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LOW OIL PRICES AND LNG
2015
ILLUSTRATIONS BY
ALEX WILLIAMSON
By Michael Stoppard
WITHSTANDING THE ROUGH SEAS AHEAD
@MStoppard
E
ven before oil prices began to fall last year, the liquefied natural gas (LNG) industry faced significant challenges. The first was a shortage
of demand, at least when measured against prospective supply. Although demand is expected to grow strongly, the number of proposed
projects still far exceeded the needs of likely customers. The second was spiraling costs. The IHS Upstream Capital Cost Index, which
measures exploration and production costs of the oil and gas industry as a whole, more than doubled over the past decade. By comparison,
during the same period, the cost of a new gas liquefaction plant grew far more rapidly, by a factor of four or five times.
Low oil prices have now injected more
turbulence. For the foreseeable future,
the industry will encounter rough seas.
The long-term economic fundamentals remain sound, but market volatility
and low oil prices will make it difficult
to embark on new projects. There is
some good news: While lower oil prices
complicate the supply side, they provide a stimulus to demand. Lower oilindexed prices could open up the LNG
market in key emerging economies and
spur efforts to reduce costs. These developments could put the industry on a
stronger footing for the long term.
The first big impact created by lower
oil prices is very direct — they effectively lead to lower LNG prices. Most
LNG is sold under long-term contracts,
and prices in these contracts are typically linked to the price of oil. So as oil
prices fall, LNG prices fall in turn, after
a lag of several months and according to
pre-agreed formulas. Some contracts include clauses that soften the price drop,
but such measures exist in a minority of
cases. IHS expects prices to drop considerably in 2015 versus last year. For example, Japan’s weighted average import
price for 2015 is projected to be below $10
per million Btu (MMBtu), as opposed to
nearly $16 per MMBtu in 2014. Spot LNG
prices have already plummeted.
A bright side of lower prices is that
they could bring new customers to
the LNG market. Oil-indexed contracts in recent years have simply
proved too expensive for many aspiring buyers. Now producers can offer the same oil-indexed contracts as
before, but with lower oil prices, they
will in effect be offering customers
lower prices for LNG. The gap between
buyer and seller around the negoti-
ating table has narrowed. This could
bring in new customers, especially in
emerging markets, which are the most
price-sensitive. Primary targets include
Bangladesh, Egypt, Jamaica, Pakistan,
the Philippines, Panama, South Africa
and Vietnam, as well as upside in the
existing market of India. The catch is
that oil prices will need to remain both
low enough in the future to support this
demand, and also high enough to support new project investments. To make
inroads in emerging economies that
are less credit-worthy, LNG developers
may also need to support buyers by investing in their downstream infrastructure and, critically, by providing forms
of credit support.
Despite the current low oil prices,
most LNG projects remain economically robust over the long term. IHS Energy
has calculated the oil-price thresholds
required to cover life-cycle costs and
provide an appropriate return for LNG
projects. A typical greenfield project —
for example in East Africa or Western
Canada — requires a “free-on-board”
(FOB) price of around $10-12 per
MMBtu. With pricing at the historically
normal ratio to oil, such projects would
require oil prices in the range of $70-82
per barrel to break even. This is within
the range of most anticipated longterm oil prices.
To take advantage of current opportunities and to enhance the long-term
competitiveness of LNG, developers
must reduce costs. There are a host of
options. Many developers are promoting miniaturization: smaller-scale projects that hope to achieve lower unit
costs and reduced project complexity. Modularization — fabricating key
components in low-cost regions and
assembling on-site — is another promising avenue for cost reduction. This can
be done even with large-scale projects
made up of a number of smaller units.
Standardization is another option (see
related article in this special section
on standardization as a tool for cutting
costs in oil exploration and production).
Cost savings can also be achieved by
reducing the local content that is often
required by resource-holding governments. Such provisions were common
when oil prices were high, but they
can be carried too far and end up adding costs and/or delaying projects, affecting the competitiveness of projects.
The kind of local content requirements
imposed in an era of high prices will require revisiting in light of current prices.
The threat to new LNG projects is less
economic and more financial. Shortterm price swings ought not to have
strong impact on new investments that
will require five or 10 years to come online, but in fact, prices today do matter.
Critically, terms in LNG contracts have
reflected the status of the market at the
time of negotiation, not the time of delivery. Given that, today’s weak market
means any contract signed today will
involve weaker terms for sellers.
Companies will generally find it difficult to invest against the current cycle,
especially at a time when capital budgets are being slashed. LNG projects,
especially traditional integrated international projects, risk being cut if they
rank at the low end of a company’s project list in their internal rate of return or
if they are at the high end as a draw on
capital. Those in the early stages could
very well end up being postponed for
an indefinite period of time.
Some of the strongest and largest
To Readers
The rapid drop in oil prices and continuing geopolitical and economic uncertainty are buffeting both the
energy industry and many countries and will continue to
have a significant impact on the world economy in 2015.
These developments raise critical questions: How
will the oil-price collapse affect the energy industry and
the global economy? What will be the price path from
here? Is the United States the new “swing producer”?
What will happen to energy demand, with the United
States growing robustly and a mixed outlook in Europe and China? How will geopolitical upheaval, with
trouble breaking out in multiple global hot spots, affect
energy supplies? How much of a threat are cyberattacks and what can be done to respond? Are there new
transformative innovations on the horizon that could
have an impact like hydraulic fracturing has had over
the past decade? And what role will policy and regulation play, especially leading up to the Paris climate talks
next December?
This special section, Turning Point: Energy’s New
World, addresses several key issues at the heart of the
current energy picture:
• How the drop in oil prices is creating turbulence for the
liquefied natural gas industry;
• The “missing money problem” in the electric power
sector that will hinder new investment and lead to
premature shutdowns of existing facilities;
“ Standardization” as a significant opportunity for the
oil and gas industry to reduce costs of major projects;
• Why China’s energy demand is now growing more
slowly and what it means for the rest of the world.
Yesterday’s special section examined future prospects for oil production in the United States, the rise of
utility-scale solar generation and the implications of
Europe’s new Energy Union.
We are pleased to partner again in these special
sections with The Wall Street Journal during the 34th IHS
Energy CERAWeek conference, April 20-24, in Houston, Texas. CERAWeek is recognized as the preeminent
gathering for the global energy industry. This year’s conference will feature presentations and interactive sessions by more than 250 senior executives, government
officials, thought leaders and IHS experts. We anticipate
attendance of nearly 3,000 participants from more than
55 countries. Join us online at www.ceraweek.com
As we embark on our 34th CERAWeek conference,
we invite you to share in new perspectives on the energy
future through the insights in these pages.
•
Daniel Yergin
IHS Vice Chairman and
Chairman of IHS CERAWeek
Author of The Quest and The Prize
@DanielYergin
companies may continue to invest
against the cycle. A prominent prior
example is the go-ahead decision on
Gorgon LNG made in 2009 after the oil
price crash that followed the 2008 financial crisis. Gorgon’s partners were financially strong and willing to look beyond
the immediate horizon. But most LNG
projects involve complex consortia that
move at the pace of the slowest or weakest partner. Few projects are likely to
have partners all able to operate free of
current constraints.
National oil companies (NOCs) of
importing countries like China, India,
Japan and Thailand will have an opportunity to acquire and develop LNG
for their domestic market at attractive
terms and may partially be able to fill
the gap created by reduced activity on
the part of international oil companies
(IOCs). But NOCs often lack the critical
operating experience, which poses an
additional set of challenges.
So will LNG continue to play a major role in the future? Despite current
challenges, the answer is an unequivocal “yes.” Given the abundance of
gas resources in the portfolios of
industry players, there are strong incentives — and a need — to ensure
continued LNG development. And
LNG will continue to offer an attractive clean-energy source. Low oil prices
have created turbulence but could also
create the requisite pressure to drive
innovations that open up new markets and reduce costs. The prospect of
those efforts coming to fruition is the
silver lining amid the storm clouds the
LNG industry is now encountering.
Michael Stoppard is Chief Strategist, Global
Gas at IHS Energy.
About IHS
www.ihs.com
IHS (NYSE: IHS) is the leading source of
insight, analytics and expertise in critical
areas that shape today’s business landscape. Businesses and governments in
more than 150 countries around the globe
rely on the comprehensive content, expert
independent analysis and flexible delivery
methods of IHS to make high-impact decisions and develop strategies with speed
and confidence. IHS has been in business
since 1959 and became a publicly traded
company on the New York Stock Exchange
in 2005. Headquartered in Englewood,
Colorado, USA, IHS is committed to sustainable growth and employs about 8,800
people in 32 countries around the world.
IHS is a registered trademark of IHS Inc. All
other company and product names may be
trademarks of their respective owners.
© 2015 IHS Inc. All rights reserved.
This special section was prepared by
IHS research staff and did not involve
The Wall Street Journal news organization.
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2015
THE ELECTRIC POWER INDUSTRY’S MISSING MONEY PROBLEM
A
Continued on next page
$0.40
AVERAGE AND INCREMENTAL COST OF TYPICAL
U.S. NATURAL GAS-FIRED COMBINED CYCLE
POWER GENERATION PLANT
Cents per kWh
By Lawrence Makovich
quarter century ago, a large-scale restructuring of the electric power
industry got underway in both North America and Europe. The effort
was termed “deregulation” on this side of the Atlantic and “liberalization” on the other. But things do not always work out according to
plan — and that is what happened here. Restructuring in the United
States never reached its intended end state because of what economists call
“the missing money problem.” This is a market failure arising from the quite
distinctive cost structures of the technologies involved in power generation
that prevent electricity markets from working the way the marketplace does in
economics textbooks. The problem can be summed up this way: Competitive
forces drive rival suppliers (who have already built their power plants) to bid to
provide electricity in the market at prices high enough to cover variable costs
but too low to cover total costs. The resulting gap between market clearing prices and average total costs causes too many power plants to retire before it is
economic for them to do so. Similarly, chronically low prices prevent the timely development of new power supply. The combination of too few new power
plants being built and too many existing power plants closing down threatens
the future adequacy of America’s power supply. How well — or poorly — power
systems address the missing money problem today and in the years to come
will be one of the key factors shaping the future of the
electricity sector.
The missing money problem arises because of the
inherent characteristics of electric power production. Building a power generation facility requires a
large up-front expenditure, and these fixed costs cannot be altered in the short run. Consequently, for
electricity generated by conventional technologies —
which still account for more than two-thirds of world
supply — fuel is the only significant input that can alter
the amount of power generated in the short run.
A modern natural gas-fired power plant built in North
America can produce electricity at an average total
cost — which includes the up-front investment — of
around 14 cents per kilowatt-hour (kWh) at low utilization rates and around 7 cents per kWh at maximum
utilization. Variable costs account for a little over half
of total costs. When owners of rival facilities with these
cost characteristics bid against each other in wholesale
markets, they are willing to provide additional electricity
for any price above the variable cost because supplying
power at that price provides some contribution towards
fixed costs. Consequently, competitive forces tend to
drive market-clearing prices to short run marginal costs.
But here’s the catch: As power plant utilization rates increase, the gap between incremental costs and average
total costs narrows, but does not fully close (see chart).
As a result, when power demand and supply are in
balance — including reserve capacity needed to insure
reliability — the market-clearing price remains below average total cost. The average power plant utilization rate
in the U.S. is around 45 percent. At this rate, the marginal
cost-based price only covers about half of the average total
cost. As the example above shows, suppliers that sell their
power in wholesale markets face a significant missing
money problem.
The missing money problem surfaces in even starker
relief with generation technologies such as hydro, wind
and solar. These require no fuel, so the short-run marginal cost of production is effectively zero. Suppliers of
electricity from these sources therefore face short-run
incentives to offer their power at any price greater than
zero. As a result, when hydro, wind and solar are competing to meet a change in demand, the market-clearing price tends to be driven toward zero. This problem
is most pronounced in the liberalized power markets
of Europe.
In the United States, the missing money problem is
made worse by policies that subsidize renewable power,
which exist in 38 states. When renewable power sources
compete in wholesale markets, their owners recognize
that losing a bid means losing the opportunity to collect
subsidies. Consequently, owners of renewable power
sometimes respond by bidding negative prices — effectively offering to pay customers to take their power — as
long as the available subsidies can more than cover sums
paid to customers.
Besides depressing energy prices, renewables such as
wind and solar also typically increase the costs of conventional generation. This is because power systems
need conventional generating technologies to back up
and fill in for intermittent renewable sources. But doing
so makes utilization rates at conventional plants lower
and more varied. These so-called added “integration”
costs only worsen the missing money problem.
Market-based pricing and well-intentioned subsidies
for renewable power have therefore brought about an
unexpected result. Prices on wholesale electric power
markets chronically settle at levels below those required
for producers to recover the full cost of their operations.
This has had a very notable effect on merchant power
suppliers. These are companies that specialize in producing electricity and selling it to wholesale markets, but
do not own the wires that distribute electricity to homeowners and businesses in particular cities or regions. The
missing money problem was one of the primary reasons
why bankruptcy reorganization was the rule rather than
the exception for merchant generators in the era of deregulation. Over the last 15 years, these merchant generators have written down billions of dollars of power
plant investments.
The missing money problem has three major consequences. The first is the risk of underinvestment in new
power supply. Second, low prices are causing many
existing power plants to be retired early, even though
their continued operation would be far less costly than
replacing the supply they now provide. Several nuclear
plants have closed prematurely in the past few years and
more than a dozen are vulnerable to closure in the years
$0.00
SOURCE: IHS
5%
Utilization rate
90%
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2015
THE URGENT NEED TO REDUCE OIL INDUSTRY COSTS
ILLUSTRATION BY
ALEX WILLIAMSON
IS STANDARDIZATION
THE KEY?
250
UPSTREAM CAPITAL COST INDEX
By Paul Markwell and Chad Hawkinson
Q4 2014
229
orld oil prices have fallen by half since last
autumn. Even before the collapse, reducing costs was already seen as a priority.
Now it is an absolute necessity. And it’s
high time. Prior to the recent crash, oil prices had
hovered around $100 per barrel for almost half a
decade. Despite high prices, oil and oil services
companies have posted modest recent returns,
100
due to their burgeoning costs.
2000
Years
2014
Why the increased costs? A major reason is the
SOURCE:
IHS
complexity of many exploration and development projects. This complexity rose as companies
tapped into deeper water, tighter rock and mature
Companies active in oil and gas exploration and profields that required more operational attention.
duction
(E&P) today rely heavily on industry standards.
Moreover, many new projects were in emerging markets
It
is
estimated
that the 120,000 engineers working for
or remote areas with limited infrastructure, and operatthe
top
500
energy
companies in the world relied on
ing in such locations also drove up costs. In addition,
80,000
different
industry
standards from over 135 stanrising global demand for skilled workers and for comdards
bodies.
But
most
oil and gas companies also
modities such as steel led to higher supply chain costs.
complement industry standards with their own internal
IHS tracks major aspects of upstream costs, and its capiproprietary standards to build, maintain and operate
tal costs index and other relevant indices have more
their upstream infrastructure. These internal standards
than doubled over the past decade (see chart).
may leverage industry-approved standards as a startIt’s now imperative that oil and oil services companies
ing point, but companies then often layer on additional
reduce costs to maintain viable returns. The industry has
company-specific requirements to ensure reliability and
faced downcycles before and knows the usual responses
safety, increase efficiency, address challenges seen on
well: convince suppliers to provide the same for less; rapast projects, improve maintainability, encapsulate cortion capital spending; restructure internally to reduce
porate practices, and reflect the perspectives and experioverhead; and try to negotiate better terms with host
ence of internal groups. As an illustrative example, an oil
governments. An additional avenue for reducing costs
and gas company could decide that all of their electrical
today is adoption of innovative technologies such as
equipment boxes be painted orange instead of industryautomation/unmanned systems, advanced sensors and
standard green.
sophisticated data analytics.
Oil companies are now realizing that proprietary stanOil and oil services companies are already busy trydards
can significantly drive up costs, while industrying the approaches listed above. But there is another rewide
agreement
on common standards can spread costs
sponse as well that could enable a step-change advance
across a larger base and thus reduce them. Companies
in cost performance. This would be to get back to basics
that rely on internal standards typically spend between
and simplify the problem. How? Through greater reli20 and 100 percent more than those that rely on industry
ance on industry-wide standards.
standards. And in some cases, the costs associated with
First, it’s important to understand what standards are:
proprietary standards can be as much as 10 times greater.
best practices agreed upon by industry participants. For
Why? In the case of the orange electrical equipment box
example, the American Petroleum Institute (API) has
cited above, the color change leads to extra manufacturcreated committees of experts from a wide array of oil
ing time and also requires the supplier to carry additionand gas operating companies, equipment suppliers and
al inventory. In the case of large, complex E&P projects,
services companies to agree on best practices (or stanengineers at the engineering, procurement and condards) for designing, installing and maintaining pumps
struction (EPC) firms that build upstream infrastructure
and valves to maximize safety, reliability and operational
have to get up to speed on different proprietary requireefficiency. Adhering to standards can be mandatory and
ments for every project, which limits knowledge reuse
enforced by regulation, as with the American Society of
and scale, thereby adding costs and delaying schedules.
Mechanical Engineers’ (ASME) Boiler & Pressure Vessel
Across thousands of projects in the industry, the impact
Code. Many other standards are voluntary.
is billions of dollars in additional costs and delays.
Standards can also ensure efficient interoperability
Internal standards are also difficult to maintain. In
across different manufacturers, enabling a competitive
most
cases, the rationale behind internal standards remarket and facilitating faster adoption of new technolsides
in
the minds of senior engineers who have worked
ogy. Because of standards, any gas station you pull into
at
their
companies
for decades. But the oil industry now
has a pump that will fit your car. Your laptop connects
faces
what
observers
call the “Big Crew Change.” Oil
to your mobile phone, as well as your printer and your
companies
hired
many
Baby Boomers during the 1970s
wireless router, even though they are from different
and
early
1980s,
when
prices
were high during and after
manufacturers. This is because companies in the tech
the
oil
crises
of
the
1970s.
But
between the mid-1980s
industry adhere to common standards for how these
and the start of the new century, hiring was modest. As
devices connect.
Cost Index (2000=100)
W
IHS Energy Analysis Related to Today’s Articles
GLOBAL LNG SUITE
Provides ongoing research and analysis of the
complete LNG value chain, including short-term trade
forecasts and long-term trends.
Continued from previous page
to come. Left unaddressed, the missing
money problem could lead to a reprise in
other regions of the power shortages that
plagued California in 2000-2001, when
consumers experienced dramatic price
spikes, brownouts and rolling blackouts.
Third, low prices distort market signals
and lead to an inefficient mix of fuels
and technologies. IHS estimates such
inefficiencies are moving the cost of fuel
used to generate electricity in the United
States to a level 9 percent higher than it
should be.
There is no one-size-fits-all solution
a result, many technical professionals in the industry are nearing retirement age, and there is a dearth
of mid-career people ready to replace them. As Baby
Boomers retire — and over the next five to 10 years,
it is estimated that 50 percent of U.S. petroleum engineers will be eligible to do so — the expertise required to maintain customized internal standards is
being lost. The challenge becomes even greater as oil
companies postpone hiring or reduce headcount to
cut costs in the wake of the price drop.
IHS has been researching this question and has
found that oil companies can replace a significant
percentage of internal proprietary standards with
industry standards while maintaining the same levels of reliability and safety. And shifting away from
proprietary standards can provide dramatic cost improvements of more than 25 percent and faster time
to market.
How can companies take advantage of standards
to cut costs? By adopting industry standards and making
them more robust.
A first step is to move away — where feasible and appropriate — from proprietary standards, or from custom
adaptations on top of industry standards, and toward
adoption of pure industry standards.
There are also opportunities to make the standards
that exist more useful and effective. Many industry
standards settle on only basic requirements because
it’s easier to get companies to agree on them. Also, in
some instances, multiple standards-setting bodies lead
to overlapping or conflicting rules; when this happens,
there isn’t a clearly accepted standard that the entire industry agrees to uphold. Because of practices like these,
there are now, for example, over 328 industry standards
that apply to valves. But the executive-level mandate to
cut costs has given the industry a compelling reason to
drive the difficult-to-achieve consensus needed to develop better and more complete standards. New industry working groups can be created to forge consensus,
with senior executives from leading companies providing the impetus for change.
This is no theoretical prospect. The aerospace sector
has shown that widespread adoption of industry standards can drive unprecedented cost benefits, along
with safety enhancements, while still allowing firms
to achieve competitive advantage on the basis of their
distinctive capabilities. In addition, the United States
Department of Defense (DoD) MilSpec Reform effort
in the 1990s demonstrated that with the right level of
leadership attention, dramatic reductions in proprietary
standards and broad adoption of industry standards can
be achieved. In the case of the DoD effort, billions of dollars have been saved.
This year, capital spending by the energy sector for
exploration and production is expected to total nearly
$750 billion. Reducing those expenditures by even a few
percentage points could lead to savings totaling tens
of billions of dollars. The potential is therefore huge.
Today’s low energy prices provide strong incentives —
and indeed the urgent need — for oil and oil services
companies to embark on the path toward a new level of
industry standards.
Paul Markwell is Vice President of Upstream Oil & Gas
Consulting at IHS. Chad Hawkinson is Senior Vice President of
Standards and Engineering Excellence at IHS.
To learn more, contact [email protected]
BRIDGING THE MISSING MONEY GAP
INDUSTRY STANDARDIZATION SERVICE
CHINA ENERGY SERVICES
This study identifies the causes of cash-flow shortfalls in the electric power industry and recommends
cost-effective solutions.
IHS provides information, software and expertise
to help companies optimize internal standards and
transition more effectively to industry standards.
Provides comprehensive insights into the world’s
largest and fastest-growing energy market, including
oil and gas, power, coal and renewables.
to the missing money problem. Each
regional power system has its own characteristics, and the best mix of solutions
in any particular setting will depend on
the distinctive characteristics of that system. But IHS, in consultation with key
industry stakeholders, has identified 13
different approaches currently being
employed, or considered, to address the
missing money problem. On the table
are a whole range of approaches from
adding capacity markets to moving back
toward more regulation or public ownership. There is much debate about what
to do. No one-size-fits-all solution exists
because current regulatory and market conditions vary significantly from
one regional power system to the next.
Evaluating these approaches against
multiple criteria has shown that some
approaches, alone or in combination,
can meaningfully address the missing
money problem. Conversely, some approaches are not likely to provide the
building blocks of an effective solution
under any conditions — and could make
matters worse.
Any measures put forward to address
the missing money problem should reflect the interests of all key power sector
stakeholders: electricity generators and
operators of wholesale markets, as well
as consumers, elected representatives
and regulators. Implementing effective
solutions will first require convincing
power-system stakeholders that a problem exists as well as getting them to agree
on its nature and causes. Only then will
they be able to reach consensus on an effective suite of remedies. And it is better
to do all this before a crisis than after.
Lawrence Makovich is Vice President and
Senior Advisor for Global Power at IHS and lead
author of the IHS Multiclient Special Report,
Bridging the Missing Money Problem.
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2015
WHAT IS HAPPENING TO CHINA’S DEMAND FOR ENERGY?
By Xizhou Zhou
were chiefly responsible for this slowdown, due to the deceleration in industrial
growth. And IHS Energy expects Chinese
oil demand to grow at only 3 to 4 percent
annually over the next few years.
Electric power demand in China grew 12
percent per year on average between 2002
and 2011. The country’s power generation
fleet tripled in size, making it the largest in
the world. In the mid-2000s, China was adding as much capacity each year as now exists in all of France
25
or Great Britain.
Power consumption growth since
2011, however, has
averaged only 6
GROWTH OF CHINA’S
ENERGY DEMAND
Year-on-year % growth
A
fter a decade of phenomenal expansion, the growth in energy consumption in China appears to be slowing
down. Whether oil or natural gas, electricity or coal, the rate of growth has been
decelerating compared with the pace just
a few years ago (see figure). “Go to China”
was long the mantra for energy companies around the world. But many players
are asking a very different question today:
What happened to what was thought to be
China’s insatiable appetite for energy? The
firms that targeted China are feeling much
justified anxiety. They will all need to adjust to the new reality of slower growth.
What is behind this slowdown in the
growth of energy consumption in China?
It is the rebalancing that is now going on
in China’s overall economy. The previous investment-led model of growth is
giving way to greater reliance on domestic consumption. That is already evident
in the numbers. Investment is no longer the main engine of China’s growth:
Consumption accounted for 49 percent
of GDP growth in 2014, compared with 41
percent through fixed-capital formation.
The shift to relying more on domestic
consumption has also led to less emphasis on exports. With two of the three
long-standing GDP drivers — investment
and exports — slowing, overall economic
growth was down to 7.4 percent in 2014.
Beijing appears content with this
change in direction. The prime minister
has even modified the official growth rhetoric in public speeches from the decadelong motto of “relatively high growth” to
“medium-high growth.” IHS Economics
expects China’s growth to slow further to
6.5 percent in 2015 and 2016.
Energy consumption has already responded. Between 2001 and 2011, China’s
oil demand doubled to reach more than 9
million barrels per day (mbd). The country
accounted for over half of the incremental increase in global oil demand during
that period. Since 2011, however, growth
has weakened greatly, expanding at only
4 percent annually instead of the average
rate of 8 percent during the prior decade.
Industrial fuels (diesel, fuel oil, naphtha)
DECELERATING 0
2010
-5
SOURCE: IHS
percent per year. The investment-to-consumption shift hits power demand especially hard, since industry accounts for 70
percent of China’s electricity consumption.
Relatively slow growth in power demand is
expected to continue, in line with the economic outlook.
Meanwhile, substantial new capacity additions are still coming online. New
hydro projects slated to enter service over
the next three years, for example, would be
sufficient to supply the electricity needs of
the entire country of Austria. The decisions
to invest in these large projects were made
when China’s power consumption was still
growing at double-digit rates. But approval
and construction took time. These projects’ entrance into service is now expected
to lead to lower average utilization hours
for power plants. This will have significant
implications for power producers, equipment manufacturers and fuel suppliers.
The coal sector is acutely feeling this
slowdown as nearly three-quarters of
China’s electricity is generated from coal.
In 2014, for the first time this century,
Chinese coal consumption and raw coal
production both declined. And with a concerted policy drive underway to curb air
pollution in coastal cities, it is likely that
coastal China’s coal demand has peaked
and spot prices last winter, usually a peak
demand season, were reported to be less
than $7 per million BTU, from as high as
$20 several years ago.
A decade of robust demand growth and
high commodity prices made many forget the cycles that are endemic in the energy industry. The recent supercycle made
China one of the most important drivers in
the global energy system. Because of that,
its deceleration is of particular importance
for the world. The outlook in China now is
for slower growth in oil demand, decreased
coal-fired power plant
utilization, overcapacity
in coal mines and slower
Electricity demand
uptake for imported gas.
Coal demand
While these trends
pose risks for compaDiesel demand
nies that have invested
in China, they also create potential opportunities. Investment in
long-distance
power
transmission
lines
could unlock cheap coal
and other resources
in Western China; this
2013
2011
2012
means that even though
2014
coastal coal consumption has peaked, national demand for coal will
continue to grow well
into the 2020s. The more
and is now in long-term decline. This was abundant supply of global gas — combined
unthinkable only a few years ago. Coal with Beijing’s push for cleaner fuels and gas
prices have fallen precipitously from a high infrastructure reforms — also means that
of over RMB 840 ($130) per ton in 2011 to Chinese utilities may be able to procure gas
less than RMB 500 ($80) today.
directly in the international market to meet
Coal’s main competitor in many mar- continued demand growth.
kets — natural gas — is also affected. As
It must be remembered that after a derecently as 2010, China was in desperate cade plus of rapid growth, China’s base
need of more gas, with demand outpac- of energy demand is many times bigger
ing domestic supply. In response, China’s than at the start of the century. So even a
national oil companies signed many long- slower rate of growth on this much larger
term contracts for liquefied natural gas base nonetheless produces large increases
(LNG). Today, these commitments are in incremental demand. This means new
starting to deliver and will all materialize supply will still very much be needed.
in the next three years. But there are now
Xizhou Zhou is Senior Director and Head of
questions about whether China can use all China Energy at IHS; he leads the firm’s flagship
this new supply. Last summer, for exam- China Oil & Gas Service and China Gas, Power &
ple, spot LNG imports into China dried up, Coal Service.