantic, Quebec, triggering fires and
explosions that claimed 47 lives. The train
was carrying Bakken crude, and the
accident sparked government investigations
into the safety of sending crude by rail.
Before that, in 2012, a tanker railcar
shortage developed, as demand for cars
outpaced availability. Crude shippers had
to compete with petroleum shippers and
a newbuild backlog transpired, with
sources quoting lengthy wait times.
THE KEYSTONE EFFECT
The North America crude midstream buildout
has evolved at warp speed, with a throng of
developers announcing pipeline and rail projects
seemingly daily. At the center of this frenzy is
TransCanada’s proposed Keystone XL Pipeline.
The estimated $5.3 billion pipeline would
carry up to 830,000 b/d of crude from
Alberta’s oil sands in western Canada and
Bakken Shale crude from North Dakota to US
Gulf Coast refiners. But the infamous
pipeline’s permitting has been delayed in
recent years on both environmental and
legislative concerns.
The project is undergoing a final
environmental review by the US State
Department. If the agency signs off, the
Obama administration would have to make a
final permitting decision, and decide whether
the project is in the national interest. The
permit is needed because the pipeline crosses
a US international border.
President Obama said earlier this year that he
would not approve the line unless there was
clear proof it would not “significantly exacerbate”
carbon pollution. In response, Canadian officials
began a campaign trying to demonstrate how it
is voluntarily implementing tighter environmental
controls on oil sands development.
Furthering the debate about crude by rail’s
safety, in late October a Canadian National
Railway train carrying crude and liquefied
petroleum gas derailed in northern Alberta.
Four cars carrying crude oil and nine with
pressurized LPG went off the track. No
crude was spilled in the derailment, but
three LPG cars caught fire.
Keystone XL was first rejected at the state and
US government level in early 2012 when it
was proposed as a Hardisty, Alberta to
Nederland, Texas project.
Despite the derailment, CN’s CEO Claude
Mongeau said on a third quarter
conference call that the “facts are clear... we
move 99.997% of our volumes to market
without incident. We have an unwavering
commitment to operating a safe railroad.”
TransCanada then applied for the pipeline in
two segments and received regulatory
approval for its so-called Gulf Coast Project,
which will carry crude from Cushing,
Oklahoma, to Nederland.
Recently, railcars have become more
available because of a slight drop in
crude-by-rail movements on
Ź
Obama at the time rejected TransCanada’s
original application to build the 1,700-mile
pipeline, saying the decision rested not on the
project’s merits, but rather a 60-day deadline
Congress imposed on the process.
Construction began on the latter 700,000830,000 b/d pipeline earlier this year, which
was expected to go into service at the end of
2013. If Keystone XL is built, the Gulf Coast
continued over page...
DECEMBER 2013
insight
47
US OIL MARKET
...continued from page 47
Project line will be integrated into the larger
system. TransCanada anticipates completing
the entire Keystone XL in 2015.
Many North American producers and refiners
are proponents of Keystone XL. But there are
also real indications that the US is becoming
more energy self-sufficient due to a boom in
domestic shale oil production and may not
need to rely on Canadian imports.
In addition, Harold Hamm, CEO of major
Bakken producer Continental Resources, said
earlier this year that the proposed pipeline is
no longer needed by his company or others
like it. TransCanada has said the pipeline
would also carry 100,000 b/d of crude from
the Bakken.
At the same time, a slew of environmental
activist groups attempted to block
construction of Keystone XL. Those groups,
from both the US and Canada, have taken
stances against Alberta’s oil sands
greenhouse gas emissions and the potential
safety hazards of transporting oil sands crude,
among other concerns.
Several, including the Sierra Club and Oil
Change International, released a study earlier
this year saying that the pipeline could lead to
a 36% increase in Canadian oil sands
production. The groups have concluded that
the pipeline proposal should be rejected
because oil sands are energy-intensive to
develop.
The Canadian Association of Petroleum
Producers this year said in a forecast that
oil sands production is expected to rise to
5.2 million b/d by 2030, from 1.8 million
b/d in 2012.
While many wait for a decision on Keystone
XL, Canadian oil sands producers have
searched for other options to move their crude
to market. In the Alberta area, many rail
loading facility projects are underway. Those
terminals are expected to help facilitate
increasing volumes of oil sands crude by rail
movements.
Bridget Hunsucker and Herman Wang
48
insight
DECEMBER 2013
narrowing price spreads and weaker
shipping profits. And while the plans of
Tesoro and other facility developers
remain intact, during late summer sources
said they began to notice that, like rail,
barging activity had started to decline.
225,000 b/d. Magellan’s joint venture
with Kinder Morgan, the Double Eagle
condensate pipeline – which runs from
Three Rivers, Texas to Magellan’s Corpus
Christi, Texas terminal – started initial
operations at 100,000 b/d in May.
In fact, as the Brent-WTI spread
contracted this year there was talk that
many crude-by-rail shippers were
returning to pipelines where available.
Moving this crude further along the Gulf
Coast from Texas markets to Louisiana
refineries is Shell Pipeline’s Houston-toHouma, Louisiana, pipeline which began
service in January 2013.
Volumes on Enbridge Energy Partners’
North Dakota crude pipeline, the
premiere system out of the Bakken, have
been on the rise in connection with less
competitive refinery netbacks for sending
Bakken crude via rail, the company has
said in recent months.
This significant “re-piping” of the US, as it
has been called, has included the addition
of new pipelines or restructuring of existing
ones to send crude oil to the US’ largest
refining region along the Gulf Coast.
Most notably, the 400,000 b/d Enterprise
Product Partners-operated Seaway pipeline,
running from Cushing to Jones Creek,
Texas began in 2012 after the line was
reversed to flow southward. It was expanded
to its current capacity at the beginning of
2013. A “twin line” is expected to come
into service to add an additional 450,000
b/d of capacity along the route.
A glut of crude and condensate is also
moving in to the Gulf Coast from Texas
markets in the Eagle Ford and Permian
via Magellan’s Midstream Partners
Longhorn and Double Eagle pipelines.
Magellan announced earlier this year that
it will expand the Longhorn pipeline,
which runs from Crane, Texas to
Houston, to 275,000 b/d next year from
A second phase of the so-called Ho-Ho
Pipeline, which involves reversing the
pipeline to run from the Port Arthur area
to Louisiana markets, including Clovelly
and St. James, was expected to go into
service by the end of 2013. The segment
will be a 22-inch-diameter line with a
capacity of 360,000 b/d.
In addition, TransCanada’s Keystone XL
pipeline is also expected to bring more
barrels to the Gulf Coast and was set for
a startup date at the end of 2013.
The pipeline will carry an initial 700,000
b/d of crude from Cushing to Nederland,
Texas. An expansion of up to 830,000
b/d of the line is possible. The so-called
Gulf Coast Pipeline is the southern leg of
TransCanada’s controversial Keystone XL
project, and will ship mostly Canadian
heavy sour crudes into Nederland. With
US governmental approval pending,
Keystone XL’s fate is still up for debate.
But when it comes to crude-by-rail and
crude-by-barge movements, shippers are
expected to continue to utilize both even
as more pipeline capacity comes
available. Though shipping margins are
narrower than in recent years, crude-byrail shippers still promote rail’s speed
and, above all, flexibility. Ŷ
US POWER MARKETS
PETER MALONEY
Senior Writer,
Megawatt Daily
MARGINAL
SUCCESS
Capacity markets in the US,
designed to spur investment in the
peakload capacity needed to keep
the lights on, have so far achieved
their aim – but that doesn’t mean
there aren’t plenty of people keen
to change them.
As they approach their 10-year
anniversary, capacity markets in the
United States are facing an overhaul in
how they are structured, with implications
for how power plants are built and
financed and what products – or range of
products – will be available to the grid.
run frequently, are critical to the
operation of the power grid. They have
to be there to meet peak demand, and
spare capacity is needed to ensure
reliability, which is measured by a
system’s reserve margin. The problem is
how to pay for those plants.
For a variety of reasons, mostly political
and regulatory reasons, capacity markets
in the US are localized in the northeastern
quarter of the country. That makes the
region a showcase for deregulated markets
both in terms of how well they have
performed and the challenges they face.
Capacity markets were created to solve
that problem, that is, to provide the
missing money.
As deregulation took hold in the US in the
late 1990s, more and more power was
traded in wholesale markets. But
stakeholders began to realize that there was
a problem, the missing money problem.
Economically there are two types of
electricity. Energy is bought and sold in
real time, and provides revenues to pay
for existing power plants, but those
revenues are not sufficient to attract the
investment necessary to build a power
plant that might not run very frequently.
Those plants, even though they may not
Ten years out, capacity markets appear to
have done a good job in fulfilling their
primary task. The lights have stayed on,
and all four northeastern wholesale
markets – ISO-New England, New York
ISO, PJM Interconnection (which
coordinates power transmission in all or
parts of Delaware, Illinois, Indiana,
Kentucky, Maryland, Michigan, New
Jersey, North Carolina, Ohio,
Pennsylvania, Tennessee, Virginia, West
Virginia and the District of Columbia)
and the Midcontinent Independent
System Operator (which covers all or
part of Montana, North Dakota, South
Dakota, Minnesota, Wisconsin,
Michigan, Ohio, Indiana, Illinois, Iowa
and Nebraska, as well as Manitoba in Ź
DECEMBER 2013
insight
49
US POWER MARKETS
Canada – enjoy robust reserve margins
(see table PJM Reserves).
According to the North American Electric
Reliability Corp.’s 2013 Summer
Reliability report, PJM’s mandated reserve
requirement for the 2013-14 planning
period is 15.9%, but the anticipated
reserve margin is well above that at 29.3%
(see NERC Summer Reliability Report).
ISO-NE’s NERC reference reserve margin
is 15%, and the region’s anticipated
reserve margin is 21.6%. NERC’s
reference reserve margin for NYISO is
17% while the anticipated reserve margin
is 18.8%. And MISO’s reserve
requirement for 2013-14 is 14.2%. Its
anticipated reserve margin is 18.8%.
PJM RESERVES
MW
220,000
Installed capacity
200,000
Forecast peak
Reserve margin
180,000
In a recently published report, “Capacity
Markets, Lesson Learned from the First
Decade,” Brattle Group concluded that
capacity markets have met their reliability
mandate, but with a caveat. The success
should not be “overstated,” the authors
wrote since those capacity markets were
all instituted at times of surplus capacity.
‘Version of socialism’
Despite the apparent successes, capacity
markets have come under frequent and
vocal criticism, particularly from power
generators and from developers of power
projects, for not sending price signals
sufficient to encourage new investments.
“I believe that there are significant and
fundamental flaws in the process,”
Anthony Alexander, president and CEO
of FirstEnergy, recently said, referring to
the capacity auction in PJM where his
company operates.
Nick Akins, president and CEO of
American Electric Power, one of the
largest US utilities, was even stronger in
his criticism. “AEP has issues with this
regulatory construct we sometimes call a
capacity market in PJM.”
160,000
140,000
120,000
100,000
80,000
60,000
40,000
20,000
*
0
2007
2008
2009
2010
2011
2012
2013
*PJM installed capacity numbers for 2013 not announced until 2014.
He went on to call the capacity market
construct a “version of socialism” and
said the “rules seem to penalize longterm investors.”
Source: PJM Interconnection
NERC SUMMER RELIABILITY REPORT
Projected internal demand (MW)
Anticipated resources (MW)
Anticpated reserve (%)
NERC reference reserve (%)
Source: North American Electric Reliability Corp.
50
insight
DECEMBER 2013
NYISO
MISO
PJM
ISO-NE
33,279
39,592
18.8
17
91,532
108,742
18.8
14.2
145,029
187,531
29.3
15.9
26,690
32,458
21.6
15
And Kenneth Cornew, executive vice
president and chief commercial officer of
Exelon, said the low level of prices in PJM’s
last capacity auction are not reflective of
the long-term capacity revenues needed to
support new generation development.
Despite those criticisms, developers are
stepping up to build new power plants.
PJM Interconnection and ISO-NE both
US POWER MARKETS
saw spikes in the amount of new
generation that was offered and cleared
in their most recent capacity auctions
(see New Generation Added).
NEW GENERATION ADDED
MW
6,000
ISO-NE
PJM
5,000
PJM’s last capacity auction saw a record
level of new generation clear, 5,463 MW,
a jump of more than 100 MW above the
5,346 MW that cleared its previous
auction. And new generation in ISO-NE
spiked to 800 MW, from 79 MW in its
previous auction.
4,000
The new projects were proposed despite
low clearing prices for capacity in the
auction, particularly in PJM, which saw
prices dip to their lowest levels in three
years (see PJM Prices).
Source: PJM Interconnection, ISO-New England
3,000
2,000
1,000
0
2010-11
And while the low prices may have
disappointed incumbent generators in
those ISO regions, they obviously did not
deter investment by some developers.
The low prices also reflect bids from
capacity resources that have raised
concerns from stakeholders.
In particular stakeholders are concerned
about state subsidies and imports.
New Jersey and Maryland were concerned
that residents of their states were paying
too much for electricity from PJM and
that the capacity auctions were not
encouraging the in-state investments that
would drive down prices, so they passed
laws instituting solicitations that gave
contracts to new in-state power projects.
The move created fireworks among PJM
stakeholders because the contracts were
tied to the ISO’s capacity markets, putting
downward pressure on capacity prices.
Through a series of regulatory
interventions PJM adjusted the rules to
2011-12
2012-13
2013-14
2014-15
2015-16
2016-17
its capacity market, but three projects –
two in New Jersey and one in Maryland
– still cleared the capacity auction.
Contracts awarded to those projects have
since been voided in decisions by two
separate federal courts.
There are also tensions on the western
side of PJM, which borders the
Midcontinent ISO. Unlike PJM,
MISO’s capacity market is voluntary,
and that is reflected in the prices.
MISO’s most recent capacity auction
closed in April at $1.05/MW-day. In
May PJM’s capacity auction cleared at
$59.37/MW-day. The disparity in
capacity prices has prompted generators
in MISO to sell their capacity into PJM,
pushing down prices. That has raised
concerns among PJM stakeholders and
administrators, who are now looking at
imposing a cap on imports.
In both instances, the imports and the
state subsidies, PJM’s capacity market
sent price signals – just not the newbuild signals originally envisioned.
Capacity markets have also proved
useful at providing a signal to generators
debating whether or not to
Ź
DECEMBER 2013
insight
51
US POWER MARKETS
continue running older plants, especially
coal-fired plants that are facing tighter
emissions controls.
“
PJM’s capacity market sent price signals – just
not the new-build signals originally envisioned.
”
FirstEnergy in July cited capacity prices
when it announced the close of two
more coal plants in PJM, the 1,710MW Hatfield Ferry station and the
370-MW Mitchell plant, both in
Pennsylvania.
At the time of the announcement, UBS
analyst Julien Dumoulin-Smith said
FirstEnergy’s announcement marked part
of a “second wave” of coal plant
“capitulations” in PJM. He cited the 10
GW of coal capacity that bid into PJM’s
2016-17 BRA but did not clear, and said
he would not be surprised to see further
retirements.
In New England, NRG Energy in May
cited low capacity prices in the decision
PJM PRICES
MW/DAY
200
150
100
0
2010-11
2011-12
Source: PJM Interconnection
insight
An analysis of data collected by the
Federal Energy Regulatory Commission
and compiled by Platts shows that
Norwalk Harbor received $2.83 million
in capacity payments, $4.19 million in
energy payments and operated at a 2.7%
capacity factor in the first quarter.
The data also shows at least a dozen
plants with even lower capacity factors.
And nearly all those plants had a higher
proportion of revenues from capacity
payments than from energy payments
compared with NRG’s Norwalk Harbor
facility. In the first quarter, capacity
payments accounted for 40% of
Norwalk Harbor’s $7 million in total
revenue.
Dumoulin-Smith estimates that low
capacity prices – exacerbated by the
FERC mandated removal of ISO-NE’s
capacity floor price in the next auction
– could force another 6 GW of mostly
oil-fired capacity out of the market.
These issues – capacity imports, state
level subsidies, low capacity prices
– have been a source of contention for
stakeholders in various ISOs. They
also reflect the changing nature of
capacity markets. They have become
broader in scope than when they were
first created.
Originally they were designed to
encourage new generation, but to
accommodate regulatory mandates,
demand response now participates on an
equal footing with generation.
50
52
to close its 352-MW, gas- and oil-fired
Norwalk Harbor plant in Connecticut.
DECEMBER 2013
2012-13
2013-14
2014-15
2015-16
2016-17
Demand response is the opposite of
generation. It turns off machines
US POWER MARKETS
during times of peak load to reduce the
need for high priced peaking power.
Such “load shaving” also shaves
potential revenues from generators, but
it provides revenues for curtailment
service providers that contract with
end-users to provide the service.
The incorporation of DR into capacity
markets, particularly in New York, New
England and PJM, has also added to the
complexity of the capacity markets and
has increased the level of administrative
intervention.
One of the hot topics under discussion
in PJM now is whether or not DR
providers are bidding and clearing in the
annual capacity auction, which looks out
to a delivery period three years in the
future, and then buying out their
obligation more cheaply in the
intervening auctions.
Critics charge that such actions are a
misuse of the process, which they say is
designed as a form of true-up for physical
assets, not a means of arbitrage for
financial players.
The issue has risen to the level where
PJM is re-examining how it dispatches
DR in its queue.
Against this background the Federal
Energy Regulatory Commission on
September 24 convened a technical
conference to address the range of issues
that have cropped up in individual
capacity markets and the inconsistencies
that exist in capacity markets across the
four ISOs.
After a day of sometimes contentious
testimony, FERC is now weighing
improvements to the markets as some
stakeholders call for further measures to
address specific concerns.
While FERC is not necessarily looking to
overhaul capacity markets as they now
exist, some of the proposals that were
presented at the meeting were, at least in
the arcane world of capacity markets,
somewhat radical.
In one presentation at the September
25 meeting James Wilson of Wilson
Energy Economics said that
experience has shown that new
merchant plants are not being bid in
at their costs. That was the
expectation, and those bids were
supposed to send a long-term price
signal. But that has not happened,
Wilson said.
He argued that many of the
expectations of the capacity markets are,
in fact, “inside out.”
As an alternative to the current
arrangement, Wilson and other
presenters at the meeting advocated a
more modest role for capacity markets.
They say that many of the challenges
that capacity markets are going to face
as a wider array of resources enter the
market – such as demand response and
wind and solar power resources –
would be better served through the
energy and ancillary services markets,
with capacity markets playing a
diminished role.
Time will tell how those ideas are
received and, if they are, how they will be
implemented. Meanwhile capacity
markets will have to deal with their
success, which has resulted in a much
wider array of resources entering into the
market and low prices. Ŷ
HOW CAPACITY MARKETS WORK
Capacity markets were designed to provide
the financial incentives for building power
generation capacity that might be used
infrequently and could not survive on real time
energy payments only.
Capacity auctions are operated by the wholesale
markets that also operate the real time and day
ahead energy markets, but capacity auctions
are run separately by those wholesale markets,
known either as independent system operators
(ISOs) or regional transmission organizations
(RTOs). Capacity auctions also have several
features that make them very different to the
real time and day ahead markets.
In the US there are organized capacity
markets in four ISOs: the PJM
Interconnection; the New York ISO; ISO-New
England and the Midcontinent ISO.
There are big differences between how the
ISOs conduct capacity auctions, but in broad
strokes existing generation and/or proposed
new generation must bid into the auction. They
provide the supply side of auction. The ISO
administrators provide the demand side by
coming up with forecasts of demand and
calculating how much capacity their systems
will need to meet that demand, and to be sure
there is a cushion to meet unforeseen events.
The administrators order the supply resource
bids in order from high to low and select enough
capacity to meet their forecast need and to
maintain their reserve margins. In most auctions
the marginal units set the price. So all bidders
are paid the price of the last bid selected.
As mentioned, the various ISOs differ in how
they have organized their capacity auctions.
PJM for instance conducts its capacity auctions
every spring for a delivery year three years in
the future. ISO-New England’s capacity auction
also looks three years out, but the capacity
auctions in MISO and New York are shorter
term, two months and six months, respectively.
All bids selected in that auction receive
payments for that delivery year. In return, they
are expected to be available to generate
power when needed, for instance, if there is
an unexpected outage of another generator, or
weather conditions create a spike in demand.
DECEMBER 2013
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53
WATER & ENERGY
BRIAN SCHEID
Editor
...TILL THE WELL
Rising energy demand is bringing
with it an increase in water usage at
the same time as resources are
dwindling in some areas – is water
scarcity a threat to the energy sector?
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DECEMBER 2013
At the height of the disastrous drought that
afflicted North America in 2012, the
operators of Connecticut’s Millstone Power
Station were, for the first time ever, forced
to shut down one of its nuclear reactor
units. As the mercury soared, water
temperatures in the Long Island Sound,
from where the plant draws water for
cooling, rose above 75 degrees Fahrenheit
(24 Celsius) and, under the conditions of its
license, it had to stop for almost two weeks.
These partial plant shutdowns, power
reductions and restarts of mothballed
plants are part of a troubling global
trend, according to some industry
observers. The energy sector is heavily
dependent on water, for everything from
cooling systems to natural gas and oil
fracking operations, and the demands
being placed on the usable water
resources are getting greater, while those
resources may be dwindling, they claim.
Less than a year later, another East Coast
heat wave forced operators of the Pilgrim
Nuclear Power Station in Plymouth,
Massachusetts to temporarily reduce power
when water temperatures in the Cape Cod
Bay, from where the plant draws its water
for cooling, briefly exceeded 75 degrees.
Droughts, for example, have impacted
“both electricity demands and power
plants’ ability to meet them,” according
to Stacy Tellinghuisen, a senior energy
and water policy analyst with Western
Resource Advocates, a nonprofit
conservation group.
During a 2011 drought in Texas, four
natural gas-fired plants, two near
Houston and two near Dallas, that had
been taken offline in 2010 were brought
back online amid a state electric grid
crisis caused by sweltering heat and
unplanned maintenance. The mothballed
plants had to be restarted because other
plants lacked access to sufficient water
for cooling operations.
According to a September report from
Synapse Energy Economics, coal, nuclear
and natural gas power plants account for
41% of freshwater withdrawals in the
US, roughly 137.4 billion gallons of
water per day.
Coal plants withdraw more than 85 billion
gallons of freshwater per day for their
cooling systems, by far the most of any
WATER & ENERGY
plant type, according to the report. Nuclear
power plants withdraw nearly 45 billion
gallons, while natural gas plants withdraw
about 7.4 billion gallons, the report shows.
Those numbers are only expected to
increase in coming years.
“Going forward, our water resources will
be further squeezed by population
growth coupled with the impacts of
climate change,” said Melissa Whited, a
Synapse associate and one of the study’s
authors. “The massive water use of coal,
nuclear, and natural gas generators will be
increasingly challenged, particularly when
alternatives that require little water, such
as wind and solar, are readily available.”
Whited said the water requirements of
coal, nuclear and gas power plants “are
enormous and leave it vulnerable to
droughts and heat waves.”
The problem is not unique to the US. High
water temperatures have plagued the
nuclear sector in Europe over the past
decade. In July 2006, for example, a reactor
in Spain was shut down due to high
temperatures in the Ebro River. A total of
17 reactors in France were either shut down
or had their output reduced during a heat
wave in 2003. And potential shutdowns of
hydroelectric generators have regularly
created threats of electricity shortages in
Australia during recent droughts.
Thermoelectric power plants draw water
from rivers, lakes and estuaries through
recirculating or once-through cooling
systems. The water is mostly returned to
its source once it is used for cooling,
leaving the power sector only responsible
for about 3% of total national water
consumption, as compared to 41% of
total withdrawals, according to Michael
Courtesy: Getty Images
Webber, co-director of the University of
Texas at Austin’s Clean Energy Incubator.
But while many of these billions of
gallons of water are frequently discharged
back into those rivers, lakes and estuaries,
it is often discharged at a much higher
temperature, creating thermal pollution
which can accelerate bacteria growth,
increase algal blooms and even kill fish,
according to environmentalists.
Ź
DECEMBER 2013
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55
WATER & ENERGY
During a US Senate hearing earlier this
year, Senator Ron Wyden, an Oregon
Democrat and the chairman of the
Senate Energy and Natural Resources
Committee, said that climate change,
which was increasing water temperatures,
would likely continue to hinder plant
cooling operations. US power generation
would likely be drawn down because of
usable water shortages, he said.
“This means that climate change poses a
double threat to some of these facilities,
“
There is no real, market price for water,
making it simpler for a soybean farmer or nuclear
plant operator to waste water rather than invest in
water-saving technologies.
”
potentially threatening both water
availability and sufficiently cool intake
water,” Wyden said.
Water shortages, which have become
more frequent as droughts have
intensified in recent years, can set up
water rights battles between generators
and other sectors, primarily agriculture,
putting new plant construction at risk.
In a report released during that 2011
drought in Texas the North American
Electric Reliability Council said that,
depending on rainfall, anywhere from
400 MW to 2,900 MW of generation
could be lost that winter. “In addition,
there is over 9,000 MW that is at risk of
curtailment if their water rights are
recalled to allow the available water to be
used for other purposes,” the report said.
“While the latter scenario is unlikely,
entities in the Region are investigating
and implementing mitigating measures.”
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DECEMBER 2013
The worth of water
This is particularly problematic since
there is no real, market price for water,
making it simpler for a soybean farmer
or nuclear plant operator to waste water
rather than invest in costly water-saving
technologies, said Webber with the
University of Texas.
“The energy sector has a lot of money
and wants water, the agriculture sector
has a lot of water and wants money,”
Webber said. “Well, normally, you
would just set up a transaction and
trade water for money, but we’re not
really set up that way for water
markets in Texas or the rest of the
United States.”
The growing use of hydraulic fracturing
for oil and gas wells could further limit
access to water, environmentalists
believe. Fracking operations use about 2
million to 6 million gallons of water per
well, consuming roughly 0.6 to 1.8
gallons of water per MMBtu of gas and
as much as 2 gallons of water per
MMBtu may be needed for processing
and transport, according to a 2010
study of Chesapeake Energy’s reported
values for water consumption in four
US gas plays. By comparison, coal
mining consumes as much as 260
million gallons of water.
Analysts have claimed that
environmentalists typically overstate the
impact of fracking on water supply. In a
recent presentation, Alicia Aponte of
General Electric’s global strategic
intelligence division said that even if
shale production increases at its current
pace, water used in fracking will account
for less than 1% annually of the water
used for power plant cooling over the
next decade.
WATER & ENERGY
Jim Richenderfer, director of technical
programs with the Susquehanna River
Basin Commission, which regulates
water withdrawals used in many fracking
operations in the Marcellus Shale, said
that about 10.4 billion gallons of water
have been consumed for Marcellus
fracking operations since the shale boom
began in 2008. Environmentalists have
falsely claimed that billions gallons of
water are used each year, Richenderfer
said. He estimated that each well, on
average, uses about 4.4 million gallons of
water.
But water used in fracking may seem to
have a deeper impact on the
municipality where the fracking takes
place, since the water is typically taken
from a single, local source and taken at
one time.
Environmentalists have used the water
issue as a motivation to move to a less
carbon-intense, renewable energy future.
The Synapse study, for example, was
funded by the Civil Society Institute, a
Massachusetts-based think tanks which
has advocated for an increase in US
renewable energy, particularly solar and
wind.
“There are energy sources available to us
that are not water intensive,” said Grant
Smith, a senior energy analyst with CSI.
“The enormous economic and political
influence of the electric utility
companies, and the oil, gas, coal and
nuclear industries present one of the
major challenges of moving toward a
new energy path.”
But less carbon intense does not always
mean less water intense. Coal-burning
power plants with carbon capture and
storage technologies, concentrated solar
power systems and nuclear power plants
have the high water-use intensity of
generation sources, according to the
National Renewable Energy Laboratory.
Wind and photovoltaic solar systems
require almost no water, however.
While water use is expected to increase,
there have been few US government
studies on the issue. A water availability
census by the US Geological Study was
mandated by a 2009 water bill, but will
not be completed for several years. And
members of congress have found little
success in getting the Department of
Energy to complete a comprehensive
water study.
Is this government foot-dragging
tantamount to negligence or is the water
issue not one to get overly worried about
at this stage? Only time will tell. So
much depends on how water stress issues
develop in different areas. But with the
world’s population still rapidly
expanding, the demands on water
resources are certain to increase
tremendously.
In a recent report on the risks for the
energy industry from water issues,
research and consultancy group Wood
Mackenzie said that “Companies (plus
their investors and governments for that
matter) are faced with a variety of
water-driven risks with some easier to
address than others” adding that “water
risks for energy companies could be
leveled out in the future – with
technology, transparency and
engagement offering opportunities to
minimize risks for all fuel types.”
“Depending on how specific companies
respond, there could be winners and
losers,” it concluded. Ŷ
DECEMBER 2013
insight
57
GLOBAL BIOFUELS
JONATHAN KINGSMAN
Global Director Agriculture,
Platts
BIOFUELS
BACKLASH
In the face of dwindling support from
many former advocates, the global
biofuels sector has been shifting
focus to second generation biofuels
that do not compete with food for
their feedstocks. But the outlook
for first generation biofuels is not as
bleak as it might appear.
Courtesy: Getty Images
Totem of all that is wrong with biofuels.
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DECEMBER 2013
Two numbers stood out from the most
recent BP Statistical Review of World
Energy of particular significance for the
biofuels industry: 2012 saw the largest
single-year increase in US oil production
ever recorded, but also the first annual
decline in global biofuels production
since 2000, largely due to a decline in
the US (-4.3%).
At the FT Commodity Conference in
Lausanne in April 2013, Greg Page, the
CEO of US trading house Cargill,
warned that biofuels are losing political
support. He argued that a few years back
biofuels had the backing of three
powerful constituencies. The first, of
course, was the Northern Hemisphere
farmers who were keen to bring more
land back into production and have
another outlet for their crops. The
second, particularly in the USA, was the
“energy-security” guys who wanted to
reduce their country’s dependence on
foreign oil and to have more control over
energy supplies. The third was the
greens, the environmentalists who
immediately saw biofuels as a low carbon
substitute for mineral oils and
(dangerous) nuclear power.
Biofuels have since lost two of those
constituencies and may even be losing
the third.
The environmentalists were the first to
desert the camp. The financial crisis of
2008 diverted attention from global
warming back to the economy. By
unlucky coincidence severe weather
problems in various parts of the world
reduced agricultural production and sent
food prices sky-rocketing. Protests in
Mexico against the rising price of corn
led to calls for less corn to be used for
ethanol, even though the corn that the
US uses for ethanol is not the same corn
the Mexicans use to make their bread.
Environmentalists also attacked the
Brazilian sugar industry for “destroying”
the Amazon jungle, even though virtually
no cane is grown anywhere near the
Amazon. And in the Asia-Pacific region
palm oil producers were suddenly in the
limelight for tearing up the Indonesian
rain forests. Even though very little palm
oil is used in biodiesel production (most
of the increase in palm oil demand has
come from domestic users in India and
China), biodiesel took the brunt of the
GLOBAL BIOFUELS
criticism. Just as the polar bear became
the totem of global warming, the
Orangutan has become the totem of all
that was supposedly wrong with biofuels.
In their fight against biofuels the
environmentalists have found wealthy
backers in the form of the industrial
food companies. A recent letter sent to
the UK Prime Minister called for an
end to biofuels made from food and
was co-signed by Nestlé, Unilever,
ActionAid, Oxfam and the WWF. The
letter argued that biofuels “are
exacerbating global hunger” with many
varieties “worse for global warming than
the fossil fuels they are meant to replace.”
The second constituency that biofuels
have lost is the “energy security” one.
The shale gas revolution in the US has
been described as the most significant
economic event of the past ten years
and has markedly reduced the US’s
dependence on imported energy.
Already in 2011 the US exported more
gasoline, diesel and other fuels than it
imported for the first time since 1949.
As for the farming constituency, farmers
in developed countries have long been
dependent on political support. Without
subsidies and various price support
mechanisms they would all be a lot
poorer. To maintain political support
they need to keep public opinion on
their side, particularly in Europe. As
public opinion turns away from biofuels,
farmers may increasingly distance
themselves from the biofuels industry,
instead branding themselves as a force
for good in providing healthy food to an
ever growing population – and as
guardians of the countryside. Farmers
want to be seen as part of the solution to
global hunger, not part of the problem. Ź
BIOFUELS AND GLOBAL HUNGER
Despite the doomsayers the world is not
running out of land (even without cutting down
rain forests). There is no shortage of food in
the world; indeed the rise in global obesity
rates would suggest that, in some parts of the
world at least, there is too much food – or that
food is too cheap.
Higher food prices are not bad for everyone.
They favor rural areas but hurt the urban poor.
Among the worst affected by high food prices
are city dwellers in the world’s poorest
countries. In Nigeria, for example, food
accounts for a third of total consumer
spending. In China the figure is 25%. In the
UK it is around 7% and in the USA it is around
5% – enough to moan about but not enough
to cause a riot.
This is not to deny the global tragedy that an
estimated 870 million people in the world go
to bed hungry every night. The question that
should be asked, however, is why?
The UN’s Food and Agriculture Organization
recently reported that each year about a third
of all food for human consumption, around 1.3
billion tons, is wasted, along with all the
energy, water and chemicals needed to
produce it and dispose of it.
In the developed world, much of the waste
comes from consumers buying too much and
throwing away what they do not eat. In
developing countries, it is mainly the result of
inefficient farming and a lack of proper
storage facilities. The FAO estimates the cost
of the wasted food, excluding fish and
seafood, at about $750 billion a year, based
on producer prices.
Wastage through inefficient supply lines is part
of the problem but ill-advised domestic
government policies can negatively impact
agriculture production. In addition, rich world
export subsidies can reduce world food prices,
thus discouraging food production. This is
particularly the case in developing countries
where local, less efficient and small scale
farmers cannot compete with bigger scale
farming boosted by subsidies. Local farmers
can be driven off their land, move to the cities
and add to the problem of the urban poor.
There is also the question of well-intentioned
food aid. Many charities believe that the
solution to world hunger is to move food from
surplus areas to deficit areas. The world’s
multinational trading companies do this already
but only if it is profitable.
Food aid does the job when it is not
profitable: the world’s charitable
organizations do a tremendous job in helping
to prevent starvation in the short term,
starvation caused by periodic crop failures or
war. Long-term food aid can however have
negative effects if free food depresses
agricultural prices in the receiving countries
and drives local farmers out of business.
The only long-term solution to global hunger is
to raise the incomes of those poor people
through sound government policies that promote
economic growth, coupled with free trade. The
solution to global hunger is not to lower food
prices. Lower food prices only result in less food
production, aggravating the problem.
By giving the world’s farmers an alternative
outlet for their production, biofuels boost
agricultural returns. This can help farmers in
developing and developed countries to earn a
better living and may encourage some of the
urban poor to return to their fields. In this sense
biofuels are part of the solution to global hunger,
not part of the problem.
Courtesy: iStockphoto.com
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59
GLOBAL BIOFUELS
What effect is the loss of political and
public support having on the biofuels
sector?
In Europe, partly as a result of the strong
lobbying by anti-biofuels groups, the
European Parliament recently voted a
6% cap on biofuels made from food.
Under current legislation the entire 10%
biofuels mandate in transport fuels by
2020 can be sourced from food-based
biofuels. Based on 2012 figures,
countries such as Germany, France and
Spain were already above the 6% cap.
Unsurprisingly, the proposal has
brought howls of anguish from the
sector, particularly as their production
capacity is already underutilized:
European biodiesel capacity utilization is
WHAT DRIVES FOOD PRICES?
The mainstream media tends to blame the
growing world population for rising food prices,
but although a popular explanation it is not a
convincing one. After all, the world population
was growing just as fast in the 80’s and 90’s
– periods of low agricultural prices and
mountainous food surpluses, especially under
the EU’s Common Agricultural Policy. Perhaps a
more important factor is rising world incomes
and the change in consumption patterns,
particularly the increase in meat production: in
1980 meat consumption in China was 20 kg per
capita; in 2007 it was 50 kg. In the USA it was
125 kg. Just imagine what happens if China ever
reaches those levels!
The media also blame speculators for rising
prices, particularly the long-term passive
investors. To give just one example, index funds
now own around 15 million mt of sugar futures
FAO MONTHLY FOOD PRICE INDEX
250
Real
Nominal
200
150
100
50
Sep-91 Sep-93 Sep-95 Sep-97 Sep-99 Sep-01 Sep-03 Sep-05 Sep-07 Sep-09 Sep-11 Sep-13
Source: FAO and Kingsman
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DECEMBER 2013
running at around 33% while for
ethanol it is about 60%.
In the US the sector is struggling to get
“the blend wall” raised from 10% to 15%
but it seems to be losing the battle, despite
the fact that American made cars imported
into Brazil run without any problems on
a 25% blend of anhydrous ethanol in
gasoline. The American Petroleum
Institute is appealing to motorists’ wallets,
arguing that an E15 incorporation will
mean that the US would have to export
more gasoline and that this would raise
the price of gasoline domestically. The
Renewable Fuels Association argues that
this is nonsense and that ethanol is
cheaper than gasoline so that more
ethanol use means cheaper fuels.
and it is obvious that by keeping this sugar off the
market they force prices higher. But wait a
minute: they don’t keep that sugar off the market,
they “borrow it” and then return it at every futures
expiry when they roll forward their positions.
Index funds inflate forward (rather than spot)
prices and send price signals to farmers to step
up production. They then “abandon” that extra
production once it becomes spot.
Although rarely mentioned in the media,
politicians have tended to aggravate food price
increases. Export bans on agricultural goods
artificially depress domestic prices (sending the
wrong signals to farmers) while inflating world
prices. Domestic price controls and export taxes
do the same thing while domestic subsidies can
also distort the market. And while we are talking
of “beggar thy neighbor policies,” the long
history of agricultural export subsidies in the US
and Europe have pressured world prices,
encouraging farmers in poor countries to
abandon their fields and head for the city slums.
The winding down of Europe’s CAP in the first
decade of this century led to a decline in
subsidized agricultural exports that was not
immediately replaced by an expansion of
production in importing countries.
GLOBAL BIOFUELS
The Environmental Protection Agency
seems to have decided against the ethanol
industry and according to a leaked draft
is working on a proposal that would
lower the ethanol mandate for 2014 to
13 billion gallons from the 14.4 billion
gallons dictated by Congress.
In Brazil the government has until
recently capped gasoline prices at a level
that made ethanol production
unprofitable. Poor weather and overoptimistic expansion added to the
sector’s woes and some mills have gone
bankrupt as a result; many others are on
life-support. Earlier this year the
government increased gasoline prices and
this has given the mills some breathing
room. The country’s weakening Real will
make gasoline imports more expensive
and the government should raise domestic
gasoline prices further. However this is
not certain given the recent civil unrest
in response to just a small hike in bus
fares; the government once again has
more important worries than looking
after their domestic ethanol industry.
It is therefore not surprising that a siege
mentality has developed within the
global biofuels sector and the big
industrial groups are moving their focus
to second generation biofuels that do not
compete with food for their feedstocks.
Investment in the sector is increasingly
focused on Brazil. BP announced in
2012 that it would be directing
investment in advanced biofuels to Ź
Another factor that is rarely mentioned is the
weather: the three years leading up to the
food price hike in 2008 saw a major drought
and frosts in Argentina, drought in Australia,
Southern Africa and areas of China and
India, heat waves across southern and
eastern Europe, serious flooding in the UK
and major hurricanes around the globe. Low
rainfall and heat stress limited crop yields in
areas of the US grain belt as did the terrible
drought in the US last year. All this bad
weather (and the increasing evidence of
climate change) has had an impact on food
production and helped push up prices.
OIL AND AGRICULTURAL COMMODITY PRICES ($/BARREL)
There is an old saying that “price is the best
fertilizer”: you could argue that food prices rose
because they were too low for a sustained period
of time. These higher prices have spurred
production and prices are now falling again.
Source: FAO and Kingsman, WTI data from NYMEX
150
260
WTI Oil (LHS)
USDA Farm Price Index (RHS)
120
220
Correlation = 0.77
90
180
60
140
30
Oct-04
Oct-05
Oct-06
Oct-07
Oct-08
Back in 2008 Mexico saw street protests against
rising food prices. In 2013 the farmers took to the
streets, protesting against low food prices.
the time many analysts explained this by arguing
that higher oil prices increased demand for crops
used for biofuels, which in turn raises the price
for these commodities. That may be partially true,
but it doesn’t explain the strong relationship
between oil and agricultural commodity prices for
the previous 30 years.
Lastly, food prices are largely cost driven. The
chart here shows that farm prices moved in line
with oil prices for a long time. The correlation, at
77% between 2004 and 2013, was significant. At
Oil and energy costs are a significant proportion
of a farmer’s gross margin. The cost of operating
farm machinery, purchasing fertilizer and
transporting farm produce all increase with higher
Oct-09
Oct-10
Oct-11
Oct-12
100
Oct-13
energy costs, as do the processing costs of food
manufacturers. Commodity prices peaked in line
with oil in the early 70’s and 80’s when there was
no biofuels industry to speak of.
But as we all know, in this modern world,
everything is both connected and inter-related.
Rapid growth in China and India has helped pull
energy prices higher which in turn pushed up
agricultural costs and increased demand for
biofuels. Which came first in this messy chicken
omelette: the chicken or the egg? ■
DECEMBER 2013
insight
61
GLOBAL BIOFUELS
the US and South America, saying it is
“increasingly interested in … the
integration potential between a sugar
cane mill and a cellulosic plant.”
There is an old joke that “advanced
biofuels are the fuel of the future, and
always will be” but progress is being
made. In the end, however, it will come
down to cost. (The sugar industry has a
huge advantage in second generation
fuels in that the cellulose in question is
already at the sugar mills so marginal
transport costs are zero.)
However there is room for optimism also
for first generation biofuels. As
unfortunate as it may be, public opinion
and policy is largely driven by lobbying.
The industrial food giants are not
lobbying against biofuels out of altruistic
concern for public welfare but because
they fear that increasing biofuels use will
drive up their input costs. Food costs
have increased over the past years not
because of biofuels but because of poor
weather and rising production costs,
particularly in US dollar terms with the
dollar held at an artificially low level. In
Brazil particularly poor weather has
raised production costs through lower
capacity utilization; combine that with
an over-valued Real and the dream that
Brazil would become a supplier of cheap
green fuel to the world evaporated.
These factors are being reversed as
farmers plant more crops and the
weather allows them to grow. This is
already lowering commodity prices and
allaying fears of rising food prices. This
should reduce the economic incentive of
the anti-biofuels lobby. If the weather
holds good the problem soon will once
again be food surpluses rather than food
shortages. Indeed, there has already been
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DECEMBER 2013
a surplus of sugar in the world sugar
market for the last three years and
producers are struggling to make ends
meet. In many countries, diverting some
of their food production to ethanol will
help tide them over, keeping them in the
game for when the weather turns bad
again and crop production drops.
India is a good example of this. The
government mandated 5% blending in
2003 in cane-growing regions and
extended it to 20 states in 2005. Despite
these initiatives ethanol blending never
really took off, partly because the
country’s sugar cane was needed for food
rather than ethanol. (In India, unlike in
Brazil, ethanol is made from molasses, a
by-product of sugar production, rather
than directly from sugar cane juice.)
With domestic sugar surpluses building
again, and oil imports becoming more
expensive, the program is gaining
traction and in 2013 the government
extended the implementation of the 5%
mandatory blend to the entire country.
Governments in many other developing
countries are also, once again, looking to
ethanol to help maintain domestic farm
incomes at a time of falling food prices.
Both the Philippines and Thailand are
pushing ahead with expanding ethanol
production and use, as is Colombia.
The biofuels sector has been struggling
because feedstocks and production have
been too expensive: better weather and a
stronger dollar should reverse that trend
while at the same time taking the
lobbying pressure off the sector in terms
of food prices. If, and this is a big if,
world oil prices stabilize at around
current levels you will see biofuels
winning back the constituencies that
have been lost recently. Ŷ
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DECEMBER 2013
insight
63
OIL & GAS UPSTREAM
EDWARD LEVY
Assistant Editor,
Global Oil
GRAYING
AT THE
The upstream oil and gas industry’s
technical innovations and pioneering
spirit have been pushing back the
boundaries that once seemed to
place an upper limit on production,
but it faces a potential constraint of
a very different kind – a shortage
of the necessary skills to keep the
boom going.
EDGES
Despite record investment in the
upstream oil and gas sector in recent
years, a somewhat gloomy sentiment has
lingered in the back of the industry’s
collective mind: the concern is that, as
droves of experienced workers approach
retirement over the next decade or so, a
deepening skills shortage will keep
pushing up already ballooning costs,
with knock-on effects on exploration and
production activity across the globe.
Against a backdrop of stubbornly high
worldwide unemployment following
2008’s financial crash, the oil and gas
industry’s technical disciplines have been
one of the global economy’s relatively
scarce bright spots, with the new
extraction methods for mature plays and
ample greenfield discoveries offering a
host of skilled job opportunities.
Nonetheless, finding and retaining the
people with the right skills to drive all
this activity consistently ranks as one of
the highest concerns for companies. A
survey in 2013 of the global oil and gas
labor market by recruitment website
oilcareers.com found respondents ranked
the skills shortage as the second-biggest
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DECEMBER 2013
threat to the oil industry, only marginally
behind economic instability.
Some even put those two the other way
around, while a joint study
commissioned by the European Union
and OPEC said that 80% of oil and gas
companies have reported significant
manpower shortages in key technical
areas. It listed the biggest problems as
being “in the areas of geology,
geophysics, subsea operations and
petroleum engineering (especially with
regard to drilling, reservoirs, completion
and production).”
The current skills shortage has its roots
in the 1980s. Though the industry
clamors to add jobs now, it has to be
remembered that conditions weren’t
always so healthy. The cumulative effects
of the 1973 and 1979 oil shocks resulted
in chronically low oil prices throughout
much of the 1980s, culminating in a lot
of M&A activity in the sector,
consolidation and mass layoffs through
that decade and into the 1990s.
Consultancy Deloitte highlighted this
in a 2012 report: “This skills gap is
OIL & GAS UPSTREAM
the result of the boom/bust cycle
inherent in the oil and gas sector: very
few new workers were hired in the late
1980s. As more-experienced petro
techs retire, the sector is left with
less-experienced workers who lack the
knowledge and depth of
understanding to undertake new
projects. All of this is taking place as
the sector runs at full capacity and the
world demands more oil and gas from
technically challenging sources such as
shale-rock formations and ultradeepwater wells.”
With wages in the sector very
competitive and rising relatively
rapidly given the competition for
talent – some surveys put recent
annual wage increases approaching
10% or even in some parts of the
world in the mid-teens – choosing a
career in the oil and gas industry can
certainly be a lucrative decision. And
yet the industry still seems to have
problems attracting and retaining
sufficient, properly trained talent.
This is particularly true in North
America, notably boom areas such as the
Bakken shale in North Dakota and the
Eagle Ford shale in south Texas, where
there are significant shortages and
importing labor will likely have to be a
key strategy in the future, Deloitte said.
The 2013 Hays Oil and Gas Salary
Guide, a well-respected publication
widely used to gauge the health of the
industry’s labor market, echoed the
concerns about the global labor
market, saying that “skills shortages are
now by far the major concern for
employers in the industry.” It too
highlighted particular problems in
North America, where the recent Ź
Courtesy: Getty Images
DECEMBER 2013
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65
OIL & GAS UPSTREAM
expansion on the back of the shale
boom in the US and oil sands in
Canada has been massive.
According to US Bureau of Labor
statistics, from the start of 2007
through the end of 2012, total US
private sector employment increased
by more than one million jobs, about
1%, while over the same period the oil
and gas industry added more than
162,000 jobs – a 40% increase,
showing how heavily the shale boom
has drawn on the pool of available
talent.
John Faraguna, Hays’ global managing
director, put it bluntly: “The American
oil and gas industry is watching its talent
supply dry up, and without a watershed
moment Americans will miss out on the
contributions this sector makes to the
overall economy.”
In fact the two North American
neighbors are increasingly in
competition with each other for
talent. Canada, where the skills
SELECTED COUNTRIES’ AVERAGE ANNUAL SALARIES (US$)
Australia
Brazil
Canada
China
Iraq
Kazakhstan
Kuwait
Norway
Nigeria
Russia
Saudi Arabia
US
UK
Yemen
Source: Hays 2013 Oil & Gas Salary Guide
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DECEMBER 2013
Local worker
Imported worker
163,600
111,000
123,000
68,300
47,200
41,900
114,400
152,600
55,100
57,900
86,500
121,400
93,400
35,100
171,000
131,400
122,500
161,400
124,500
117,200
79,700
128,600
140,800
151,100
81,000
123,800
93,100
97,300
shortage has become a mainstream
issue, has launched programs to try
and attract workers to move north of
the border, with Alberta and other key
oil-producing provinces at the
forefront of a strategy to recruit from
the US.
Canada’s Petroleum Human Resources
Council says that as many as 38,700 new
positions may have to be filled by 2022
to drive the planned expansion of oil
sands and shale. Cheryl Knight,
executive director of the Council, said
that to achieve this workforce growth the
industry will actually need to find
between 125,000 and 150,000 new
workers by 2020. “The result is that
labor shortages will persist throughout
the coming decade … Skills shortages
are critical and every sector will be
affected. There are not enough workers
with the needed experience and
qualifications.”
Estimates for labor requirements in
Australia are similarly stark.
Government agency Skills Australia
estimated in 2012 that the country
would need an additional 73,000
employees by 2014 to deliver resource
projects alone. As a result, labor input
costs are likely to remain a key source of
overall project cost inflation – already a
serious issue for the country’s massive
LNG expansion.
In the UK, such thinking continues to
color current discourse regarding the
industry’s labor outlook. Kevin Forbes,
CEO of North Sea technical recruiter
oilandgaspeople.com, believes that the
UK’s upstream industry faces problems
unless adequate replacements are found
to quickly replace the skilled workers
approaching retirement.
OIL & GAS UPSTREAM
“The industry specialisms that are most
hard to fill are those with an aging
workforce. It’s no surprise that
geoscientists and drilling specialists are
hard to recruit as these key workers are
retiring in large numbers,” he said in
May, reviewing estimates from his
organization that the North Sea’s oil and
gas industry alone will need to find
120,000 new staff over the next 10 years.
Gordon Taylor, a UK-based director of
the Subsurface Division at project
consultancy RPS Energy, told Platts that
while the estimate of 120,000 or more
new staff needed to keep the North Sea
running might be on the high side, there
is certainly demand for new people to
work in the industry. “The skills shortage
is definitely a huge issue for technical
consultancies and engineering firms
everywhere. We are a global firm that is
seeing the effects.”
Negative perceptions
Part of the problem is that the industry
competes against other well remunerated
technical sectors for what is generally
perceived the world over to be a too
shallow pool of graduates in the STEM
subjects – science, technology,
engineering and mathematics. The legacy
of the 1980s – negative perceptions
surrounding the oil and gas industry and
its volatility – contributed to fewer such
graduates actively choosing to enter the
sector over the succeeding decades.
“Price fluctuations may imply a ‘bust’ in
the near future, which makes it difficult
to entice new workers into the job market
– even in prosperous times,” said Katie
Hester, a Deloitte energy consultant.
“After downsizing in the 1980s and early
1990s, many young engineers entered the
tech sector instead of oil and gas.”
WHICH ROLES ARE IN HIGHEST DEMAND?
Geologist 2.4%
Contract
Administrator
9.4%
Drilling 9.4%
Engineer 52.6 %
Project manager 26.1%
Source: Air Energi/oilcareers.com Global Oil and Gas Workforce Survey
The result is that tech companies
employ a large share of these younger
skilled engineers, while the oil and gas
sector has many middle-aged workers,
with an average age pushing 50. In the
US, nearly two-thirds of the labor
force is 50 years old and over while
only 12% is under 35 years old,
meaning there is only one young
professional for every four
approaching retirement, according to
Hays.
Particularly amongst the younger
generations there may also be a serious
image problem insofar as the industry
– despite being cutting edge in so
many ways, and a critical part of the
world economy – suffers from being
“uncool” or even worse, firmly on the
wrong side of the environmental
argument; part of the problem not the
solution to global warming. As a
Deloitte study from the mid-2000s put
it, “For many Gen-Yers, employment
in the oil and gas industry, in its
current state, is likely not acceptable in
their social networks.”
Ź
DECEMBER 2013
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OIL & GAS UPSTREAM
COUNTING THE COSTS
Labor costs for upstream oil and gas projects
can, at the top end, amount to more than half
total project costs, depending on the type of
project, location and configuration. According
to a report by consultants McKinsey, a
conventional LNG liquefaction plant in
Australia – where labor costs have been at
the very top end of the global league – would
comprise project management labor costs of
17%, construction labor 17% and
engineering labor 10%, amounting to 44% of
total project costs.
Absolute project costs vary enormously
between locations, depending on factors such
as salary levels and labor productivity. The
Business Council of Australia estimates that
project costs in Australia are 40% higher than
for comparable projects in the US Gulf Coast.
In particular, the relative cost of offshore oil
and gas developments is extreme – some
200% higher for offshore platform and
pipeline components.
Labor costs have been and are expected to
remain the fastest rising input cost for
projects. Australian publication Macromonitor
says labor costs in Australia rose annually by
5.2% between 2001-2006, by 7.0% between
2006-2011 and are forecast to increase
annually by 5.8% through to 2021. According
to Independent Project Analysis, a consultancy
employed by the Australian government to
research the labor market, both salaries and
productivity are at fault. Labor costs are
17.5% higher in terms of salaries, but
Australian projects require 30-35% more
labor input than a comparable project on the
US Gulf Coast.
Canadian oil sands projects can be even more
labor intensive. Peter Howard, CEO of the
Canadian Energy Research Institute, said in
July 2013 that the cost for an in-situ project
had risen by 6.3% compared with 2012 to
C$47.57 ($46.35)/barrel, an integrated
mining facility (with an upgrader) by 10.9% to
C$99.02/b and a stand-alone mine by 13.2%
to C$68.30/b. For an oil sands venture, labor
accounts for 60% of project cost, he said,
while the remaining 40% is materials and
equipment.
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DECEMBER 2013
Still, Hays’ 2013 report suggests that at
least some of the measures that have
been taken to attract fresh young talent
have been effective. “In 2012 we
reported a large influx of new and
experienced hires into the oil and gas
industry. This saw record numbers of
people in the zero to four years
experience bracket.”
But even if substantial amounts of new
people are being attracted into the
industry, it still leaves the significant
problem of a lack of experience to fill
more senior posts in the short and
medium term – the kinds of people
crucial to lead projects effectively and
ensure the continuity in working cultures
that can be crucial to maintaining
standards, particularly all-important
safety standards.
“The concept of succession planning and
accelerated leadership development is of
critical importance. Board members are
increasingly concerned about the next
generation of leaders as well as the
tactical steps being taken to develop these
leaders. This, combined with the transfer
of tacit knowledge from moreexperienced employees to lessexperienced employees, is creating an
increase in demand for mentoring and
coaching programs in support of
accelerated leadership development,” said
Deloitte in its 2012 study.
The UK – widely regarded as the
technological leader in subsea
technology – has been particularly
affected by the global nature of the oil
and gas labor market, according to
Hayes, which said the drain of talent to
overseas markets has intensified the
skills shortage in the North Sea.
Fast-expanding areas in the global
upstream like Australia, Brazil, East
Africa and the Middle East are all
grappling with their own skills deficits
and make for lucrative destinations for
those prepared to travel.
So how worried should the industry be
and what steps is it taking? There are
certainly surveys that suggest the
situation is not as woeful as some seem
to fear.
“Overall, hiring activity in Canada is at
a measured pace for the moment,” said
oilcareers.com, which it put down to
“ongoing uncertainty surrounding
Canada’s nearly maxed-out pipeline
capacity, which has operators asking
whether to increase production or
maintain current levels.” It also
reckoned that the US was “reasonably
stable” with the country having “a
relatively solid domestic pool from
which to recruit for the moment.” It
described the market as “a candidates’
market” though, and wondered what
the future might hold as LNG projects
there get into full swing.
Malcolm Webb, CEO of Oil and Gas
UK, the offshore North Sea industry’s
trade body, said he was confident the
industry would quickly address the need
for newly qualified people. “Remember,
this is an industry that grew out of
nothing. We are a can-do industry, facing
up to this issue,” he said in a May
interview on BBC Radio 4.
Some steps have of course been taken
already. The UK government,
recognizing the problem at the
beginning of the century, has made
progress in channeling graduates into
the field. In 2000, the government
formed PILOT, a joint task force with
OIL & GAS UPSTREAM
the private sector to help ensure the
industry’s long-term future. Oil and
Gas UK’s 2013 economic report notes
that since PILOT’s inception, the
North Sea workforce has increased by
100%.
Among other initiatives are efforts by
OPITO, the UK-based Offshore
Petroleum Industry Training
Organization, to forge close ties with
the military aimed at attracting the
18,000-20,000 services personnel
discharged annually, along with
workers looking to leave the police
force, automotive and aviation
industries, many of whom have skills
transferable into the oil and gas
industry. Similar efforts to tap exservices people have been launched in
other countries, such as the US’s
Veterans to Energy program.
Money isn’t everything
But although programs such as these
bring motivated staff with transferable
skills into the industry, the specialist
skills still have to be learnt – or to be
more precise, taught. Effective training
is one way companies can attract and
retain people with the necessary skills,
but a survey by the Society of
Petroleum Engineers found that nearly
two-thirds of respondents said they
were still awaiting technical training
that they felt they should already have
received.
Some companies, recognizing the need to
gain an edge over their competitors, have
invested heavily in training programs as
well as in talent acquisition and retention
but there is a big gap to bridge.
According to oilcareers.com, graduate
training programs established by some of
the larger companies are still “not
yielding the volumes of personnel
required to top up the rosters of today’s
mega projects.”
Companies can also, as they seem to be
having to do, pay higher wages to
“fight for talent,” but there are obvious
downsides to being involved in a
spiraling bidding war for human
resources.
Not that money is everything. While the
majors are able to pay a premium to try
and attract the very best, remuneration is
not the only factor that the kind of
highly motivated, skilled people that are
most in demand weigh when they have
an array of choices, as they do in the
current market.
“Large salaries are having less influence
on a candidate’s next career move,
instead challenging projects in new areas
such as the Barents Sea provide greater
appeal to those who feel explorers at
heart,” said Michael Kenway, the
Norway country manager for global
recruitment specialist Hydrogen
following Norway’s latest licensing
round, which has brought a number of
“pioneering prospects” such as the giant
Johan Sverdrup find into companies’
drilling crosshairs.
Meanwhile, on the flipside of this
enthusiasm to develop a new generation
of engineers, specialists and
geoscientists, there are also concerns
that the drive could go a little too far
– especially if oil prices don’t hold at
the historically high levels we have seen
for much of the past decade. That
“boom/bust cycle inherent in the oil
and gas sector” lingers in people’s
memories even if oil prices have been
exceedingly resilient in the face of
widespread economic turmoil over
recent years.
While it is highly probable, barring some
sort of great leap forward for alternative
energy sources, that oil and gas will
remain critical to the global economy for
many years to come, continued
discoveries and new production amid an
uncertain demand picture and stiffening
competition from renewable resources
mean there is always the possibility of
prices falling again.
But industry veterans like RPS Energy’s
Taylor point out that there is considerable
downside to prices before the industry
might start contracting again. “Most of
my career we’ve been dealing with $30 oil
and cheaper. So even if the price declines
20-30% to $70-80, it’s still good for the
industry – though the economics of shale
might prove to be a different story,” he
said. Another veteran, Jeff Sundquist, who
now represents the province of Alberta at
the Canadian High Commission in
London and also chairs a Canada-UK
energy forum, was philosophical on the
topic of skills shortages: “Ultimately, it is
important to remember that the market
will dictate how everyone responds.”
And that perhaps is the key point.
Whatever the issues with finding people,
production of oil and gas has surged in
various parts of the world. The US has
raised output of oil and gas by record
amounts in recent years and it is hardly
the only major boom player in global oil
and gas production. The industry, despite
always having to keep one eye anxiously
fixed on the horizon because of its long
project lead times and vast investments,
has always had to adapt to the current
market conditions – and has proved itself
capable of doing so time and again. Ŷ
DECEMBER 2013
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SPECIAL ADVERTISING SECTION
INDUSTRY LEADERS SHARE INSIGHTS
GLOBAL ENERGY AWARDS FINALISTS ASSESS THE LANDSCAPE
Charting course for a global energy company is never easy, but today’s shifting landscape is challenging even the most
seasoned of executives. The shale revolution continues to send shock waves through markets as the United States this year
becomes a net exporter of oil for the first time since 1995. Renewable power sources keep coming online despite recent
bumps in the road. Midstream and downstream operators are making bold maneuvers to satisfy users who’re increasingly
switching to different fuels. To hear how leading companies are assessing today’s challenges, Platts reached out to seven
finalists in the 2013 Platts Global Energy Awards. Here’s what they’re saying:
Questions and answers have been edited for clarity and brevity.
Q: Can renewables compete with cheap, abundant natural gas to become a bigger staple of the US energy mix?
Kevin Smith, CEO of SolarReserve: In 2012, almost 50% of all new power generation in the US was from renewables.
As a percentage of new projects, renewables are the only thing competing with natural gas right now in the US. Nuclear
and coal really can’t compete either on a cost basis or on an ability to get projects permitted.
Q: How is solar storage technology affecting international interest in solar?
Kevin Smith, CEO of SolarReserve: It definitely is a game changer. At our flagship project in Nevada, which will go
into commercial operation next year, solar with energy storage can operate just like conventional power. We can turn it
off and turn it on when we want. We’re seeing a huge amount of interest in that storage technology internationally.
We’ve probably had 30 different countries visit our Nevada facility in the past 18 months.
Q: Where are midstream and downstream companies filling gaps in transportation infrastructure to address
shifting trends in energy consumption?
Graham Sharp, Chairman of Puma Energy: There’s much greater need in developing countries for infrastructure,
whether it’s in terminals, logistics supply or even gas stations. So we’ve been investing across that sector quite heavily and
building that infrastructure to first-world standards. Some of Puma’s expansion has been through the acquisition of assets,
such as Exxon Central America, which we purchased in 2012, or BP Southern Africa, which we purchased in 2011.
Q: Why are refineries closing? And how is that affecting midstream investments in infrastructure?
Graham Sharp, Chairman of Puma Energy: In Europe, most refineries were built to produce the maximum amount of
gasoline, but the demand there today is for diesel. Same in Australia: all the demand growth is in diesel. There, refineries
are closing one by one, so the amount of imported petroleum products is greater. There’s a need for more infrastructure,
so we’re building a large terminal up in Queensland.
Q: How are fuel consumption trends affecting strategic decisions at upstream firms?
Chris Faulkner, CEO of Breitling Oil and Gas: Climate gurus are squabbling over whether nuclear should play a role after
Fukushima. Germany, spooked by that nuclear disaster, is getting wistful over coal again; Poland is digging its heels in on
coal; and Japan and Australia are backpedaling on their Kyoto commitments. All of this furor will result in a brighter outlook
for global gas consumption. We prefer an oil-weighted portfolio of low-risk development assets for the next few years.
Q: Which strategic steps of recent years are paying biggest dividends for upstream North American operations?
Chris Faulker, CEO of Breitling Oil and Gas: Companies that recognized the shift in drilling focus to oilier plays or
who already had a good mix in their portfolio were able to better weather the transition from natural gas and NGLs to
crude oil and condensate. Add to that a focus on keeping capex closer to cash flow, or at least keeping debt service within
reason, and those are the companies thriving today.
Q: What does the shale revolution mean for companies worldwide in the exploration & production space?
Al Walker, President, CEO & Chairman of Anadarko: We’re excited about the opportunities this may create to take
the expertise and technology that has been developed in the United States and apply it internationally. We’re still very
early in the process of evaluating international shale opportunities. We are optimistic it can become a longer-term option
for developing regions and established economies.
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DECEMBER 2013
Q: Large-scale fuel purchasers are making new types of decisions in today’s shifting energy landscape. More, for example,
are using natural gas for power plants. How are shifting demand trends impacting upstream strategies and operations?
Al Walker, President, CEO & Chairman of Anadarko: Until demand catches up with this newfound supply, we do see
commodity prices for natural gas being range-bound, and we’re actively managing that within our portfolio. Anadarko’s in
the fortunate position of having assets that offer higher liquid yields in the US onshore where we can efficiently deploy
capital and generate higher rates of return, while maintaining the option of increasing activity in more natural-gas prone
plays as commodity prices adjust.
Q: What needs to happen downstream in order to more effectively bridge the US shale boom?
Rick Bott, President and Chief Operating Officer at Continental Resources: There’s only one Bakken. The light,
sweet crude produced in the Bakken has numerous qualities attractive to refiners – very low sulfur, consistent API gravity
and high quality refining yields to name a few. Bakken can be delivered to all three coasts, the Midcontinent and
Canada. Refiners have taken notice and are investing in additional light, sweet processing capacity to run more Bakken
outright or as blendstock for heavy-sour crudes. The demand for Bakken extends globally. Were the US to remove export
barriers, our trading partners in Asia, South America and Europe would be able to efficiently refine Bakken crude and
deliver refined products back to the United States.
Q: How are power industry players using new tools to help them manage emergent risks?
Paul Cusenza, CEO and Chairman of Nodal Exchange: Power industry executives are looking at many questions
around shale gas, renewables, nuclear and coal. With all these unknowns, how do you know what your revenues will be
in 2014? If you want to remove the price risk, we help with that by enabling entities to hedge that risk. You can do that
now at your pricing node on the electric grid with a granular futures contract on Nodal Exchange where all contracts are
cleared to address the credit risk as well.
Q: Where are marketplace innovations removing roadblocks to help executives make better decisions?
Paul Cusenza, CEO and Chairman of Nodal Exchange: In the past, cleared power contracts were only offered at the
hubs. It didn’t really meet the needs of power companies. They were still exposed to significant price risk at their locational
node. Prior to the creation of Nodal Exchange, nobody cleared nodal contracts.
Q: How are upstream and midstream firms exploiting more abundant natural gas supplies?
Kristian Rix, deputy director for international communication at Repsol: The conversion from coal to natural gas in
power plants told us that gas was going to be more in demand. LNG technology was allowing you to transport it from
one continent to another. So we’ve built up a position on both sides of the Atlantic and also on the Pacific. We built a
terminal in Peru, which was key to supplying Japan when its nukes were shut down after the earthquake.
Q: What strategic steps are smaller exploration-and-production companies taking to generate cash for
capital-intensive exploration projects?
Kristian Rix, deputy director for international communication at Repsol: We have the highest exploration spend, per
barrel produced, amongst integrated oil and gas companies in the industry. We’re generating that cash by bringing
projects online, such as the big Brazilian offshore fields and Bolivian fields. We also upgraded all of our refining system in
Spain by investing around $5 billion. So we’ve increased our capacity to provide high-value fuels in Europe, which is very
diesel-hungry.
CNOOC
In the past year, CNOOC Limited made significant progress in all aspects of business and maintained a good
performance. In addition, the Company is committed to enhancing the capability for sustainable development. The
nomination of Platts Global Energy Award is undoubtedly a prestigious recognition to CNOOC Limited as well as a
great motivation to drive its future growth. The Company will work even harder in the future to maintain its high
standard of corporate governance and leadership practice. Looking ahead into 2014, with the continuous support from
stakeholders, CNOOC Limited will dedicate more efforts to transform itself into a global energy company, supply more
energy to the world, and make greater contributions to the communities and society.
KOSPO
Our vision is to become one of the world`s leading power generation companies. Korea Southern Power, Ltd. is ready to
run at full speed in a future race to the world. We will strengthen differentiated competitiveness to realize tomorrow`s
vision today. And this moment, executives and employees in our company try to change ahead and always try
renovation. First of all, we take opportunity in the market by competitive preference of production, sales, technology.
Then we will become a blue chip company that leads market standards with efficiency, responsibility, profitability and
competitive corporate culture. This is our ambition.
DECEMBER 2013
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SPECIAL ADVERTISING SECTION
GLOBAL LEADERS PROFILE
Al Walker
Chairman, President and CEO
Anadarko Petroleum Corporation
Anadarko Petroleum Corp.
Anadarko is among the world’s largest independent oil and
natural gas exploration and production companies, with 2.56
billion barrels of oil equivalent (BOE) of proved reserves at
year-end 2012. Anadarko employs more than 5,300 people
worldwide and possesses a deep and balanced portfolio
encompassing positions in liquids-rich US onshore resource plays
in the Wattenberg field, Eagle Ford Shale and Permian Basin,
among others. We are among the industry’s most successful
deepwater explorers with production and/or exploration in the
Gulf of Mexico and approximately 15 countries including Algeria,
Brazil, Ghana, China, and Mozambique.
Anadarko’s Mission
Anadarko’s mission is to deliver a competitive and sustainable
rate of return to shareholders by exploring for, acquiring and
developing oil and natural gas resources vital to the world’s
health and welfare. Anadarko is committed to finding and
producing the energy our world needs, overcoming challenges
through engineering, science, technology and talent.
As a recognized leader in deepwater exploration, the company
effectively transfers the skill sets and experience to proven
basins worldwide. Once a commercial discovery has been
made, Anadarko has a track record of bringing large projects on
stream, on schedule and within budget.
Anadarko’s Commitment
With Anadarko’s world-class projects, inspiration isn’t hard to find.
Recent accomplishments include the startup of oil production at
the El Merk project in Algeria, natural gas discoveries that rank
among the world’s largest in Mozambique’s deepwater Rovuma
Basin and the advancement of sanctioned large-scale projects in
the Gulf of Mexico at Lucius and Heidelberg.
Anadarko’s Operations
Additionally, Anadarko has been recognized on numerous
occasions for its safety programs and environmental
performance. Ranked among Forbes Magazine’s Most
Innovative Companies and a Top Workplace according to
Workplace Dynamics, Anadarko has earned three Earth Day
Awards from the Utah Division of Oil, Gas and Mining, and
three consecutive Excellence Awards for environmental
performance and community engagement from Colorado’s Oil
& Gas Conservation Commission. The company also is
regularly among those honored by Platts at its annual Global
Energy Awards. Consistent with its commitment to continuous
improvement and open communication, Anadarko also has
played leading roles in several industry initiatives aimed at
greater transparency and accountability.
Anadarko’s US onshore resource plays provide the solid, lowerrisk foundation that enables the company to seek higher-impact
projects in global deepwater basins. The company utilizes
innovative technology and industry-leading practices to safely
enhance drilling and completion techniques, increase well
productivity, reduce costs and improve environmental
performance from a balance of liquids-rich and natural gasbearing formations in the US. In the deepwater Gulf of Mexico,
We believe energy is fundamental to modern life, and oil and
natural gas are foundational to a secure and reliable energy
future. We take our responsibility seriously to deliver resources
to our energy hungry world, and firmly believe we employ the
right people, the right values, the right portfolio and the right
strategy to safely accomplish our mission and meaningfully
contribute to the world’s health and welfare.
Anadarko recognizes that delivering on promises to
shareholders requires exceptional assets and a highly skilled
work force engaged in a shared vision. We seek employees with
a passion for finding and producing energy resources that desire
an entrepreneurial work environment, strive for excellence and
continuous improvement, and live the company’s core values of
integrity and trust, servant leadership, commercial focus and
open communication.
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Anadarko’s vast infrastructure and expertise provides the ability to
economically develop new discoveries and continually generate
value through the company’s “Hub-and-Spoke” philosophy.
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DECEMBER 2013
SPECIAL ADVERTISING SECTION
GLOBAL LEADERS PROFILE
Jeanne Schwartz
Vice President, New Venture Commercialization
Assurant, Inc.
Assurant, Inc.
Assurant’s Solar Group
Assurant’s solar group helps solar project developers and
investors protect what matters to them most – their financial
investment in their renewable energy projects. Founded in
2011, Assurant’s solar group provides innovative insurance and
risk management solutions to protect the financial health of
residential and commercial solar projects throughout the project
lifecycle. A key part of this protection is Assurant’s industry
leading warranty management program. This coverage
authorizes and pays claims, labor and shipping replacement
parts on any warrantied equipment even after an original
equipment manufacturer goes out of business. By providing a
single point of contact for all warranty components, the
warranty management program makes it easier to maintain solar
projects throughout their projected lifespan.
Assurant Solar Project Insurance and the largest solar installation
in the Springfield-Dayton, Ohio area. This insurance bundle of
property and liability coverage with a warranty management
program was the first and only solar project insurance geared for
commercial-sized solar projects between 100KW and 3MW.
Importantly, it was co-developed with industry participants to
ensure that it included important benefits sometimes overlooked
by less specialized insurers such as:
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Business interruption coverage when a component is damaged and not producing energy;
Single point of contact for all components, regardless of
original equipment manufacturer (OEM), and even if that
OEM is no longer in business;
Claims authorization, payment and management of any warranty claim; and
Coverage for de-installation labor, shipping costs and reinstallation of warrantied components.
Helping Customers Protect What Matters Most
Assurant’s solar group is a part of Assurant, Inc., a Fortune 500
company and a member of the S&P 500 with approximately $29
billion in assets and $8 billion in annual revenue. Assurant is
distinguished by its leading positions in specialty insurance
businesses. Although each business is unique and diverse, all share
three common strengths: risk management expertise, strong
distribution partnerships and administration of complex processes.
Assurant is steadfast in helping protect what matters most to
consumers and upholding the company’s enduring values:
Common Sense, Common Decency, Uncommon Thinking and
Uncommon Results. These values are exemplified by Assurant’s
solar group in the work completed on behalf of customers and
in support of the solar industry.
Assurant’s solar group strategy is focused on helping clients
reduce their financial risks and develop new solar projects to
grow the solar industry. To understand the unique needs and
pain points of solar project developers, Assurant became a solar
customer to experience what it was like to develop its own solar
project. This research effort was critical to the launch of
Since then Assurant’s solar group has expanded its offering to
provide protection for residential projects and develops
customized protection plans based on client needs. Coverage is
“right-sized” and tailored to fit individual projects, eliminating
excess coverage and inflated insurance costs that traditionally
prevented developers and investors from securing needed
insurance protection. This flexibility allowed Assurant’s solar
group to develop an insurance and warranty solution for
Connecticut’s Clean Energy Finance and Investment Authority
(CEFIA), the country’s first green bank, when it launched a
new $60 million residential solar leasing program for state
residents this year.
Under the leadership of Assurant’s Vice President of New
Venture Commercialization Jeanne Schwartz, the business is a
leading innovator of solar insurance products. Assurant’s solar
group also is an important contributor to risk management
efforts in the solar industry by leveraging the company’s deep
insurance knowledge and expertise in delivering high-quality
service offerings to clients. For more information about
Assurant’s solar group, visit www.assurantsolar.com.
DECEMBER 2013
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SPECIAL ADVERTISING SECTION
GLOBAL LEADERS PROFILE
Chris Faulkner
Chief Executive Officer
Breitling Energy
Breitling Energy
Based in Dallas, Texas, Breitling Energy was founded on the
fundamental principles of applying state-of-the-art petroleum
and natural gas exploration and extraction technology to the
development of onshore oil and natural gas projects. Breitling’s
focus areas include Texas, Oklahoma and North Dakota.
Breitling offers oil and gas investment opportunities through
direct participation programs and oil and gas direct
participation working interest which enable investors to
participate in the potential cash flow and unique tax benefits
associated with oil and gas investments. Especially important in
a downturned economy, oil and gas investments allow savvy
investors to diversify and reinforce their investment portfolios
with a stable commodity that is in steady demand.
Breitling Energy is a large independent (non-integrated) oil and
natural gas company in the US with proved reserves
throughout most major basins in North America.
Breitling’s exploration activities are focused on adding profit
generating production to existing core areas and developing
potential new core areas. Breitling’s production operations
supply liquid hydrocarbons and natural gas to the growing
world energy markets. Worldwide production operations are
currently focused in North America.
Breitling Energy’s primary goal is to increase the value of
acquired properties through a combination of exploitation,
drilling and proven engineering extraction practices, with its
most significant emphasis on CO2 tertiary recovery operations.
As part of the Company’s corporate strategy,
Breitling believes in the following fundamental
principles:
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Acquire oil and gas properties that provide a majority working interest and operational control or where it can ultimately be obtained.
Maximize the value of these properties by increasing production and reserves while controlling cost.
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DECEMBER 2013
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Maintain a highly competitive team of experienced and
incentivized personnel and engineers.
Remain focused in specific regions where Breitling has a
competitive advantage as a result of its ever expanding infrastructure, or where it can ultimately be obtained.
Acquire properties where additional value can be created
through secondary and tertiary recovery operations and a
combination of other exploitation, development, exploration
and marketing techniques.
Chris Faulkner, Founder, President and Chief Executive Officer
Breitling Energy, drives the company’s long-range economic
and energy outlooks, which serve as the basis for strategic
planning as well as investor relations, short and long-term
business strategy, mergers and acquisitions, and the
development and application of new and existing technology
for optimizing recovery efficiency within Breitling’s
conventional and unconventional resources.
His diverse and extensive background in the oil and gas industry
covers all aspects of oil and gas operations, including project
management, production, facilities, drilling and business
development. Mr. Faulkner serves as an advisor to the ECF Asia
Shale Committee and sits on the Board of Directors for the
North Texas Commission. He has been featured in numerous
media outlets. He is a frequent lecturer at industry events and is
a member of many industry organizations, including the Texas
Alliance of Energy Producers, the Dallas Petroleum Club,
Independent Petroleum Association of America, Texas Alliance
of Energy Producers and Texas Independent Producers and
Royalty Owners Association. He is actively involved in local and
national philanthropic and non-profit organizations, including
Dallas Performing Arts, Texas CAN-DO, American Heart
Association and Big Brothers Big Sisters.
Mr. Faulkner studied biomedical engineering at Southern
Methodist University, business and mathematics at Baylor
University and at the University of North Texas. He received an
honorary doctorate degree for his achievements in business
administration from Concordia College.
SPECIAL ADVERTISING SECTION
GLOBAL LEADERS PROFILE
Li Fanrong
Chief Executive Officer
CNOOC Limited
CNOOC Limited
CNOOC Limited (the “Company”), incorporated in Hong
Kong in August 1999, was listed on the New York Stock
Exchange (code: CEO), The Stock Exchange of Hong Kong
Limited (code: 00883) and the Toronto Stock Exchange (code:
CNU). The Company has been selected as a constituent stock
of the Hang Seng Index, Hong Kong, since July 2001.
The Company is China’s largest producer of offshore crude oil
and natural gas and is one of the largest independent oil and
gas exploration and production companies in the world. The
Company mainly engages in exploration, development,
production and sales of oil and natural gas. In addition to its
major domestic operation areas in offshore China, CNOOC
Limited has greatly extended its global presence in overseas and
raised its international profile in recent years.
Core competencies
As a large E&P company, we have a large and diversified asset
portfolio across offshore China and globally. This diversified
portfolio provides tremendous growth opportunities for us. We
have been uniquely benefited by inheriting our parent
company, CNOOC’s exclusive right to explore and develop oil
and gas in offshore China in cooperation with foreign partners,
and have developed our leadership position in offshore China.
Our experienced management team has a proven track record
on execution, which is clearly demonstrated by our historical
growth. We have strong project management and cost control
capability and maintain strong track record of completing
projects on time and on budget. We also have a stable, highly
motivated workforce with strong technical expertise.
Enhancing our international profile
This year, the Company has accomplished a number of
milestones in overseas expansion.
The acquisition was the largest one of its kind made by Chinese
companies and has become an important milestone on the
Company’s road of internationalization.
The acquisition of Nexen was completed on February 26,
2013. The transaction has not only brought rich resources and
diversified asset portfolio for the long term development of the
Company, but also veteran management and staff of Nexen
who have extensive working experience in major oil and gas
producing areas around the world.
On September 18, 2013, CNOOC Limited began trading on
the Toronto Stock Exchange. Listing on the TSX represents our
continuous commitment to maintaining transparency and
good corporate governance in the countries where we operate.
On October 22, 2013, as part of a consortium, the Company
has been awarded a 35-year production sharing contract to
develop the Libra pre-salt oil discovery in the Santos Basin,
offshore Brazil. The participation of CNOOC Limited in Libra
project not only signifies the milestone of a strategic entry into
ultra-deepwater field for the Company, it also aligns with our
philosophy of seeking partnerships to expand our global
footprints.
Outlook for 2014
Looking ahead into 2014, CNOOC Limited will continue to
dedicate its efforts to the transformation of the Company to a
global energy company, supply more energy for the world, and
make greater contributions to the shareholders, communities
and the society.
2012 key statistics
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In July 2012, CNOOC Limited announced the acquisition of
Nexen Inc. (“Nexen”) at a consideration of USD15.1 billion.
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Oil and gas production: 342.4 million BOE
Net proved reserves: approximately 3.49 billion BOE
Total revenue: RMB247.63 billion
Total Assets by year end: approximately RMB456.07 billion
Employees: 10,063
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SPECIAL ADVERTISING SECTION
GLOBAL LEADERS PROFILE
Harold Hamm
Chairman and Chief Executive Officer
Continental Resources
Continental Resources
Continental Resources is a Top 10 independent oil producer
in the United States. Based in Oklahoma City, we are the
largest leaseholder and producer in the nation’s premier oil
field, the Bakken play of North Dakota and Montana. We also
have significant positions in Oklahoma, including our recently
discovered SCOOP play and the Northwest Cana play. With a
focus on the exploration and production of oil, Continental is
on a mission to unlock the technology and resources vital to
American energy independence.
America’s Oil Champion
Since our inception in 1967, exploration has been a key
component of Continental’s success. Our teams continue to
explore and find new crude oil sources, applying enhanced
horizontal drilling and completion technologies to drive
production growth and help shape America’s energy future.
For several decades, the conventional view in America was one
of energy scarcity, we were running out of domestic oil and
natural gas, and our only path was to increase imports as the
country’s demand grew.
Recently this view began to change, first as the majority of
domestic energy producers shifted their focus to natural gas
shale development. Understandably so: the resource is
plentiful, found in numerous basins and production is
growing. However, Continental did not follow suit. Instead,
we took a contrarian view and forged our own path looking
for large, crude oil-dominated plays.
largest contiguous oil fields discovered worldwide in more
than 40 years.
More recently, we’ve seen further benefits of exploration
success in our own backyard with the discovery of the South
Central Oklahoma Oil Province, or SCOOP, as we named the
new oil- and condensate-rich resource play. Our subsurface
exploratory teams continue to bring their entrepreneurial spirit
to the hunt for new resource plays.
Clear Vision of Growth
As we expand the Continental team, we’re working hard to
communicate the values and strengths behind Continental’s
46 years of success. Exploration, hard work and industryleading growth are essential to our DNA.
In October 2012, Continental unveiled a new 5-year plan to
once again triple both production and proved reserves. This
would represent 300,000 Boepd of production, establishing us
solidly as the only super independent exploration and
production company whose production is 100% domestic.
At Continental Resources, our team understands what
challenging conventional wisdom can accomplish. We are
proud to call Continental America’s Oil Champion. It’s a
pledge that Americans can solve our own energy challenges.
At Continental, we’re proving it every day.
Statistics
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Entrepreneurial Spirit
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As a first mover, experimenting and deploying the cuttingedge technology of today, we demonstrated the Bakken’s
massive resource potential early on, allowing us to amass the
play’s most commanding position. We continue expanding
and extending the play, which is now recognized as one of the
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Producing more than 150,000 Boe per day as of Nov. 2013
Proved Reserves of 922 MMBOE as of Mid-Year 2013
Concentrated on Crude Oil (71% of Production)
Cash Margin of 76% and $59.54 per Boe in 3Q13
#1 Leaseholder and Producer in the Bakken
#1 Leaseholder in the SCOOP
Market Cap of $21 Billion
NYSE CLR
CLR.com
SPECIAL ADVERTISING SECTION
GLOBAL LEADERS PROFILE
Sang Ho Lee
President and CEO
Korea Southern Power Corporation Limited
KOSPO
the first and biggest of its kind in the world to be dedicated to low
rank coal combustion. It is currently under construction with a
completion date targeted for 2015.
History
KOSPO was divided from Korea Electric Power Corporation
(KEPCO) in 2001 and has grown into the largest thermal
power generation company in Korea in terms of total
generation capacity, and sales volume and revenue. KOSPO has
also become the most domestically renowned energy company
through the highest thermal efficiency of its power plants and
its premier position in renewable energy developments.
Vision & strategy
KOSPO declared a vision statement of “Global Top 10 Power
Company” as its new future strategy. With the core strategy of
cost reduction and efficiency enhancement as its foundation,
KOSPO established a new strategic system to attain such a
vision. This new system has paved the way for KOSPO to
maintain its position as the front-runner among Korean and
international power companies, and to establish a sustainable
growth plan through the diversification of business areas.
KOSPO is your best partner for overseas business and actively
developing new overseas projects through its excellence in
Commissioning and O&M know-how for power plants. KOSPO
is demonstrating its advanced technologies in power generation to
the world through multiple projects including a combined cycle
commissioning in Qatar Ras-Laffan, gas turbines commissioning
in Samla, a O&M project in Jordan, a commissioning in India
Vemagiri, Marafiq Project commissioning in Saudi, wind power
commissioning in Israel Rotem. And we are developing new
overseas projects all around the world, such as in Vietnam, Chile,
Turkey, India, etc. We aim to become not only a leader in Korea,
but a global partner for all electricity needs.
KOSPO’s strengths
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Management principle
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Through supplying stable power, accumulating innovative
technologies, creating future growth engine, innovating
organizational culture, and fulfilling social responsibilities,
KOSPO is realizing “Growth of Technology & Value” and is
taking a leap to be the global top 10 power company to lead
the world’s energy technology.
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Domestic business
KOSPO is contributing to national economic growth with best in
class plant operating capability and maintenance technology.
KOSPO has achieved a top-ranked performance and the first 6.9
billion USD sales among Korean generating companies in 2012.
KOSPO has a total generation capacity of 9,240 MW and recorded
63,393 GWh gross generation in 2012. KOSPO made groundbreaking improvements to Circulating Fluidized Bed Combustion
(CFBC) technology to adjust the range of combustible fuels from a
previous level of 6,080 kcal/kg down to 3,750 kcal/kg level coals.
Currently, the 1,000 MW capacity Samcheok Green Power Plant is
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Overseas business
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DECEMBER 2013
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New Concept Fluidized Bed Boiler System
(1,000 MW capacity)
Generation By-Product Recycle
CCR(Carbon Capture & Reuse)
Power Plant Cycle O&M Technology
Regeneration Technology of de-Nox Catalyst
KOSPO Technology & Project Management Center
For more detailed information, please contact us at :
KOSPO 620, Teheran-ro, Gangnam-gu, Seoul, 135-502,
Korea(zip code : 135-791), Tel : +82-70-7713-8000
http://www.kospo.co.kr
Statistics (as of Dec. 31, 2012)
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Total Employees
Assets
Capital
Liabilities
Electric Power Sold
1,938
7.086 bil. USD
3.743 bil. USD
3.343 bil. USD
61,079 GWh
SPECIAL ADVERTISING SECTION
GLOBAL LEADERS PROFILE
Paul Cusenza
Chairman and Chief Executive Officer
Nodal Exchange
Nodal Exchange
Nodal Exchange is the first commodities exchange dedicated to
offering locational (nodal) futures contracts and related services
to participants in the organized North American electric power
markets. Nodal Exchange builds on the success of the existing
Regional Transmission Organization (RTO/ISO) Real Time
and Day Ahead markets by offering cash settled futures
contracts in a cleared market enabling Nodal Exchange
participants to effectively manage basis and credit risk.
Since its launch in April 2009, Nodal Exchange has grown to
become a significant part of the North American power market,
obtaining a market share of over 27% of all cleared North
American power futures contracts, measured by open interest, as
of October 31st, 2013. Notional value of open positions is about
$15 billion per side and $30 billion in total. Nodal Exchange’s
success is due to many innovations, and, in particular, to its
granular contract offering, which allows participants to create
more effective hedges. Nodal Exchange is the leading market for
power basis trading – across all cleared markets, Nodal Exchange
has an over 50% market share of zonal open positions and a
100% market share of nodal open positions. Nodal Exchange is
continuing its strong growth with year-to-date 2013 trading
volumes more than doubling those for the same period in 2012.
Benefits of Nodal Exchange
Granular Contracts
Nodal Exchange offers ~1,200 cleared power contracts with
~50,000 expiries offering the largest set of cleared contracts for
power. Nodal Exchange offers on-peak and off-peak power
contracts on hundreds of unique locations in the following
organized electric markets: ISO-NE, NYISO, PJM, MISO,
ERCOT, and CAISO. Nodal Exchange power contracts are all
offered in 1MW lot sizes to give participants the ability to
tailor their futures positions to their actual needs.
Product Innovation
Nodal Exchange is constantly evolving its offering to meet the
changing needs of the North American power market. Since
launch, Nodal Exchange has extended expiries out 68 months,
added Real Time power to its suite of Day Ahead power
contracts, introduced contracts in the ERCOT and CAISO
markets, added a Henry Hub natural gas contract, designed
new more granular off-peak contracts, and created the ability to
trade “look-alike” Financial Transmission Rights using new
energy + congestion contracts. Nodal Exchange’s business
model allows for the rapid introduction of new products, and
Nodal Exchange has the flexibility to quickly add granular
locations as needed by Participants.
Credit Risk Management
One of the major advantages Nodal Exchange offers to its
Participants is the full clearing of all trades through its Central
Counterparty (CCP): LCH.Clearnet. LCH.Clearnet is the
leading independent clearing house, serving major international
exchanges and platforms, as well as a range of OTC markets.
With its broad reach, experience, and large capital base, LCH.
Clearnet allows Nodal Exchange Participants to concentrate on
the market itself rather than on counterparty or credit risks.
Capital Efficiency
Nodal Exchange provides effective risk management and
superior capital efficiency through the use of portfolio Value-atRisk (VaR) margining. This robust and effective approach to
margining, which accounts for the correlations between many
different contracts, even across ISOs and different commodities
(e.g., power and gas), results in greater capital efficiency for
Nodal Exchange Participants.
Price Discovery and Market Liquidity
Nodal Exchange provides superior price discovery and market
transparency. Daily marks are provided to participants on
approximately 50,000 expiries.
Nodal Exchange is a designated contract market (DCM)
registered with the US Commodity Futures Trading
Commission (CFTC). Nodal Exchange is an independent,
privately held company. For more information, visit
www.nodalexchange.com.
DECEMBER 2013
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SPECIAL ADVERTISING SECTION
GLOBAL LEADERS PROFILE
Pierre Eladari
Chief Executive Officer
Puma Energy
Puma Energy
Puma Energy is a global integrated midstream and downstream
oil company active in over 35 countries. Formed in 1997 in
Central America, Puma Energy has since expanded its activities
worldwide, achieving rapid growth, diversification and product
line development. The company directly manages over 6,000
employees. Headquartered in Singapore, it has regional hubs in
Johannesburg (South Africa), San Juan (Puerto Rico), Brisbane
(Australia) and Tallinn (Estonia).
Our investment in state of the art storage terminals provides us
with competitive advantage in ensuring security of supply and
fuel quality management.
Puma Energy’s midstream operations support our own
downstream activities. We have developed successful retail,
wholesale, B2B, aviation bunkering, lubricant, bitumen, LPG
and supply businesses across Africa, the Americas, Middle East
and Asia Pacific.
See us online at pumaenergy.com.
Our focus on integrated midstream and downstream activities
means we can achieve significant economies of scale and operating
efficiencies. For our customers this translates into competitive
costs, managed risk, secured supply and seamless delivery.
In the midstream sector, we have 4.6 million m3 of installed
storage capacity.
Puma Energy – Fast Facts:
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All our terminal operations are managed in-house, making us
one of the largest independent fuel storage operators
worldwide, and enable us to control directly a critical part of
our supply chain.
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Our facilities handle approximately 24 million m3 of oil
products per year, both for our own needs, and providing
storage services to 3rd parties.
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DECEMBER 2013
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15th year of operation
Storage capacity of over 4.6 million m3
Over 21 million m3 2012 throughput
More than 1,500 retail stations
Operating in 35+ countries
2012 sales volume: over 8.9 million m3
2012 turnover: USD 8.7 billion
6,000+ people employed directly by Puma Energy
15,000+ people employed indirectly by Puma Energy
More than 8,000 petrol pumps worldwide
Serving 27 Airports
SPECIAL ADVERTISING SECTION
GLOBAL LEADERS PROFILE
Antonio Brufau
Chairman and CEO
Repsol
Repsol
Repsol is an international integrated oil and gas company based
in Spain. Headed since 2004 by Antonio Brufau, it is one of
the largest private oil companies in the world, operating in over
30 countries.
Repsol produces 360,000 barrels of oil equivalent per day. It
operates chemical plants and state-of-the-art refineries, handling 37
million tonnes of crude oil, which is transformed into different
products and distributed at nearly 5,000 service stations worldwide.
Repsol’s performance in the last three years has led analysts to
rate it one of the most attractive companies in the world by
portfolio. In 2013, the company reported 10 oil discoveries
worldwide, achieving its resource incorporation goals for the
whole year six months early and in 2012 Repsol had a reserve
replacement ratio of 204%. Repsol also expanded its refining
portfolio, investing billions to convert its refining system in
Spain, making it one of the most advanced and efficient in
Europe and boasting superlative conversion capacity.
Betting on technology
Repsol believes that investment in technological innovation is
crucial to achieving a more efficient and sustainable energy
system which can keep up with energy demand whilst
guaranteeing the sustainability of the environment. Repsol
invested $110 million in R&D during the course of the year to
make this vision a reality.
In 2013 Repsol and Indra, an award winning company in the
field of energy and advanced technology, joined forces to
develop a pioneering technology known as HEADS
(Hydrocarbon Early and Automatic Detection System),
designed to achieve unprecedented automatic detection of oil
spills, improving reaction times and safety.
Other pioneering projects developed throughout 2013, which
include Project Kaleidoscope and Project Sherlock, will enable
Repsol to access untapped reserves in new frontier areas. The
company’s drive for more accurate seismic imaging and
reservoir modeling based on supercomputing is contributing to
bring down exploration costs and increase recovery of reserves.
Repsol’s focus on innovation as a driver of smart energy is
embodied in the Repsol Technology Centre (RTC). The RTC is
one of the biggest and most modern in Europe, where Repsol
develops fuels for competition, biofuels and microbiology to
obtain better efficiency and quality in all its products.
Socially responsible
Repsol strives for the welfare of people and is a step ahead in
building a better future through the development of smart
energy solutions. Through hard work, talent and enthusiasm,
the company is making progress in offering the best energy
solutions for society and the planet.
Repsol led the charge in corporate social responsibility
throughout the year. Repsol features prominently in the
FTSE4Good, Ethibel Sustainability and Dow Jones
Sustainability indexes. It was recognized by Newsweek magazine
as the company with the best environmental performance in the
energy sector and topped the Climate Disclosure Project energy
sector rankings for management of its carbon footprint. Repsol
initiatives to integrate disabled and vulnerable people into its
workforce have been recognized through a number of awards,
including the Reina Sofia Award, Discapnet of the Once
Foundation and the Ability Award.
Visionary
In a year when energy companies were faced with a tough
operating environment, Repsol’s focus on E&P has paid off. Its
vision of becoming an ever more nimble upstream player, with an
emphasis on technology, has continued to bear fruit throughout
2013, allowing the company to deliver on industry-leading
growth targets in terms of production and reserves increases.
Repsol has delivered on all of the major tenets of its 2012-2016
strategic plan. The company is now focusing on the next stage
of development, moving several large discoveries into
production to boost output.
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SPECIAL ADVERTISING SECTION
GLOBAL LEADERS PROFILE
Kevin Smith
CEO
SolarReserve
SolarReserve
A leading global developer of large-scale solar power projects
and advanced solar thermal technology, SolarReserve is poised
to transform the electricity industry by commercializing the
world’s leading solar thermal energy storage technology.
SolarReserve’s utility-scale concentrated solar power (CSP)
plants feature a groundbreaking molten salt power tower
technology with fully integrated energy storage, making them a
true alternative to fossil fuel generators such as coal and natural
gas. Through this innovative approach to clean power
generation, SolarReserve offers power utilities and large
industrial energy users reliable, renewable energy “on demand”
– day and night – to help them meet growing energy
consumption needs.
SolarReserve was founded to solve two fundamental problems in
renewable energy generation – dispatchability and scalability.
With more than $1.8 billion of solar projects in construction
worldwide and over 5,000 MW in development, SolarReserve’s
team of power project professionals is striving to address the need
for reliable and clean energy across the US and around the world.
With fully integrated, large-scale energy storage technology that
utilizes liquid molten salt to both capture and store the sun’s
thermal energy until electricity is needed, SolarReserve’s CSP
plants operate just like a conventional power generator and are
a genuine alternative to baseload coal, nuclear or natural gas
burning electricity generation facilities. But unlike
conventional fossil fuel generators, SolarReserve’s CSP plants
are not only completely emissions-free, but take advantage of a
limitless and free fuel source – the sun.
provide our country, and the world, with clean, reliable
electricity, around the clock.
The Crescent Dunes Project, a 110 megawatt solar plant under
construction in Nevada, is SolarReserve’s flagship CSP initiative
and a shining example of the company’s market-leading
technology. The Crescent Dunes plant, which began
construction in of the fall of 2011, is a tremendous success story
for US-developed technology. With more than 800 workers
currently on-site and over 1,000,000 man-hours completed to
date, the Crescent Dunes Project is creating over 4,300 direct,
indirect and induced jobs over the construction period. Slated
to come online in 2014, the project will be the world’s largest
solar thermal tower project with integrated energy storage and
will provide a firm supply of solar energy to power 75,000
homes during peak demand periods, even after dark.
In addition to its flagship project, SolarReserve has
development activities worldwide, and currently has 246 MW
of photovoltaic (PV) projects in construction in South Africa
– some of which are the largest project finance transactions ever
completed in South Africa and among the largest renewable
energy projects on continental Africa.
With construction and development activities worldwide,
SolarReserve is providing renewable energy solutions that not
only generate clean energy, but also cultivate economic growth
for communities and support the goal of energy independence
for countries and industries around the world.
Statistics
■
This revolutionary energy storage technology is unparalleled in
the industry today. SolarReserve’s utility-scale technology can
provide reliable green electricity, on-demand 24 hours a day, to
tens of thousands of homes with each power plant that is built.
SolarReserve’s plants feature the technology that can truly offset
the negative impacts of conventional power generators and
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■
■
Projects Portfolio: $1.8 billion of large-scale solar power
projects, both concentrated solar power and photovoltaic
projects in development, totaling 356 MW of capacity
Global Reach: 5,000 MW of solar projects in various stages
of development in countries and regions such as South
Africa, Chile, Australia, the Middle East, China and Europe
Employees: 80
SPECIAL ADVERTISING SECTION
GLOBAL LEADERS PROFILE
Sheldon Kimber
Chief Operating Officer
Recurrent Energy
Recurrent Energy
Recurrent Energy is redefining what it means to be a
mainstream clean energy company, with a fleet of utility-scale
solar plants that provide competitive clean electricity.
With a 2 gigawatt (GW) project pipeline and more than 700
megawatts (MW) of signed contracts spanning the US and
Canada, Recurrent Energy holds one of the largest solar
development portfolios in North America.
Recurrent Energy has enabled more than $3.5 billion in
investment in clean energy, with dependable returns that are
well-matched to the needs of public and private capital markets.
Recurrent Energy’s leadership collectively brings over 100 years
of solar and energy project experience in project development,
engineering, and structured finance. Technology expertise,
supply chain capabilities, and access to capital further enables
Recurrent Energy to deliver solar generating plants at any scale
with market-leading cost and efficiency.
The company’s development strategy is to build a balanced
portfolio of utility-scale solar projects ranging in size from 20
to 500 MW to meet increasing demand for clean electricity at
highly competitive prices. This approach provides a diversity of
projects that can deliver both large capacities and rapid
development timelines.
As a leading solar project developer, Recurrent Energy’s mission
is to transform our world to sustainably meet its energy needs
with clean electricity.
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To learn more, visit
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DECEMBER 2013
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GLOBAL ENERGY AWARDS
PATSY WURSTER
Director, Global Energy
Awards, Platts
SHALE TAKES
TOP PRIZE
The winners of the Platts
Global Energy Awards
Each year, the Platts Global Energy
Awards program provides a microcosm
of the world’s energy markets; viewing
the competitors and winners gives an
excellent overview of the year’s top
stories. The 15th year, which garnered
more than 200 nominations from 26
countries, reveals an industry that
continues to diversify – in product
development, technological
advancements, and geographic presence.
The Global Energy Awards judging panel
– which includes former national
regulators, former heads of major energy
companies and leading academics,
analysts and legislators – noted a high
caliber of entrants, with many nontraditional names staking their claim in
several categories. Discussion and debate
prevailed as two categories ultimately
rewarded multiple winners.
Three stories dominated the discussions
this year: Asia remains the global engine
of demand growth across the board, and
China is dominating with its elegantly
negotiated cross-border deals. CNOOC,
one of the largest producers of crude and
natural gas, leads the way in investing
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DECEMBER 2013
globally. Its deal with Nexen represents
China’s biggest-ever overseas energy
acquisition, and earned the company a
Strategic Vision Award this year.
Second, solar continues to be a big story,
with the resource rapidly approaching
grid parity; prices have dropped
significantly in recent years, and
continue to decrease. Two solar-focused
companies received Global Energy
Awards this year, but the energy source
appeared as a component of the business
efforts of multiple winners.
Finally, shale has led to a major rise in
the United States’ natural gas
production, specifically in the Bakken
formation, thanks to the development of
hydraulic fracturing and horizontal
drilling technology. Shale’s dominance is
reflected in the Global Energy Awards,
which designated Continental Resources
as Energy Company of the Year and its
CEO, Harold Hamm, as winner of a
Strategic Vision Award. Together,
Continental and Hamm are the “Best
Picture/Best Director” winners in what
many call the “Oscars of the Energy
Industry.”
GLOBAL ENERGY AWARDS
The Global Energy Awards do not
simply reflect the industry’s success in
the prior year; they indicate the direction
in which the industry and its leading
thinkers are headed. For their corporate
and individual leadership, innovation
and superior performance, Platts is
proud to honor the 2013 recipients of
the Global Energy Awards.
Energy Company of the Year
Continental Resources
United States
Traditionally the most sought-after
award in Platts’ annual competition, the
Energy Company of the Year Award
recognizes firms that exemplify
leadership and innovation. This year’s
winner, United States-based independent
oil producer Continental Resources,
demonstrated those qualities in both its
financial growth and its innovative spirit.
Based in Oklahoma City, Continental is
focused on the exploration and
production of onshore oil-prone plays
and is a top independent oil producer
in the United States. Under the
leadership of Chairman & Chief
Executive Officer Harold Hamm,
Continental has a long and successful
history of developing its industryleading leasehold and production in the
nation’s premier oil play, the Bakken of
North Dakota and Montana, as well as
significant positions in Oklahoma in its
recently discovered SCOOP play and
the Northwest Cana play. In 2013,
Continental will celebrate 46 years of
operation.
In 2012, Continental estimated that the
Bakken and neighboring Three Forks
reservoirs collectively hold 24 billion
barrels of potentially recoverable crude
oil equivalent – 20 billion in oil and
four billion in natural gas. Concurrent
with an increase in production and
addition to proved reserves, Continental
realized significant operating efficiencies
through improving cycle times,
lowering completion costs, and
transitioning to pad drilling in the
Bakken play.
Continental focuses its exploration
activities in large new or developing
plays that provide it the opportunity to
acquire undeveloped acreage positions
for future drilling operations. The
company has been successful in targeting
large repeatable resource plays where
horizontal drilling, advanced fracture
stimulation and enhanced recovery
technologies allow it to economically
develop and produce crude oil and
natural gas reserves from unconventional
formations.
Continental plans to uphold the
financial flexibility afforded by its strong
balance sheet while pursuing growth; in
October 2012, the company announced
a new five-year growth plan to triple its
production and proved reserves. As its
production grows, Continental is
optimizing takeaway capacity and
implementing competitive marketing
strategies to bring its high-quality crude
oil barrels to premier markets.
Continental has a justifiably proud
culture of bravery, entrepreneurial spirit,
and innovative leadership exemplified by
Hamm, who is this year’s winner of the
Strategic Vision Award in the CEO
category. Continental’s first-mover
advantage in the Bakken, where it boldly
experimented and deployed cutting-edge
technology, enabled the company to
amass the most commanding acreage
position in what is now recognized Ź
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GLOBAL ENERGY AWARDS
as one of the largest contiguous oil fields
discovered worldwide in more than 40
years. For its starring role implementing
the latest technology in the year’s biggest
location, Global Energy Awards judges
are pleased to name Continental
Resources the 2013 Energy Company of
the Year.
capital investment, but showed excellent
potential. Inspired by 2003’s startling
results from a combination of horizontal
drilling and fracking, Hamm went all in.
He deployed an army of landmen to
acquire mineral leases on 350,000 acres
in the region. Unable to find financial
partners, Hamm began to drill.
Strategic Vision Award
In addition to his role as Chairman and
CEO of Continental, Hamm is
Chairman of Hiland Holdings. He
co-founded and serves as Chairman of
the Domestic Energy Producers
Alliance, which aims to preserve the
millions of jobs and billions of dollars in
economic activity and tax revenues
generated by onshore drilling and
production activities within the United
States. He is also dedicated to preparing
the next generation of industry leaders.
In 2012, he helped establish the Harold
Hamm School of Geology and
Geological Engineering at the University
of North Dakota.
Chief Executive Officer
Harold Hamm, Continental Resources
United States
Continental Resources’ Chairman &
Chief Executive Officer, Harold
Hamm, is this year’s winner of the
Strategic Vision Award in the CEO
category. He is a man on a mission: to
bring America to energy independence
within the next decade.
Hamm, born in Enid, Oklahoma to
sharecropper parents, is the youngest of
13 children. He got his start pumping
gas and fixing flats at a local service
station before heading to work in the
region’s oil fields as a teenager. In 1967,
at the age of 21, he established his own
company and set off in search of
America’s big oil fields. Hamm’s dream
was first realized with Continental’s
discovery of Ames Hole, which is the
largest oil producing astrobleme in
North America, and continued with
Cedar Hills, the first field developed
entirely by horizontal drilling. But it
was the decisiveness of Continental’s
entry into the Bakken that established
Hamm as a major player and resonated
most with the Global Energy Awards
judges.
Hamm and his team had learned
through experience that the stubborn
rocks in the Bakken region demanded
sophisticated technology and significant
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DECEMBER 2013
The judges noted that Hamm did not
accept America’s conventional view of
energy scarcity over the past several
decades, which dictated that as domestic
supplies of oil and natural gas dwindled,
the country’s options were to increase
imports or shift focus to natural gas shale
development. Instead, he applied his
knowledge, intuition, and exploratory
spirit to pursue large, crude oildominated plays. His extraordinary
prescience extends beyond Continental;
Hamm believes that America can be
energy-independent by 2020, a goal
many experts have deemed attainable.
The judges for Platts Global Energy
Awards salute Hamm for rising from
sharecropper’s son to corporate CEO
while retaining the heart of an
entrepreneur.
GLOBAL ENERGY AWARDS
Strategic Vision Award:
Lifetime Achievement
The Lifetime Achievement category of
the Global Energy Awards is not a
winner-take-all; this year’s judging panel
felt strongly that three nominees
surpassed the threshold and earned the
honor based on their body of work. This
year’s three winners chose three very
different paths through the energy
industry: they include a utility executive,
a regulator, and an engineer. Diverse
though the winners may be, they
showed similar characteristics of
leadership and vision within multiple
industry contexts.
Strategic Vision Award
Lifetime Achievement
Jim Rogers, Duke Energy
United States
Jim Rogers, Chief Executive Officer of
Duke Energy, personifies the forwardthinking CEO who has profound impact
within his companies and throughout his
industry. His career is a series of “firsts,”
leading the way with his high-visibility
stance on major issues such as nuclear
power, market deregulation and
emissions trading.
Rogers is retiring as chairman,
president and CEO of Charlotte,
North Carolina-based Duke Energy,
the largest electric power holding
company in the United States with
more than $110 billion in total assets.
He became president and CEO of
Duke Energy following the merger
between Duke Energy and Cinergy in
2006. Before the merger, he served as
Cinergy’s chairman and CEO for more
than 11 years. Prior to the formation of
Cinergy, he joined PSI Energy in 1988
as the company’s chairman, president
and CEO.
In his time at Duke Energy, Rogers has
restructured the company into a leading
“pure play” electric utility holding
company. He spun off all of the
company’s natural gas operations into a
new, investor-owned company called
Spectra Energy; sold the Commercial
Marketing and Trading Business; closed
or sold Duke’s proprietary trading
operations; and repurchased $500
million in stock before orchestrating the
Progress Energy merger. Rogers’
leadership at Duke has been lauded for
balancing the “triple bottom line” of
people, planet and profits.
Rogers has served 25 years as a CEO in
the utility industry, during which time
he has delivered an average total
shareholder return of more than 12%
per year. He is now considering two
career options; teaching at the John F.
Kennedy School of Government at
Harvard, or becoming a social
entrepreneur, working to bring electricity
to the 1.3 billion people in the world
who have none. “I want to change
people’s lives in a fundamental way,”
Rogers said. The judges feel that, as a
visionary and a pioneer with profound
impact on the energy industry, this
Lifetime Achievement Award winner is
already well on his way to accomplishing
that goal.
Strategic Vision Award
Lifetime Achievement
Michael Peevey, California Public
Utilities Commission
United States
A different perspective on leadership
comes from Michael Peevey, currently
President of the California Public
Utilities Commission (CPUC). As the
state’s lead regulator, Peevey developed
and implemented a creative, Ź
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GLOBAL ENERGY AWARDS
forward-thinking strategy to repair
California’s troubled utility climate,
earning him worldwide respect and
recognition. One judge referred to him
as “the steady hand that steered the
ship to safe waters” in weathering
California’s unique struggles as well as
the challenges common to many
industry energy professionals: nuclear
power, market deregulation and
climate change.
procure 33% of their power from
renewable sources by 2020.
The judges recognized in Peevey a
champion of the environment and a
leader in establishing innovative policies
to mitigate climate change. With his own
unique brand of strategic vision, Peevey
has changed California for the better.
Strategic Vision Award
Lifetime Achievement
Peevey is currently in his second six-year
term as head of CPUC, one of the
country’s most influential regulatory
agencies; Californians spend more than
$50 billion annually for services from
industries regulated by the agency. He
joined CPUC in 2002 after a long and
storied career in the energy industry, first
at Edison International and Southern
California Edison Company, then at
NewEnergy, Inc.
Energy efficiency is Peevey’s hallmark.
Under his leadership at CPUC,
California created a groundbreaking
Energy Action Plan, which lays out a
single, unified approach to meeting
California’s energy needs. He was
instrumental in creating California’s first
Long Term Energy Efficiency Strategic
Plan, which presents a single roadmap
covering government, utility, and private
sector actions necessary to achieve
maximum energy savings in the state.
Peevey is a strong supporter of renewable
energy. Under his watch, the CPUC
implemented the California Solar
Initiative, which has a goal of installing
3,000 megawatts of new customer solar
projects by 2016. Peevey also oversaw the
implementation of one of the most
ambitious renewable programs in the
country, now requiring utilities to
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Bipin Vora, UOP LLC, A Honeywell
Company
United States
Engineering genius Bipin Vora caught
the attention of the judges immediately
with his Strategic Vision mission
statement: “Spreading cheer in humanity
through innovations in process
technology and efficient use of resources
leading to sustainable growth and
development.” Simply put, Vora is
recognized globally for developing safe
and environmentally friendly
petrochemical processes.
As an engineer and an inventor, Vora has
made countless impactful contributions
that changed the energy industry from
the ground up, earning him 92 patents
in the United States and 200
internationally, and has authored more
than 140 publications in various
technical and trade journals. His
technological innovations set new
standards for performance, and put
petroleum on the map of many
industries.
Vora spent 39 years at UOP LLC, A
Honeywell Company, and continues to
advise them on R&D and marketing
matters. The company has a 100-year
history as an international supplier and
licensor for the petroleum refining, gas
GLOBAL ENERGY AWARDS
processing, petrochemical production
and major manufacturing industries.
Today, more than 60% of the world’s
gasoline and 85% of biodegradable
detergents are made using its technology.
Products produced today employing
technologies developed under Vora’s
leadership from 1967 to 2006 are valued
at more than $10 billion per year. At
UOP, Vora worked in Experimental
Development, Technical Services, Process
Design, and R&D. He was a director of
all R&D programs related to Olefins and
Detergent processes and in 2001 was
named a UOP Fellow, the company’s
highest technical position.
Vora has been credited to leading
development and commercialization of
several new process technologies, namely
UOP OleflexTM process for propane and
isobutane dehydrogenation, high
conversion UOP PacolTM, UOP
DeFineTM and UOP/Cepsa DetalTM
alkylation processes for the production of
linear alkylbenzenes, UOP InAlkTM
process for high octane gasoline, and UOP/
Hydro MTOTM process for conversion of
methanol to ethylene and propylene.
The judges applauded Vora’s
contributions to petrochemical-derived
processes, which have certainly spread
cheer throughout humanity – and done
so while adhering to the basic principles
of safety, environmental protection and
sustainability.
Strategic Vision Awards
Rising Star – Company
Nodal Exchange
United States
A new company entering an established
market is well served if its leaders are
adept at repackaging challenges as
opportunities. This is one of the core
strengths of Nodal Exchange, the
company selected by judges as this year’s
Rising Star. North America’s organized
wholesale electric markets present
thousands of distinct price locations, or
nodes; the markets’ complexity and the
associated technological sophistication
of the systems required to serve them
had prevented the development of
adequate forward markets to supply
liquidity and allow complete hedging of
power portfolios. Enter Nodal
Exchange, which launched its trading
platform in 2009.
Based in Vienna, Virginia, privately
held Nodal Exchange is staffed by
management, employees, and advisers
with extensive experience in the power
and financial industries. The company
is the first commodities exchange
dedicated to offering locational (nodal)
futures contracts and related services to
participants in the organized North
American electric power markets. The
company allows its participants to trade
cash-settled, fully standardized
contracts in a cleared market, enabling
market participants to effectively
manage basis and credit risk. The
company offers more than 1,000
contracts on hundreds of unique
locations in the RTO/ISO markets and
is a designated contract market
regulated by the CFTC with all
contracts cleared by LCH.Clearnet Ltd.
The company has grown significantly,
obtaining a market share of over 25% of
all cleared North American power futures
contracts, measured by open interest, as
of August 31, 2013, with a year-to-date
trading volume that is double the same
period of 2012. The company credits its
growth to its employees and
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GLOBAL ENERGY AWARDS
constituents, including LCH.Clearnet,
21 clearing members, 9 brokerages and
over 80 signed participants. Nodal
recently received approval from the
United States Commodity Futures
Trading Commission to be registered as a
Designated Contract Market. In the
future, the company intends to further
expand its product offerings and also
extend its services to other market
regions in the United States and Canada.
At age 35, Kimber is the Chief Operating
Officer of Recurrent Energy, a
mainstream clean energy company with a
fleet of utility-scale solar plants that
provide competitive clean electricity. The
company boasts a 2 GW project pipeline
and more than 700 MW of signed
contracts spanning the U.S. and Canada,
representing one of the largest solar
development portfolios in North
America.
The Rising Star category, with many
outstanding companies on the road to
becoming major industry players,
brought out vigorous debate among the
judges. However, the Global Energy
Awards judges all praised Nodal
Exchange for maximizing the
opportunities presented by the DoddFrank Act and the global trend toward
deregulated markets in transmission. The
company’s innovation has resulted in
astounding growth, evolving from no
open positions at launch to claim
significant market share in a highly
competitive environment. Nodal
Exchange has established a business
premise that many feel will soon become
an accepted industry standard as it
continues to innovate to meet the
changing needs of the marketplace.
Rising Star – Individual
After extensive experience in traditional
energy, including five years at Calpine
working on gas-fired power projects,
Kimber joined Recurrent Energy shortly
following its founding in 2006. He has
helped manage the company’s transition
from a small-scale rooftop developer
with 12 employees to an industryleading utility-scale developer with more
than 125 employees across multiple
global offices. He currently leads all
project development, engineering,
procurement, construction, operations,
and origination activities. The company
has 260 MW of solar projects in
operation, delivering electricity to some
of North America’s leading utilities and
large energy companies. Poised for an
historic year, the company plans to
complete an additional 315 MW of
projects in 2013, bringing its total
operating portfolio to well over half a
gigawatt.
Sheldon Kimber, Recurrent Energy
United States
It is fitting that the Individual winner of
this year’s Rising Star Award powers a
company that’s powered by a star. The
sun provides our planet’s most abundant
energy resource; 173,000 terawatts of
solar energy strikes the Earth
continuously, more than 10,000 times
the world’s total energy use. And Sheldon
Kimber is putting it to work.
Kimber played a key role in Recurrent
Energy’s sale to Sharp Electronics, which
acquired the company in 2010 for $305
million. Now, as governments around
the world scale back clean energy
subsidies, many solar companies are
struggling; Recurrent Energy, however, is
thriving. It recently announced that
Google and KKR are making an
investment in six solar photovoltaic
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GLOBAL ENERGY AWARDS
facilities that are currently being
developed and will be managed by the
company. The facilities have a combined
production capacity of approximately
106 megawatts and will provide clean
electric power to local utilities and
municipal offtakers under long-term
Power Purchase Agreements.
Kimber is respected by his peers for his
keen ability to assess market trends and
make sound strategic decisions. His
unique voice stands out among energy
executives as he sets a new course for
competitive, clean solar power capable of
competing in mainstream energy
markets. The judges were unanimous in
their selection of Kimber as this year’s
Rising Star: Individual, calling him a
go-getter, a sharp decision-maker, and a
quick mover. He is on a trajectory for
success as he and Recurrent Energy lead
the way to a new era of clean,
competitive, mainstream power.
Strategic Vision Awards
major domestic operations as well as
overseas oil and gas assets in Asia,
Africa, North America, South America
and Oceania. Its metrics are
astounding: in 2012, the company
claimed more than 10,000 employees,
oil and gas production of 342.4 million
BOE, and ownership of net proved
reserves of approximately 3.49 billion
BOE, with average daily net production
of 935,615 BOE.
CNOOC’s acquisition of Nexen, which
received broad support from common
shareholders, was completed in February
2013. The deal brought several benefits
to the company; Nexen provides a critical
new base for overseas development, with
rich resources and a diversified asset
portfolio, run by veteran management
and staff with extensive working
experience in major oil and gas
producing areas around the world.
Together, these elements are essential to
CNOOC’s near-term and mid-to-long
term development.
Deal of the Year
CNOOC Limited
China
Energy industry mergers and acquisitions
were major news last year. But one deal
stood out head and shoulders above the
rest: in July 2012, CNOOC Limited
announced its $15.1 billion acquisition
of Canadian Energy Producer Nexen Inc.
This massive, cross-border transaction
represented China’s biggest-ever overseas
energy acquisition.
CNOOC is China’s largest producer of
offshore crude oil and natural gas and is
one of the world’s largest independent
oil and gas exploration and production
companies. It mainly engages in
exploration, development, production
and sales of oil and natural gas, with
The road to integration was not without
its obstacles, which included obtaining
government approvals on the
acquisition; integrating two entirely
different corporate cultures; analyzing
the effectiveness and synergies of the
acquisition to Nexen and Canada; and
determining impact of the acquisition
to the communities where Nexen’s
projects are located. The seven-month
negotiation, led by CNOOC CEO Li
Fanrong, surmounted global challenges
and specifically stressed on the
intangible benefits the deal would bring
to Nexen shareholders and employees,
Canada, the United Kingdom, the
United States, and other countries in
order to win approval from shareholders
and regulatory bodies.
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Following the acquisition, management
is working to ensure a smooth
integration process and cultivate a new
corporate culture that represents the
core values of the two companies.
Nexen has already begun to move the
needle, contributing 24.8 million BOE
to the company’s total net oil and gas
production from March to June 2013.
During the period, the company’s total
net oil and gas production rose 23.1%
year-on-year to 198.1 million BOE.
Without Nexen’s production output,
the production growth of CNOOC
was 7.7%.
Judges noted that the deal boosted
CNOOC’s growth potential expanding the company from
conventional to unconventional
resources and adding exploration and
production assets - while generating
synergies for the its existing operations.
CNOOC “executed magnificently,”
noted one judge. “It’s the kind of deal
that changes geopolitics.”
Industry Leadership
Electricity Generation
Korea Southern Power Corporation
Limited
South Korea
Over the past five years, South Korea,
traditionally a major energy importer, has
increased its investment in renewable
energy to reduce its reliance on foreign
oil. In the process of improving its
domestic energy situation, governmentowned Korea Southern Power
Corporation Limited (KOSPO) has
exhibited exceptional industry leadership
in the energy generation field: developing
cutting-edge alternative fuel resources
and power generation technology that
affords the company the ability to scale
globally.
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KOSPO is one of six wholly owned
electricity generation subsidiaries of Korea
Electric Power Corporation, which
generate substantially all of Korea’s
electricity. The company is the country’s
largest thermal power generation company,
in terms of 2012 total generation capacity,
sales volume and revenue. In order to
respond to global climate change and to
promote the creation of a new growth
engine in the energy sector, KOSPO has
pursued projects in the fields of renewable
energy, greenhouse gas capture and reuse,
and coal by-products recycling. Such
efforts resulted in KOSPO securing the
top spot in the Korean power sector, with
the largest capacity in renewable
generation facilities.
Among KOSPO’s groundbreaking
developments was its new power plant
combustion technology, currently in
place at the company’s 1,000 MWcapacity Samcheok Green Power Plant,
which was specifically designed for
carbon emissions reduction. The plant is
the first of its kind in the world to be
dedicated to low-rank coal combustion,
which provides more efficient
combustion of lower grade coals. The
judges found this particularly notable,
given the difficulties faced by many
carbon-capture facilities.
KOSPO also continues its R&D in
greenhouse gas reduction through its
own internationally patented carbon
capture and reuse technology. Judges
were impressed by the company’s ability
to scale its greenhouse gas capture
facilities, one 0.5 MW-class and one 10
MW-class, with impressive plans to reach
300 MW by 2015.
Perhaps KOSPO’s most impressive
achievements include its efforts in wind
GLOBAL ENERGY AWARDS
power generation. The company is
developing Korea’s first and largest
offshore wind project, located off of the
southwestern coast. The 2.5-gigawatt
offshore wind farm, worth $9 billion,
will be built in three phases and is slated
for completion by 2019. It is destined to
transform electricity for the entire
country.
The Global Energy Awards judges
applauded KOSPO’s main priority –
providing a stable supply of domestic
energy – as well as its efforts to develop
power generation technology, invest in
green technology and alternative fuel
resources, and develop overseas. Through
these efforts, KOSPO assures a
sustainable future while strengthening its
position in the global markets and
helping achieve its long-term goal: to be
a top global power company.
Industry Leadership:
Exploration & Production
Anadarko Petroleum Corporation
United States
Texas-based Anadarko Petroleum is
among the world’s largest independent
oil and natural gas exploration and
production companies, with 2.56
BBOE of proved reserves at year-end
2012. The company, which employs
more than 5,300 worldwide, boasts a
deepwater exploration/appraisal success
rate of approximately 70%, well above
the industry average of just under
50%.
Anadarko has operations in the Rocky
Mountains, the southern United States
and the Appalachian Basin. It is among
the largest leaseholders in Africa and is a
deepwater producer in the Gulf of
Mexico, with additional producing
assets and exploration opportunities
worldwide. But the big story that
caught judges’ attention was in
Mozambique, in water depths of
approximately 5,000 feet.
In 2006, Anadarko signed an agreement
with the Government of the Republic
of Mozambique for the Offshore Area 1
in the deepwater Rovuma Basin. Four
years later, it drilled its first discovery at
the Windjammer project, a massive
natural gas accumulation with more
than 480 net feet of natural gas pay,
and a gross column of more than 1,200
feet. Since that time, Anadarko and its
partners have safely drilled more than
20 successful wells in the area,
including two major complexes,
Prosperidade and Golfinho/Atum,
which combined hold an estimated 35
to 65-plus trillion cubic feet of
recoverable natural gas.
Anadarko’s success continued in 2013,
with new massive natural gas discoveries
at Espadarte and Orca. The collective
size of the discoveries represents
enormous potential for Mozambique to
become a major exporter of LNG.
Benefits for the country could include
substantial revenues, long-term foreign
investment, training and employment,
investment in infrastructure, and growth
in business and enterprise capacity, as
well as the potential to provide natural
gas for domestic consumption and
industry.
The company deems Mozambique a
transformational opportunity, given
that the project offers potential to
produce 50 million tonnes of LNG per
annum, or 20% of current global need.
Mozambique, which previously had no
LNG production, could rise to become
the world’s third-largest LNG
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exporter. Developing this massive LNG
park will likely require the largest
foreign investment in Mozambique’s
history. Anadarko estimates the gross
investment for the first phase of the
project will be around $15 billion,
exceeding the country’s total GDP. But
this Industry Leadership Award winner
is confident that its drilling experience,
combined with its professional courage
and exploration culture, will help
achieve its goal of delivering a cleanerburning fuel source to global markets,
beginning in 2018.
Judges were particularly impressed that
though Anadarko’s project in
Mozambique was “risky, big, and
extremely remote,” the company
exhibited a phenomenal logistical
demonstration – one that, impressive as
it is today, is destined for even greater
global implications in the near future.
Industry Leadership
Grid Optimization
Bonneville Power Administration
United States
Exhibiting a groundbreaking business
process that seems destined to become
industry standard is a true sign of
industry leadership. The Bonneville
Power Administration (BPA) has
developed one such process in its
synchrophasor program, which enables
the agency to instantly evaluate the
qualities of its power generation and
adjust the amount of power on the grid
accordingly.
BPA is a federal agency based in the
Pacific Northwest under the United
States Department of Energy. BPA
markets wholesale electrical power from
31 federal hydroelectric projects owned
and operated by the U.S. Army Corps
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of Engineers and Bureau of
Reclamation, one nonfederal nuclear
plant and some small nonfederal
resources. BPA supplies about one-third
of the electric power used in the
Northwest. The agency owns, operates
and maintains about 75% of the region’s
high-voltage transmission system. It
promotes energy efficiency and
renewable energy, and integrates
renewable resources, such as wind
energy, into its grid. As a self-funding
agency, BPA recovers its costs by selling
wholesale power, transmission and
related services at cost.
Global Energy Awards judges found
much to admire in BPA’s
synchrophasor program, which the
agency completed in 2013.
Synchrophasors are precise grid
measurements taken from Phasor
Measurement Units (PMUs). PMUs
measure voltages, frequency, current,
active and reactive power, and stream
measurements to a control center 60
times per second. All measurements are
time synchronized to a microsecond
using GPS, providing an
unprecedented view of the power
system’s dynamic state. BPA’s system is
the largest, most sophisticated
synchrophasor network of any utility
in North America, and the only one
designed specifically for power system
control capabilities.
BPA is now collecting 137,000
measurements from across the grid
every second, requiring the
development of intelligent data mining
capabilities to make sense of a terabyte
of data generated each month. Thanks
to the inflow of data, BPA has
improved its view of power system
stability issues, such as power
GLOBAL ENERGY AWARDS
oscillations that can lead to large-scale
power outages. The agency expects to
avoid at least one large-scale outage in
40 years, at a conservative estimated
value of $1.2 billion to $3.5 billion.
The agency is also collaborating with
wind power plant operators in the
region to expand PMU coverage. It has
almost 5,000 MW of wind generation
connected to its control area today, and
expects that PMU data will help
address large-scale wind integration
challenges.
BPA’s investment in synchrophasor
technology is expected to provide
significant value to the agency, northwest
electric utilities and electric ratepayers.
Judges were impressed with the value as
well as the scale of the project, as well as
the amount of wind integrated, noting
that BPA’s efforts are destined to become
industry standard.
Industry Leadership
Midstream
Puma Energy
Switzerland
In selecting the winner of the Industry
Leadership Award for Midstream, Global
Energy Awards judges found the
numbers for one company leapt off the
page: Puma Energy. The company
handles more than 22.5 million M3 of oil
products annually, with 14 million M3
sold via a network of 56 bulk storage
terminals, 24 airports and 1,500+ service
stations resulting in $13 billion revenue
in 2012. Puma Energy is huge, and it is
“full of smart people looking for
advantages and gaining an edge,” said
one judge.
Puma Energy is a global integrated
midstream and downstream oil
company. Formed in 1997 in Central
America, Puma Energy has since
expanded its activities to more than
6,000 employees in 35 countries across
five continents. The company’s core
activities in the midstream sector include
the supply, storage and transportation of
petroleum products, underpinned by
investment in infrastructure that
optimizes supply chain systems,
capturing value as both asset owner and
marketer of product.
Puma Energy is the world’s largest
operator of bulk storage terminals; its 56
sites provide traders, wholesalers, oil
majors and other customers with access
to over 4.5 million M3 of storage. The
company’s refining assets include two
refineries acquired from ExxonMobil: a
20kbd refinery at Managua, Nicaragua,
and a controlling stake in a 22kbd
refinery in El Salvador. Its downstream
activities include the distribution, retail
sales and wholesale of refined products,
as well as products in the lubricants,
bitumen, LPG and marine bunkering
sectors.
Judges were struck by the company’s
extreme business locations: where other
oil companies have moved out, Puma
Energy has moved in. The company
operates in remote, demanding,
climatically challenging, and sometimes
potentially dangerous environments,
where it operates with sustainability and
safety in mind. Its business in emerging
markets often involves creation of the
infrastructure required for it to operate,
so the company often partners with
state-sponsored organizations to improve
road networks, ports and storage
facilities. The company calls this
strategic practice “over-investing in
assets;” it does not shy away from
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long-term benefits can be justified.
Puma Energy also sets its own standards
for regulatory oversight, rescue services,
health, safety and environmental
requirements in parts of the world where
these operations are often lacking, taking
international best practice as a
benchmark.
Judges were intrigued by Puma Energy’s
efficiency despite the ambitious nature
and impressive scale of its operations.
The company’s total sales are expected to
reach over $13 billion in 2013. Puma
Energy aims to become the leading fuel
storage and distribution company in its
markets, and to continue its fresh and
dynamic approach to providing oil
products to parts of the world where they
are most needed.
Stewardship Award
Corporate Social Responsibility
Manila Electric Company
Philippines
Corporate social responsibility (CSR),
for any company in the energy industry,
generally denotes a program of
sustainability: protecting both the people
and the resources, in both the short-term
and the long-term. One company stood
out this year by not just establishing a
philanthropic effort towards
sustainability, but also integrating social
responsibility into the heart of its
business model – which is what the
Stewardship Award for CSR aims to
recognize.
The Manila Electric Company (Meralco)
is the largest electric distribution utility
in the Philippines, powering more than 5
million customers in its 9,337 km
franchise area. The company services
approximately 25% of the total
Philippine population. It generates about
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50% of the Philippine GDP and
accounts for nearly 55% of Philippine
energy sales.
Meralco recorded record levels in sales,
operational and financial performance in
2012. Its sales revenues reached $6.8
billion with market capitalization at
year-end 2012 of $7.2 billion. As the
company evolves into a total energy
solutions provider from being a power
distributor, it has aligned its CSR
initiatives with its corporate efforts –
focusing on showing its malasakit, or
genuine concern for others, to its three
Cs: Customers, Community and
Country.
Meralco’s core CSR initiative is its
Community Electrification program,
which gives the area’s poorest families
access to electricity with little to no
application fee. Meralco’s efforts have
electrified more than 8,000 families from
its franchise area. Besides providing the
families with lower monthly electricity
bills compared to the rates of village
sub-metering, Community
Electrification enables families to run
electric appliances, aiding in the
establishment of small businesses as well
as improving productivity in household
chores and farm work. The program has
also energized 17 remote island schools
using solar photovoltaic energy systems,
providing new learning opportunities for
nearly 3,000 students. Through this
initiative, Meralco has become a “big
brother” to local electric cooperatives by
modeling electrification schemes that can
be sustained by poor and remote
communities.
Community electrification is but one of
the 1,500 CSR activities the company
has enacted in the past decade. It has also
GLOBAL ENERGY AWARDS
partnered with more than 2,800
organizations and engaged 30,000
individuals, approximately 90% of which
are Meralco employees, to volunteer their
time and talent. The company estimates
its total impact at more than 438,000
citizens, enabling many to rise above the
challenges of poverty for the first time.
The company has recently added solar
into its electrification, exhibiting an eye
toward future sustainability while dealing
with the present supply inefficiencies.
Meralco’s employees are to be
commended for their culture of impact
– one that continuously challenges and
improves the company’s own
performance, strengthens its efficient use
of resources, and values commitment and
accountability.
Stewardship Awards
Efficiency Initiative –
Commercial End-User
IBM
United States
Judges selected an atypical winner in the
Stewardship Award for Energy Efficiency
category this year. Historically, the award
has recognized companies that enact an
energy efficiency plan to protect the
environment while strengthening the
bottom line. This year’s winner, IBM,
achieved those objectives – but its
commitment to rolling out the changes
throughout its entire massive global
enterprise, over decades, makes the
impact of its changes exponentially
greater than most.
Incorporated in 1911, and employing
434,246, IBM is a globally integrated
technology and consulting company.
The company’s 2012 revenue was
$104.5 billion, with net income of
$16.6 billion and total assets of $119.2
billion. IBM has two principal goals:
to help clients succeed by becoming
more innovative, efficient and
competitive through the use of
business insight and information
technology solutions; and to provide
long-term shareholder value.
Environmental sustainability, including
energy conservation and climate
protection, is a key area in which
IBM’s expertise, programs and
technologies contribute to these goals.
IBM’s commitment to energy
conservation dates back to 1974, and
the company has had a corporate-wide
energy conservation goal since 1996. Its
current goal is to implement projects to
conserve energy equal to 3.5% of IBM’s
annual energy use. The energy savings
goal is pursued in four main categories:
typical energy conservation projects
such as lighting, HVAC and CUP
system upgrades, and time of day
management; manufacturing energy
efficiency projects in the
microelectronics manufacturing and test
areas; software and analytics-based
energy optimization systems at data
center, office and building complexes;
and server and storage virtualization and
consolidation projects.
In 2012, IBM’s energy conservation
projects were the result of over 2,670
conservation projects at over 400
locations around the globe. The projects
saved 400,000 MWH of energy,
equivalent to 6.5% of the company’s
total energy use for the year, saving $35
million in expense. It also avoided over
155,000 metric tons of CO2 emissions.
Cumulatively, IBM’s energy management
program has delivered extraordinary
savings from 1990 to 2012, reducing or
avoiding 6.1 million MWH of
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electricity, saving over $477 million, and
avoiding 3.9 million metric tons of CO2
emissions.
IBM’s energy conservation program adds
real and additional benefits to the
business beyond energy use reductions.
For example, it often realizes energy use
reduction in data centers and
manufacturing and assembly operations
through improving equipment utilization
and reducing cycle times and energy
waste in the system.
Judges remarked on its absolute savings
program; the company aimed for and
achieved a hard cut in energy across its
entire enterprise. Energy efficiency is not
just wise environmental stewardship – it
is good for business as well, and IBM has
proven it on a grand scale.
Stewardship Awards
Efficiency Initiative – Energy
Supplier
Constellation, an Exelon Company
United States
Even in an environment of lower
electricity prices, energy remains one of
the top five expenditures for businesses.
Current economic circumstances are
forcing all businesses to be as lean as
possible. And customers are increasingly
seeking products and services that are
manufactured and delivered in a
sustainable way. Baltimore, Marylandbased Constellation, a business unit of
Exelon Corporation, attracted judges’
attention for its creativity in combining
commodity supply deals with long-term
energy management programs, and its
innovation in both programs and
financing structure.
Constellation is a supplier of power,
natural gas, renewable energy and energy
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management products and services for
homes and businesses across the
continental United States and Canada.
Constellation provides integrated energy
solutions that help customers buy,
manage and use energy, from electricity
and natural gas procurement to
renewable generation and conservation.
More than 100,000 commercial,
industrial, public sector, and
institutional customers, including
two-thirds of the Fortune 100, use
Constellation to help strategically
manage energy. The company provides
nearly one million residential customers
with electricity and natural gas plans
that can provide price protection,
savings and environmental
opportunities.
In developing its unique business model,
Constellation executives applied their
knowledge about the decision making
process and challenges business leaders
face when considering efficiency
upgrades – such as energy efficient
lighting, building automation controls,
and HVAC upgrades – and the lack of
capital funding to make these
improvements. Business priorities and
economic pressures regularly move
facility improvements to the bottom of
the priority list. To find a solution to this
issue, Constellation combined an
electricity supply agreement with an
energy efficiency contract, eliminating
the capital issue.
Through its unique bundled commodity
and energy efficiency solution,
“Efficiency Made Easy,” Constellation
factors the cost of efficiency measures
into the price per kilowatt-hour of the
customer’s electricity bill over the length
of their electricity supply agreement.
Customers realize an immediate energy
GLOBAL ENERGY AWARDS
cost savings through a reduction in
electricity use, while operating in a
more environmentally responsible way.
Judges were impressed by the results;
from 2011-2013, Constellation’s
customers collectively reduced CO2
emissions by more than 166 million
pounds.
Judges were impressed that Constellation
avoided cross-subsidization and its
attendant pricing issues, instead
exhibiting impeccable design and
implementation in both its programs and
its financing structure. Though
Constellation’s scale has not yet impacted
the market in a major way, it has
excellent potential to set the course for
future markets. “There aren’t many
programs that deliver supply and also
drive efficiency in a single instrument,”
said one judge.
Stewardship Award
Green Energy Supplier
First Solar, Inc.
United States
Judges agreed that one company
dominated the green energy category this
year: First Solar. In a cost-competitive
environment, the company’s nimble
approach helped it achieve success
without subsidies.
First Solar is a provider of solar energy
solutions, aiming for affordability,
reliability and accessibility on a global
scale. The company manufactures and
sells photovoltaic (PV) solar modules
with an advanced thin-film
semiconductor technology; it also
designs, constructs, and sells PV solar
power systems that use the solar
modules it manufactures. First Solar is
the world’s largest thin-film PV solar
module manufacturer and one of the
world’s largest PV solar module
manufacturers.
In addressing overall global demand for
PV solar electricity, First Solar has
developed a differentiated, fully
integrated systems business that can
provide a competitively priced turn-key
utility-scale PV system solution for
system owners and competitively priced
electricity to utility end-users. First
Solar’s global effort focuses on four main
areas: utility-scale power generation
through grid-connected bulk power
systems; fuel displacement through
hybrid solutions that bring together solar
and conventional fuels; off-grid and
energy access platforms for underserved
energy markets; and solutions for
restricted spaces.
The company began in 1999, when
government subsidies of renewable
energy were common. It has since
strategically moved away from subsidized
markets in order to focus on cost
competitiveness. Its unique Levelized
Cost of Electricity basis – calculating the
total cost of ownership from project
development and financing through
operations and maintenance over the
plant’s operational life – enables it to
offer electricity costs of between
$.07-$.15/kWh, depending on the
region and other factors. Incredibly, First
Solar’s creative approach has rendered its
energy cost competitive with
conventional generation sources such as
fossil fuels.
The company has reached several
milestones – achieving world-record
research cell efficiency of 18.7% and
total area module efficiency of 16.1%,
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barrier, produce 1 GW in a single year,
and implement a global PV module
recycling program. The company boasts a
pipeline of over 3 GW of contracted
solar power plants and over 7 GW
installed worldwide.
First Solar continues to gain traction in
its markets and expand its global
presence, while continuing to add to its
advanced stage project pipeline, one of
the largest contracted captive solar
pipelines in the world. The company
expects to not only maintain but also
increase its cost competitiveness at the
system level relative to its peers for the
foreseeable future. Judges felt that First
Solar, in its unique approach to
manufacturing costs as well as its
creativity in moving from supply
modules to becoming a vertically
integrated provider of utility-scale
systems, elevates the entire solar industry.
Premier Project Award
Construction
GAIL (India) Limited
India
Construction projects in the energy
industry can face numerous challenges,
including pressures of location, financing,
timing and scope. This year’s Premier
Project Award in the Construction category
goes to a company that surmounted those
challenges and more to create a key
component of its country’s national gas
grid. GAIL (India) Limited, the largest
state-owned natural gas processing and
distribution company, earned effusive
praise from the Global Energy Awards
judges in becoming this year’s award
winner for its Dabhol-Bangalore Gas
Pipeline Construction Project.
Incorporated in 1984, New Delhi-based
GAIL works to accelerate the country’s
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use of natural gas. The company was
initially responsible for construction,
operation and maintenance of the
Hazira-Vijaypur-Jagdishpur (HVJ)
pipeline, a massive 1,800 km crosscountry natural gas pipeline that laid the
foundation for India’s natural gas
market. GAIL has now become an
integrated energy major with presence in
entire gas value chain, with assets
including 10,791 km of gas pipelines,
2,042 km of LPG pipelines, seven gas
processing plants, a gas-based
petrochemical plant, and a gas-based
power generation facility, with
additional subsidiaries in the United
States and Singapore. It is also pursuing
business opportunities in Africa and the
Middle East.
Commenced in 2010 and completed in
2013, the Dabhol-Bangalore Pipeline
was designed to transport 16 MMSCMD
of RLNG from Dabhol LNG Terminal.
The pipeline project is a component of
the National Gas Grid, acting as a
common carrier between western and
southern parts of India for companies
including Reliance, Shell, PLL and
ONGC, thus integrating the country’s
entire gas market. It has the potential of
ushering in a green revolution in the
heavily industrialized western and
southern region of India, which will have
access to environment friendly green fuel
for the first time.
The pipeline’s unique route snaked
through the undulating, monsoon-prone
terrain of Western Ghat Mountains,
known as the Great Escarpment of India.
Such uncertain ground proved costly to
build upon; the project encompassed 48
horizontal directional drilling crossings,
11 major river crossings, 276 water body
crossings, steep pipeline trenches
GLOBAL ENERGY AWARDS
approaching a 60-degree slope, 20
railway crossings and 382 road crossings.
Logistical coordination efforts included
65 vendors and contractors, and nine
million km of vehicle movements for raw
materials, pipeline and heavy machinery.
Despite the challenges, the DabholBangalore Pipeline boasted one million
incident-free man days and was
completed within three years. The project
was also on budget; careful planning and
project management, including use of
innovative bidding methodology such as
reverse auctions for line pipes, achieved
cost savings nearing 40%. The judges
applauded GAIL’s strategic thinking and
perseverance in bringing efficiency to
India’s gas grid.
Premier Project Award
Engineering
Hatch Ltd. & Hatch Mott MacDonald
Canada
The winner of the Premier Project Award
in the Engineering category is ambitious
not only in its dazzling scale, but also in
its contribution towards achieving a
larger goal. Ontario Power Generation’s
Niagara Tunnel, located in Niagara Falls,
Ontario, Canada, is the largest
hydroelectric project completed in
Ontario in the past 50 years. The tunnel
diverts water from the Niagara River and
carries it downstream to the Sir Adam
Beck generating complex, propelling
water by gravity alone at an incredible
500 cubic metres (17,660 cubic feet) per
second, fast enough to fill an Olympicsized swimming pool in a matter of
seconds. This renewable energy initiative
was undertaken by consulting
engineering firm Hatch, a 2,400-person
employee-owned firm focusing on
infrastructure, transportation, and
environmental engineering.
Construction of the Niagara Tunnel
involved the use of “Big Becky,” the
world’s largest hard rock tunnel-boring
machine (TBM), which is as high as a
four-story building, longer than a
football field and weighs in at 4,000
tonnes. The TBM excavated a 10.2-kmlong water diversion tunnel between the
Niagara River above the Horseshoe Falls
and the Sir Adam Beck hydro-generating
complex down river. The tunnel is nearly
twice the diameter of the Euro Channel
railway tunnels, and will deliver an
additional 500 M3’s of water to hydro
stations, facilitating an increase of 1,500
GWh (13%) in average annual clean
renewable and reliable energy
production.
Hatch overcame many logistical hurdles
on the project. All underground work
had to be accessed from a single entrance
at the outlet end of the tunnel, so all
tunnel operational equipment had to be
designed to allow traffic to pass to and
from the TBM. Concrete was at times
pumped 1.4 km, requiring very precise
mix design and quality control. And
because the excavation proceeded from
the outlet end of the water conveyance to
the intake end, which is located
immediately below the International
Niagara Control Structure in the upper
Niagara River, about 2 km upstream of
the Horseshoe Falls, preventative
measures had to be taken to prevent
potentially serious groundwater inflow
during TBM excavation.
The Niagara Tunnel was safely completed
in March 2013, nine months ahead of
schedule and $100M under its $1.6B
budget. The tunnel will provide the
province with a reliable, maintenancefree source of clean energy for the next
100 years. It is also a key element of Ź
DECEMBER 2013
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GLOBAL ENERGY AWARDS
what judges called Ontario Power’s
“ambitious but attainable” long-term
energy plan including closure of the
remaining three coal-fired generating
stations. The judges unanimously praised
Hatch and its Niagara Tunnel for its
overall technical complexity, logistical
execution, and innovative use of
technology.
Leading Technology Award:
Commercial Application
The Global Energy Awards’ Leading
Technology category drew many
well-qualified entries this year. After
vigorous debate, judges elected to
name two winners in the category, to
recognize two companies that stood
out for their use of technology at both
ends of the energy spectrum; one
driven by energy production and
supply, and one driven by energy
consumption.
Leading Technology Award
the offshore oil and gas industry faced
post-Macondo, where operators and
drilling contractors began to review
long-established well integrity practices,
with a renewed focus on the safe and
reliable containment of well fluids. Meta
seeks to redefine well integrity, therefore
reducing risk, protecting and
maximizing future production, and
delivering safe, productive and
profitable wells.
Meta’s solutions are based around
Metalmorphology™, its unique
technology that allows metal to be
shaped downhole, delivering instant, gas
tight, V0 certified and permanent
metal-to-metal isolation. The process
uses established metal working
principles that balance steel’s mechanical
strength to create solutions that ‘morph’
together and conform perfectly to the
shape of the well. The result is well
integrity solutions that last across the
well’s lifecycle.
Commercial Application
Meta Downhole Ltd.
United Kingdom
Aberdeen-based Meta Downhole is a
premium downhole isolation company
specializing in well integrity. The
company provides well isolation
solutions across the lifetime of an oil and
gas well – from well architecture and
design through to completion,
production and decommissioning. Meta,
a private venture capital-backed
company, services an international client
base with offices in the United
Kingdom, Middle East, Far East and the
United States.
Since its founding in 2012, Meta has
created a completely new market space
in well integrity management. The
company was born out of the challenges
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insight
DECEMBER 2013
Meta’s downhole isolation solutions are
rigorously tested in the company’s
testing facilities, among the most
advanced of their kind in Europe. With
the ability to simulate downhole
conditions accurately, Metalmorphology
has been proven to deal with axial
load-bearing forces of up to 6 million lbs
and temperatures of over 320ºF.
Through its technology, Meta helps
operators reduce risk and ensure that
they comply with regulatory standards. It
also assists operators in protecting and
maximizing future production with
minimal well downtime and the
building-in of well structural and zonal
integrity at the outset of the well. It helps
deliver profitable and productive wells
through the safeguarding against
GLOBAL ENERGY AWARDS
predictable trouble zones and weak spots
and the ability to optimize productivity
from all producing zones.
In a short time, Meta has achieved
record-breaking revenues, profits and
EBITDA value, as well as building a
forward order book in excess of $100
million. Judges were excited by Meta’s
developments and noted that when
materials are at play, the opportunity
exists for a ripple effect across multiple
industries. Meta’s commercially
available, technologically proven and
innovative products are creating a new
market space and opening up a new era
in well integrity.
Leading Technology Award
Commercial Application
Caterpillar Inc.
United States
Founded in 1925, Caterpillar is the
world’s leading manufacturer of
construction and mining equipment,
diesel and natural gas engines, industrial
gas turbines and diesel-electric
locomotives. The Peoria, Illinois-based
company reported 2012 sales and
revenues of $65.875 billion. In such a
large company, small changes can have
impressive impact; in Caterpillar’s case,
its compressed-hydraulics approach to
hybrids has taken the technology from
consumer cars into heavy equipment.
Caterpillar’s efforts demonstrate the
potential far-reaching effects of this
technology, which Global Energy Awards
judges felt honored the intent of the
Leading Technology Award.
The company created its Cat® 336E H
Hybrid Excavator by applying three main
technologies: it conserves fuel with
engine power management, optimizes
performance using restriction
management, and re-uses energy via the
hydraulic hybrid swing, which captures
the excavator’s upper structure swing
brake energy in accumulators, and then
releases the energy during swing
acceleration.
This hydraulic hybrid technology uses up
to 25% less fuel compared to a standard
model, and offers up to 50%
improvement in fuel efficiency, without
sacrificing performance. A 25% fuel
consumption reduction yields a savings
of 23.6 gallons over an eight-hour shift
or potentially more than 5,900 gallons
over the course of one year. At $4 per
gallon of diesel fuel, this represents a
savings of $23,600 per year/machine.
Assuming current fuel prices, Caterpillar
estimates that customers will recover
their incremental hybrid investment in as
little as one year, with 18 months typical.
The 336E also produces additional
environmental sustainability benefits,
such as significantly reduced operating
noise and exhaust emissions; it is a
quieter, cleaner machine than its
ancestors. It is a hybrid that reduces
customer costs sustainably, with no
negative impact on machine
performance. Judges were vociferous in
their enthusiasm for the cumulative
global impact of a 25% fuel savings on
heavy equipment machines that are used
across so many industries, worldwide.
Caterpillar is developing additional
models featuring its fuel-saving hybrid
technology to meet the needs of a global
marketplace with varying emissions
regulations. Caterpillar expects that its
expanding application of the technology
will continue producing competitive
advantages and commercial gains for the
company by increasing sales, revenues Ź
DECEMBER 2013
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GLOBAL ENERGY AWARDS
and profits. The company considers the
336E one of its most significant
achievements in a long history of
engineering innovations – technologically,
sustainably and commercially.
modification system to create a
proprietary gas-fermentation microbe,
the company has made a dramatic
advance along the biotechnology frontier,
with a potentially transformational
impact on the world’s energy industries.
Leading Technology Award
Sustainable Innovation
LanzaTech
United States
LanzaTech put sustainability into the
2013 Leading Technology Award for
Sustainable Innovation – the company
received the same honor in 2011. Judges
conceded that winning the award twice
in three years is extremely rare; however,
they felt strongly that LanzaTech is once
again worthy of the honor.
LanzaTech was founded in New Zealand
in 2005, with a mission to develop and
commercialize technologies for the
production of cost competitive, low
carbon fuels and chemicals that do not
compromise food or land resources. Now
headquartered in the United States and
operating on four continents,
LanzaTech’s technology converts local,
abundant industrial waste and low cost
resources into sustainable, valuable
commodities. By using readily available
resources, LanzaTech provides a
strategically important source of
sustainable energy.
LanzaTech captures value from what has
long been seen as a waste product. The
company transforms carbon-rich waste
gases (from industrial sources such as
steel mills and processing plants) and
synthesis gas (from any biomass resource
such as municipal solid waste, organic
industrial waste and agricultural waste)
into fuel-grade ethanol or chemicals that
can be used in the manufacture of new
products. By developing a genetic
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DECEMBER 2013
LanzaTech has raised more than $100
million in capital and has a diverse
pipeline of products in development:
ethanol for use as fuel and as a chemical
intermediate; platform chemicals; and
hydrocarbon fuels including diesel, jet
and gasoline. The company estimates
more than 50% of steel mills worldwide
use technology that could be retrofitted
to include its process, which translates to
30 billion gallons of ethanol or 15 billion
gallons of sustainable aviation fuel –
about 19% of the current world aviation
fuel demand.
LanzaTech is the first company ever to
scale gas fermentation technology to a
pre-commercial level, developing and
successfully operating two facilities that
convert waste flue gas from Baosteel and
Shougang steel plants into ethanol. Both
facilities in China operated at annualized
production capacity of 100,000 gallons.
Site location and engineering plans for
two full commercial facilities are under
way, with commercial production
expected to begin in 2014.
Judges appreciated that LanzaTech has
addressed all three variables that drive the
cost of biofuel production: technology,
feedstock and transportation. The
company is highly efficient, utilizes waste
resources, and can be installed at the
source of the feedstock. LanzaTech’s
technology represents new ways to
produce fuels that are cost-competitive
without subsidies, and products that are
critical parts of daily life. Ŷ
Our Children Turn to Us for a Brighter Energy Future
Too many of the world’s children have no modern
energy in their lives… no lights to read by, no
computers for school work, no digital devices
to bring their communities into the 21st Century.
Advanced coal is changing all of that. Coal has
been the world’s fastest growing major fuel of
the 21st Century. And coal is expected to pass
oil as the world’s largest energy source in coming
years. Coal-fueled electricity enables laptops
for students, cell phones for villagers, safe lights
for cities and modern appliances for families.
And technology will continue to drive new uses
for coal including carbon capture, use and storage.
All over the world, advanced coal is creating
electricity that is abundant, inexpensive and clean.
Coal has driven the world’s best economies,
raising hundreds of millions out of energy
poverty in recent years.
But there is much more to be done. Some
3.6 billion people in the world have little or no
access to electricity. Another 2 billion people
will join the global population over the next two
decades. Energy poverty is the number one issue
facing the world today. Advanced coal is the best
energy source to provide abundant, low-cost
electricity at the scale needed to solve this
challenge.
Let’s work together to bring energy access
to all by 2050.
Find out more at PeabodyEnergy.com
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