GE Report: The Age of Gas & The Power of Networks

THE AGE OF GAS
& THE POWER
OF NETWORKS
PETER C. EVANS & MICHAEL F. FARINA

CHAPTER I.

EXECUTIVE SUMMARY

TABLE OF CONTENTS
I.

Executive Summary

II.
The Age of Gas

Natural Gas in History: Three Eras
11
Global Gas Landscape Today 16

Outlook for Gas Growth to 2025
19
III.
Growth and Transformation of Gas Networks
Power of Networks 27
Network Modes 28
Network Evolution 31
Network Density: LNG 33

Network Interconnections and Interdependencies
35
IV.
Enabling Technologies and the Industrial Internet
Supplying the Network 39

Securing and Optimizing the Network
48
Growing the Network 50
V.
Future of Gas Networks

Developing New Gas Networks: Anchors and Satellites
56
Future Network Integration 64
Natural Gas and Carbon 70
VI.
Catalysts and Conclusions
Driving Network Investment 73
Supporting Technology Innovation 75

Encouraging Safe and Sustainable Development
76
VII.

Notes, Data Appendix, Bios and Acknowledgments

© 2013 General Electric Company. All Rights Reserved.
This material may not be copied or distributed in whole or in part, without prior permission of the copyright owner.

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CHAPTER I.

EXECUTIVE SUMMARY

I. EXECUTIVE SUMMARY
Natural gas is poised to capture a larger share of the world’s energy
demand. Gas has been a part of the energy landscape since the Industrial
Revolution. What is new and changing is the role of this unique resource
in the global energy mix. Natural gas is shifting from a regional and often
marginal fuel to becoming a focal point of global energy supply and
demand. The world is entering a period in which natural gas is positioned
to rival coal consumption as well as take share from oil on the global
stage. The world is also entering a period in which gas will increasingly
complement wind and other renewable energy sources, particularly in
power generation. This is significant because the world continues to shift
to electricity to power industry, commercial, residential and most recently
transportation systems. We anticipate gas will grow by more than a third
over its current global consumption by 2025.
Gas growth is accelerating, in part, because the infrastructure networks
that connect supply and demand are becoming more diverse and
expanding around the world. The future of gas will not be the same as the
past. Gas network growth and new supply options like shale gas, coupled
with technology innovation, are contributing to creating greater network
density, greater flexibility, and improved economics. Indeed, the power
of networks and the Age of Gas are closely inter-linked and will contribute
to a range of valuable benefits. These benefits include significantly lower
environmental emissions relative to other fossil fuels, synergies with
more intermittent renewables, and contribution to overall energy system
resilience to disruption.
Power of Networks
Natural gas requires networks to link sources of production to the various
locations where it will be used. One defining characteristic of networks
is that they become more valuable with size as more entities join the
network. These characteristics facilitate the development of adjacent
networks, uncovering hidden opportunities to create value as new links
are established. Network growth creates greater flexibility and improved
economics, which in turn fosters further growth. Denser networks
contribute to making energy systems more robust and therefore more


3

CHAPTER I.

“Gas network growth and
new supply options are
contributing to creating
greater network density,
greater flexibility, and
improved economics.”

EXECUTIVE SUMMARY

resilient to disruption and less likely to exhibit extreme
price volatility.

Gas typically travels by one of three means to reach
users. One is through pipelines. Gas pipeline systems
are mostly land-based and the most common form of
transport delivering 89 percent of gas consumed today.
The second is by sea. The sea-based network is made
possible by the large-scale conversion of gas to liquefied
natural gas (LNG) with the use of special-purpose
transport ships. About 10 percent of global gas flows
occur as LNG trade on the high seas. International trade in LNG is expected
to increase by almost 70 percent over this decade. Finally, there is a small
quantity of gas, about 1 percent globally, which is compressed or liquefied
in small facilities and transported by rail or truck. In places like North
America, where arbitrage opportunities are great between higher cost
diesel and lower cost gas, new vertical network linkages are emerging such
rail networks and gas pipeline networks. This will drive fast growth in small
scale LNG and compressed natural gas (CNG) systems going forward.
Combining network modes helps gas networks to evolve and grow. The
evolutionary process involves a combination of technology deployment
and market arrangements that bring together buyers and sellers. The
pace of growth varies dramatically around the world and hinges, again, on
the degree of network development. In the early phase of development,
gas infrastructure is characterized by point-to-point connections. In more
mature phases where density is high, there are many opportunities to
build linkages within, as well as across, other energy systems including
electricity, railroad, shipping, and roads used for long-haul trucking to
create sophisticated meshed networks.
Large-scale multi-billion dollar “mega” pipeline and LNG projects will
“anchor” future gas network growth. This is the traditional growth path
to connect large supply sources with demand centers. Complementing
these large-scale systems will be a new generation of smaller modular
“satellite” systems. Gas networks will evolve around the world based on the
development of anchor systems and satellite opportunities.


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CHAPTER I.

EXECUTIVE SUMMARY

As these networks integrate, gas delivery will become more flexible and
more resilient. This will support increased use of gas by large-scale power
and industrial users, as well as for smaller-scale distributed power and
urban heating and cooling needs. The integration of gas systems over
the next decade is going to bring unprecedented flexibility to the gas
market, driving significant institutional and market changes, and also
opens the way for gas to capture a larger share of energy demand.

“The integration of gas
systems over the next
decade is going to bring
unprecedented flexibility
to the gas market, driving
significant institutional and
market changes, but also
opens the way for gas to
capture a larger share of
the energy demand.”

Energy System Resilience

The world needs both resilient and sustainable
energy systems. This is particularly true for fuel and
electric power infrastructure since they provide the
foundations upon which other critical systems rest,
such as communications systems, healthcare systems
and financial systems. A resilient energy system
optimizes the strengths of individual energy networks. It
harmonizes their operations to the benefit of consumers.
An energy system that relies heavily on any one energy
network will be more vulnerable. Furthermore, networks
that are optimized to be more efficient with lower losses
and reduced transaction cost are more sustainable as
well. Gas is well positioned to work with other energy
sources to improve overall energy system resilience.
Furthermore, as gas systems become more intelligent with new digital and
software technologies, these benefits will likely grow.
Gas networks, which are often underground, in contrast to road and power
grids, can often provide stable service during severe weather events. In
this way, gas can contribute broadly to economic resiliency by providing
diversification, redundancy, and backup systems. Gas technologies are
supporting new concepts for grids-within–a-grid and multi-source micro
grids to increase resilience and reaction time in the face of disruptions. In
addition, distributed power systems built around gas networks can provide
fast power recovery for public utilities such as hospitals, waterworks and
government agencies, which is very important in disaster relief. However,
in other events, for example, earthquakes or typhoons (for LNG ships) gas
systems may be disrupted. This is why gas, power, and liquid fuel networks
are best when optimized to support each other.


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CHAPTER I.

EXECUTIVE SUMMARY

Technology and Innovation
Technology innovation is at the foundation of the growing role that gas
is playing in world markets. Since the era of gas manufactured from coal
back in the 19th century to the emerging unconventional gas era of today,
technology change and gas industry growth have been closely linked.
Presently, innovation is taking place at the component level as well as
the systems level. While the building blocks of gas networks, including
compressors, valves, turbines, and engines continue to be pushed to
their design limits, the most exciting advances are taking place at the
systems level. For example, it has been largely the integration of existing
technologies which has contributed to making shale gas development
such a game-changer for North America.
In the future, we foresee more examples of new technology systems,
which will have a dramatic impact on gas network growth including new
floating LNG technologies and “mini-midstream” (small gas gathering
and conversion and transportation systems) technology sets. We will also
see an array of new digital systems for sensing, monitoring, control, and
analytics, all of which are a part of the Industrial Internet, which is bringing
about deeper integration of the digital world with the world of machines.1
Technology innovation can be divided into the different ways that it
contributes to gas network development. There are innovations taking
place upstream which focus on supplying gas networks. This includes
technologies to improve efficiency and lower costs of large-scale
remote gas projects such as deepwater gas, sour gas, and other large
conventional gas developments. Other technologies will contribute to
securing, integrating and optimizing gas systems from an efficiency as well
as environmental and safety standpoint. The new technologies that help
integrate and transform small-scale LNG and CNG systems into “virtual
pipelines” will be important to the rapid development of new gas markets
like the transportation sector. Lastly, there are technological innovations
focused on expanding the range of applications for gas. The flexibility of
natural gas makes it a valuable complement to other generation sources
like renewables. Across each of these areas, advances in the Industrial
Internet, including data analytics, machine-to-machine and machine-tohuman interfaces will have a powerful effect on the productivity of gas
related facilities, fleets and networks.


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CHAPTER I.

EXECUTIVE SUMMARY

Gas Outlook to 2025
Global gas demand today is about 3,500 billion cubic meters per year (Bcm)
or about 70 percent of the size of the global oil market. The GE Age of Gas
outlook projects global consumption will grow by nearly 1,300 Bcm of gas
by 2025, which is a 36 percent increase relative to the present. This would
increase gas to 26 percent of global primary energy consumption. Over
half of the incremental growth in this period
will take place in China, the Middle East, as well
as Southeast and South Asia. Under the right
conditions, including an increase in supply,
additional policy support, and network growth,
natural gas could achieve a 28 percent share
of global primary energy consumption. This is
equivalent to, or slightly larger than, expected
coal and oil share in 2025.

“As gas markets mature and
networks expand, the industry
will be increasingly pushed toward
a competitive environment with
more price convergence.”

The power sector will be the key driver of future gas demand growth. As
the world power systems expand, we anticipate that gas used to produce
electricity will expand by nearly 50 percent. Economic and environmental
factors are driving the shift away from oil and coal toward natural gas
and renewables in the power sector. There is a window of opportunity
for gas to be developed profitably and still compete effectively against
internationally-traded coal if it falls within the right competitive pricing
range. This “strike zone” varies by region and with the degree to which gas
prices are linked to oil prices.
Getting gas into the “strike zone” can be accomplished through traditional
vertical integration between buyers and sellers, but with more flexibility
on long-term contracts. As gas markets mature and networks expand, the
industry will be increasingly pushed toward a competitive environment
with more price convergence. Regional prices will be different because
of the underlying cost of supply and transportation and less because of
contractual linkage to oil. The slow retreat from oil-linked prices in places
outside North America and Northwest Europe will create incentives for the
industry to adopt new processes and options as well as widen the spectrum
of technologies deployed. In terms of new gas supply, conventional sources
will continue to dominate and will make up 70 percent of incremental supply


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CHAPTER I.

EXECUTIVE SUMMARY

growth. However, unconventional sources will continue to grow as well.
By 2025, we expect that unconventional gas will constitute nearly 20
percent of global gas supply, up from 14 percent today.
Global annual expenditures on natural gas infrastructure now range
from $250 to $300 billion per year. Of this total, nearly 25 percent of
industry spending is devoted to expanding gas transportation networks
including pipeline, storage, and LNG systems. Over the next five years,
gas transportation network development is likely to account for nearly 30
percent of annual capital spending of the $400 billion global gas industry.
A significant portion of this investment is related to large-scale LNG
development, which will exceed pipeline investment over this time period.
Age of Gas
Expanding the global role of gas will depend on a new wave of investment,
additional policy adjustments, and coordination among companies and
governments. Future growth will require focus on the key role that networks
play in the gas industry. Policy makers will need to give greater attention to
the importance of growing gas networks (horizontal growth), and the options
available to facilitate the linkages between various energy systems (vertical
linkages). Fostering an environment for innovation will also be critical. Tax
credits and incentives in the early stages can be instrumental to encourage
new supply development. On the consumer side, examining tax policies that
distort competition between fuels is also important. For example, current
policies often tax LNG based on fuel volume rather than energy content. This
increases the effective tax on LNG by 1.7 times the rate applied to diesel fuel,
distorting network investments and end-use fuel choice.
There are strong indications from North America that successful gas
development can foster economic growth and job creation. This experience
demonstrates that gas network development can be a vehicle for economic
development, manufacturing competitiveness and increasing energy
system resilience. Other catalysts for network investment include efforts to
drive international cooperation on gas projects and continued evolution of
pricing policies that align with the various stage of industry development.
Natural gas can provide substantial environmental benefits. These benefits
are achieved directly when used as an alternative to dirtier fuels, or if


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CHAPTER I.

EXECUTIVE SUMMARY

resources, like water, are conserved. They are also achieved indirectly
when gas supports other lesser environmentally-damaging energy sources
like wind and solar. Realizing these benefits can have long-term and
far-reaching positive impact on the economy and society. These benefits
can already be captured where gas is economically competitive. These
environmental value drivers, if accounted for in developing projects, can at
least partly offset the current price differentials between natural gas and
competing fuels. At the same time, natural gas will only be able to reach its
potential if technologies are deployed that can support safe, efficient and
reliable capture and extraction. Specifically, this means redefining what
is possible in gas operations including: enabling oil substitution, improved
water management, reduction of fugitive emissions and gas flaring, and
other new approaches to advance efficiency and electrification.
The Age of Gas outlook presented here is not a foregone conclusion. Many
complex pieces need to fall into place. However, there is real potential
for natural gas, enabled by the power of denser and more flexible global
networks, to win global market share from coal and oil, and in so doing
transform the global energy landscape in beneficial ways.


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GE Report: The Age of Gas & The Power of Networks

CHAPTER II.

THE AGE OF GAS

II. THE AGE OF GAS
The history of natural gas traces the slow, steady progress of a valuable
but marginal fuel gradually advancing toward becoming a global fuel. In
the last 50 years, there have been defining energy trends in each decade.
In the 1970’s and 1980’s, it was the oil price shocks and the rise of coal
and nuclear power, in the 1990’s it was deregulation, in the 2000’s, it was
carbon and clean energy policy — a direct response to the surge in coal
use over the last two decades. The challenges and complexity facing the
energy industry today have developed from each of these previous trends
while being shaped by new ones as well. There is a unique opportunity for
the next defining energy trend to be the “Age of Gas.” To understand the
emerging Age of Gas, what it means, and how it can be realized, it is helpful
to begin by briefly exploring the historic role of natural gas as a direct and
indirect energy source.
Natural Gas in History: Three Eras
The history of natural gas can be divided into three eras. The first was
the manufactured gas era which lasted for a century, from 1810 to
approximately 1920. This was followed by the conventional gas era,
spanning the period from 1920 to around 2000. The unconventional gas
era is just getting underway.
Manufactured Gas Era
At the start of the Industrial Revolution, factories and whole cities went
dark at night, save for the light that could be produced from candles and oil
lamps. The invention of gas lighting changed this. Cities all over the world
embraced gas as a way to light city streets, squares and railway stations
and numerous other locations, as the Industrial Revolution spurred rapid
growth. British, Belgian and American cities were at the forefront in building
these systems. By the 1860’s, gas lighting and the small supply networks
that were built to support them had spread to cities such as Sydney,
Buenos Aires, Calcutta, Tokyo, Hong Kong and Singapore.2
The fuel to supply these early networks was manufactured gas derived
primarily from coal, but other materials were also converted into gas


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THE AGE OF GAS

including oils, wood, and pine tar.3 Thousands of gas works were built
around the world and new gas light companies emerged to build gas
lighting systems. However, these nascent gas networks were challenged
by Thomas Edison’s introduction of commercially viable incandescent light
in the 1870’s. Electric lighting was widely considered a superior technology
since it provided a light of better quality, consistency, and without soot and
fumes. One observer of the time called Edison’s electric light “a little globe
of sunshine,” which provided “bright, beautiful light, like the mellow glow of
an Italian sunset.”4 Incandescent light quickly gained share over gas. The
gas industry responded by seeking out new uses for gas such as industrial
applications, and uses in homes for cooking, and water and space heating.
However, the gas industry found it hard to compete especially when the
cost of coal feedstock rose in response to shortages caused by World War I.
As a consequence, the role of gas in the global energy mix remained low.
Conventional Gas Era
The 20th century ushered in the conventional gas era with significant
changes in the source, distribution and end-use technology. Manufactured
gas faded and the industry turned increasingly to conventional sources
of gas with the discovery of major gas fields, made in the pursuit of oil.
Prospectors discovered gas underground in discrete reservoirs or so-called
non-associated gas. Some of these reservoirs were massive, such as the
Hugoton reservoir in Kansas (1922), the Groeningen field in the Netherlands
(1959), and the Urengoy gas field in West Siberia (1966).5 Large quantities
of gas were also found dissolved with oil. When brought to the surface, the
gas dissolved much like a carbonated drink when the cap is removed. But
in many cases, this “associated gas” was considered a nuisance and ended
up being vented into the atmosphere or flared if there was no economical
way to get it to market.
In time, innovation and investment in gas transportation expanded and
more gas found its way to market. Technology breakthroughs in the
construction of steel pipelines helped to make it more economical to
transport. Pipeline networks became larger and more efficient by the
1950’s as they captured considerable economies of scale with larger,
higher pressure pipes. A few large transcontinental pipelines were built,
as well as more regional networks. Innovations in the 1960’s also opened


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THE AGE OF GAS

the opportunity to trade gas across oceans. This was made possible with
the development of techniques for super-cooling the gas to reduce its
volume to 1/600 of its atmospheric volume. Special cryogenic LNG tankers
began to ply the oceans with names like Methane Princess and Methane
Progress. Commercial trade in natural gas (LNG) commenced between
Algeria and France and the UK, and from Alaska to Japan.
More rapid expansion of natural gas began in the 1970’s and 1980’s,
with a number of intersecting factors playing a role.
The oil shocks of 1973 and 1978 caused governments
and utilities to actively diversify their fuel mix, often to
the benefit of gas. Conventional gas also received an
important boost from changes in end-use technology,
such
as the introduction of the combined cycle gas turbine for power production.
Breakthroughs were made in applying jet engine gas turbine technology
to produce electric power.6 Utility companies and industrial users
increasingly embraced these technologies on the basis of cost, efficiency
and environmental performance. This was the era of the race for industrial
scale. With the introduction of new technologies, the use of gas contributed
to this race. In the late 80’s and early 90’s, regulatory changes also played
a role. In the UK, the changes involved the privatization of state-owned
companies and opening the gas pipeline network to competition. In the US,
the most significant changes were opening the network and removing price
controls. This contributed to creating a more competitive and efficient gas
industry.7

“This was the era of the
race for industrial scale.”

With these developments, gas utilization and the networks that supported
it spread significantly in North America, Europe and Northeast Asia. Natural
gas use has expanded as economies and population have grown. In 1970,
global gas consumption was 1,000 billion cubic meters (Bcm) per year with
80 percent of consumption in North America and Eurasia.8 In 1990, gas use
had grown to 2,000 Bcm representing about 20 percent of global primary
energy supply. By the year 2000, natural gas had grown in volume (2,400
Bcm), and captured share, reaching 22 percent of global primary energy
use. Yet, owing to the competitiveness of alternative hydrocarbons, gas
continued to lag coal and oil as a primary energy source. End-use supply


13

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THE AGE OF GAS

concerns, both real and imagined, periods of price volatility, as well as
limitations of networks in much of the world, worked to keep gas in third
place. Thus, while it was an increasingly important part of the global
energy mix—overtaking hydro and nuclear energy—natural gas still
trailed oil and coal.
Unconventional Gas Era
It was recognized as far back as the 1820’s that natural gas accumulated
not only in discrete underground pockets (usually porous sandstone
or limestone reservoirs) but was present in the larger underlying rock
formations. Potential unconventional gas sources included methane
trapped with coal seams, coal bed methane (CBM), gas present in low
permeability sandstone (tight sands), and even in dense organic-rich shales
(gas shales). For shale, the difficulty was liberating it from the fine-grained,
clay- and organic carbon–rich shale rocks in an economic fashion.
Cycles of abundance and scarcity in the US gas market after 1950 drove
bursts of intense interest in developing unconventional gas. Small
research and development projects were launched in the mid-to-late
1970’s. However, successful development (supported in part by tax
incentives) of CBM resources in Black Warrior basin in Alabama, in the
Fruitland coal seams of northwest New Mexico, and in the Powder River
basin of Wyoming in the 1990’s, showed unconventional resources could
be a significant source of continental gas supply. Today, CBM production
is about 10 percent of US gas supply and is becoming a contributing
unconventional gas supply source in China and Australia. Later, in the
1990’s, experimentation with fracturing technology opened up large tight
sands developments in the Rocky Mountains, principally in the Green River,
Piceance, and Uinta Basins of Wyoming, Colorado, and Utah. Similar tight
sands efforts in parts of east and central Texas also emerged during this
time. Nearby, another unconventional source, the Barnett Shale, had been
quietly investigated since the late 1980’s.
In 1992, George P. Mitchell drilled the first horizontal gas well in the Barnett.
By 1997, he was experimenting with “light sand fracturing.” At the time,
shale gas production in the US was an insignificant part of US supply—only
1.6 percent of total US gas production in 1999.9 The breakthrough occurred
in the late 1990’s, aided by the persistent experimentation by independent

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THE AGE OF GAS

companies like Mitchell Energy. Trial and error efforts continued with
various forms of fresh water hydraulic fracturing techniques—known as
fracking — and proppants designed to keep rock structures open to release
the gas. These early efforts evolved into today’s advanced horizontal
drilling and “slickwater” fracturing techniques, aided by new micro-seismic
imaging and manufacturing-based approaches to development. A surge
in supply followed.
Other companies quickly adopted the techniques and applied them to other
shale formations in Arkansas, Oklahoma, Louisiana, Texas, Pennsylvania
and Western Canada. Since 2000, aided by a period of high gas prices
through 2008, shale gas production surged up at an unprecedented rate.
Unconventional gas (shale, CBM, and tight sands) in the US grew by 223
percent through 2012 and now represents about 55 percent of US gas
supply. Today, technological advances in the gas shales have lowered costs
while increasing well productivity. This is the reason shale gas is considered
a “game changing” resource. Furthermore, as these techniques have
been applied in oil-prone shales, there has been a renaissance in US oil
production. The implications and scale of this oil renaissance are uncertain,
but it is clear that the significant growth in “light tight oil” will bring with it
significant quantities of associated gas, adding yet another large source of
gas supply to the US market.
So far the shale boom has been heavily concentrated in North America.
Within less than a decade, the United States has become the world’s
largest producer of natural gas and in combination with Canada, accounts
for 25 percent of global production. Today, US producible reserves alone
are estimated to be in excess of 2,500 trillion cubic feet.10 This is 1.5 to 3
times what total recoverable reserves were estimated to be in 1980.11 If
these recovery estimates prove accurate, there are nearly 100 years of US
gas supply available at expected future consumption rates. Largely on the
back of the North American shale development, in 2012, unconventional gas
rose to 14 percent of the global gas supply mix, up from 6 percent in 2000.
The success of these developments has contributed to lifting the global
role of unconventional gas in the supply mix. New estimates point to large
potential shale gas reserves around the world including China, Australia,
Argentina, Brazil, Algeria, Saudi Arabia, and parts of Africa, among other
countries. The unconventional resource wave in North America is driving


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THE AGE OF GAS

job creation and changing national competitiveness. Furthermore, it is
shaping expectations of major shifts in the geopolitical landscape of energy
in the years ahead. While questions remain on the future of shale resources
outside North America, there is good reason to believe we are entering the
unconventional gas era.
Global Gas Landscape Today
In 2012, global gas demand reached 3,500 billion cubic meters (Bcm) per
year and gas now represents about 24 percent of primary energy supply.
This level of demand is equivalent to 63 million barrels of oil per day. The
gas industry is therefore about 70 percent of the size of the global oil
market today. Global gas demand has been growing over the past decade
at a steady rate of approximately 3 percent a year but with significant
variation between regions (see Figure 1).
The big mature gas regions like North America, Europe and Eurasia
constitute 57 percent of global demand, but growth has slowed to a rate of
about 1 percent per year- or has contracted recently in the case of Europe.
China’s gas consumption has gained pace, growing at approximately 11
percent a year over the past decade, but started from very low levels of
consumption. Currently, China consumes 140 Bcm or about 4 percent of
global demand. This is approximately the same as Africa’s consumption
and less than an eighth of North American consumption. Other regions are
also growing rapidly. The Middle East, for example, has had a growth rate
of 7 percent and now consumes 556 Bcm or 13 percent of the world total.
The balance of global gas consumption is comprised of the rest of Asia (15
percent) and Latin America (7 percent).
Gas serves a variety of end-users competing differently in each of its key
markets. The largest share of gas finds its way into power generation,
which currently makes up 41 percent of global consumption. A portion
of this gas is used to fire “peaking” units, which run periodically to meet
periods of highest electricity demand. The other portion is used for
“mid-merit” or cycling and “base-load” power generation, in which
gas-fired turbines operate in the daytime or in all hours of the day. The
second-largest demand for gas is for industry, where gas is used as a
process feedstock to produce fertilizers, chemicals, plastics, and a wide
range of other products. Industrial use makes up 24 percent of global gas

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Figure 1. Regional Gas Demand by Source, 2013
Source: GE Global Strategy Analytics, 2013

17%

EURASIA

16%
24%

EUROPE

NORTH AMERICA

4%

13%

MIDDLE EAST
4%

7%

LATIN AMERICA

POWER GEN

BUILDINGS

AFRICA

CHINA

7%

OECD ASIA PACIFIC

8%

OTHER ASIA

POWER GEN
BUILDINGS
INDUSTRIAL

INDUSTRIAL
OTHER

OTHER

demand. The unique applicability of gas to some industrial processes, like
ethylene production, can give gas a competitive advantage. The third major
source of demand is for buildings which make up another 20 percent—
largely for space heating, cooking and in some cases, cooling. Gas is a
premium fuel for space heating needs and is prized for certain commercial
uses like cooking or drying. Finally, there are other uses, primarily in the
energy sector and transportation sectors. For example, gas is used as
a source of hydrogen in refineries to make diesel fuel. In some of these
applications gas competes directly with oil in remote operations. It powers

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THE AGE OF GAS

Figure 2. Global Gas Supply and Trade, 2000–2012

AFRICA

EUROPE

EURASIA

MIDDLE
EAST

CHINA

OTHER
ASIA

OECD ASIA
PACIFIC

2000
2004
2008
2012

2000
2004
2008
2012

2000
2004
2008
2012

2000
2004
2008
2012

2000
2004
2008
2012

2000
2004
2008
2012

NORTH
LATIN
AMERICA AMERICA

2000
2004
2008
2012

Source: GE Global Strategy and Analytics, 2013

1000
800
600

BCM

400
200

0

-200

2000
2004
2008
2012

2000
2004
2008
2012

-400

DOMESTIC SUPPLY

UNCONVENTIONAL

CONVENTIONAL

IMPORTS

PIPELINE IMPORTS

LNG IMPORTS

EXPORTS

PIPELINE EXPORTS

LNG EXPORTS

NOTE: Unconventional gas includes gas shale, CBM, and tight sands supplies. Conventional includes all

other gas sources in the region. European pipeline exports aggregated intra-regional gas trade primarly
f
rom Norway and the Netherlands to other parts of Europe.

the compressors and processing equipment used to purify and transport
gas for delivery. Gas is also increasingly being used directly as vehicle fuel.
Collectively, these and other uses account for 15 percent of global gas
consumption.
There is robust cross-border trade in gas. More than 30 percent of gas
now moves from one country to another, either through pipeline networks
or by sea via the LNG network. As shown in Figure 2, the largest pipeline
exporting regions are Eurasia, parts of Europe (e.g. Norway), and North
America, which largely involves flows from Canada to the US, and smaller

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THE AGE OF GAS

flows from the US into Mexico. While more gas is traded by way of pipelines
than by LNG, the share of LNG has been gaining. LNG imports more
than doubled to 327 Bcm in 2012 up from 140 Bcm in 2000. The largest
LNG exporters today are Qatar, Australia, Malaysia and Indonesia. The
largest LNG importers are Japan and South Korea followed by the UK
and southern Europe.
Outlook for Gas Growth to 2025
Gas is poised to capture a larger share of the world’s energy needs. Our Age
of Gas forecast envisions total world gas demand reaching approximately
4,800 BCM by 2025, which is 36 percent more gas than is produced and
consumed today.12 Over half of the incremental growth will take place in
China, the Middle East, as well as Southeast and South Asia (Figure 3). The
growth in the Middle East is predicated on availability of new gas supplies
and finding agreement between producers and consumers concerning
investment and pricing policy. The growth story in most of Asia is linked
to timely infrastructure development and the competiveness of gas versus
oil and coal.
Infrastructure development will be critical in Africa and Latin America as
well. Gas will be attractive as an alternative to oil in transportation and
other distributed energy settings as new supplies are brought online.
Further, as regional economies grow, Africa will increasingly look to supply
its own needs as well as export gas.
In the mature regions, growth will be slower albeit from a much larger base.
Growth in North America is expected to accelerate in the second half of
the decade as new facilities are built to capture the value of low cost shale
gas. Russia and the Caspian region will continue to rely on abundant gas
resources, but are expected to increasingly focus on improving the energy
efficiency of their operations. The region will continue to be a major supplier
to Europe and will increasingly export gas to Asia. The European gas
market is expected to grow very slowly in the near-term. In fact, gas use
has been declining since 2010 as coal has become more competitive and
economic conditions have been challenging. However, we expect Europe
to return to its growth path by the end of the decade.


19

CHAPTER II.

THE AGE OF GAS

Figure 3. Natural Gas Growth Outlook, 2012-2025
Source: GE Age of Gas Outlook, 2013

2012

2012-2025 ABS GROWTH

CHINA

249

MIDDLE
EAST

227

OTHER
ASIA

185

EUROPE

132

NORTH
AMERICA

131

LATIN
AMERICA

119

AFRICA

2012-2025 CAGR

102

EURASIA

66

OECD ASIA
PACIFIC

51
100

200

300

400

500

600

700

800

BCM

POWER GEN

0

15

0

100

200

0

BCM

BUILDINGS

INDUSTRIAL

2% 4% 6% 8% 10% 12% 14%

PERCENT CHANGES

OTHER

In terms of supply, conventional sources will continue to dominate and will
make up 70 percent of incremental supply growth. Russia’s conventional
gas resources remain vast but somewhat more costly to develop as
traditional dry gas reservoirs are supplemented with large Arctic gas
deposits under the Yamal peninsula and deeper, more complex, finds in
western Siberia.13 These supplies will meet domestic needs and remain
an important part of the European supply. In addition, the initial phases
of eastern Siberian gas development will be underway by decade’s end.


20

CHAPTER II.

THE AGE OF GAS

Nearby, Turkmenistan and other Caspian producers will increase exports
into China as new pipelines are finished and investment in the super-giant
Galkynysh gas field continues.14 In the Middle East, Qatar and Iran will
continue gas development. However, Iran’s gas resources are expected to
remain largely out of international markets in the near-term amid ongoing
geopolitical tension. Elsewhere, massive new offshore conventional gas
finds on the northwest shelf of Australia, in Mozambique and Tanzania, and
in the Mediterranean will anchor large LNG projects over
the next ten to fifteen years.

“By 2025, we expect that
unconventional gas will
constitute nearly 20 percent
of global gas supply, up from
14 percent today.”

Bolstering these conventional supplies, unconventional
gas is forecasted to grow at twice the pace of traditional
gas sources. By 2025, we expect that unconventional
gas will constitute nearly 20 percent of global gas
supply, up from 14 percent today. Most of the gas will
be developed in the United States and Canada, led by
the Marcellus shale region centered in Pennsylvania
and the Eagle Ford shale of south Texas. By some estimates, Eagle Ford
has become the largest oil and gas field development in the world on
a capital expenditure basis. Outside North America, Australia’s CBM
resources are in full development, anchoring several LNG projects in
Queensland. In Argentina, excitement about the prospects of the Neuquén
Basin is building. In China, shale gas exploratory work is continuing in the
Sichuan region and other parts of China. Developing shale gas in China
presents many challenges, but we think material volumes will emerge
after the end of the decade. The unconventional gas outlook shown here is
conservative in some respects. Across the world, from Australia, Algeria and
Brazil to Mexico, Turkey, and Russia, shale optimism is growing. However,
unconventional gas growth will be paced by several key factors including
infrastructure that are discussed in more detail below.
The power sector will be the key driver of future demand growth. Gas
complements steady baseload sources like coal and nuclear fuel as
electricity demand changes through the day, and balances intermittent
renewable supplies when the sun is not shining or the wind is not blowing.
As the world power systems expand, we anticipate gas used to produce
electricity to expand by nearly 50 percent. There are uncertainties
concerning the growth of each specific generation technology. For example,


21

CHAPTER II.

THE AGE OF GAS

Japan’s future gas demand will be closely tied to post-Fukushima decisions
on the future of nuclear power. It will also be influenced by the rate of new
nuclear power plant construction around the world.15
An even larger question for the future of gas concerns the generation share
it will capture from coal. There is a window of opportunity or “strike zone”
for gas to be developed profitably and still compete effectively against
internationally-traded coal. However, if gas prices are too high, coal will
gain share. Likewise, when gas prices fall, gas becomes highly competitive,
but investment in new supply falters. These dynamics are not the same
across the world. Different regions currently fall in different places across
this strike zone, as illustrated in Figure 4. In North America, the recent
decline in gas prices has placed natural gas clearly within the strike zone
in the US (fully independent pricing from oil), which has helped gas win
share. The competitive dynamics are different in Europe where prices are
higher and there is tighter correlation to oil prices. Prices are even higher in
Asia, creating more competitive challenges. We expect gas demand in the
power sector to grow, but gas will need to stay in the strike zone to do so.
There are other factors beyond current prices which influence the role
of gas in power generation. Gas contributes to the diversification of the
fuel mix. Since it can ramp up quickly and follow load, it can contribute to
flexibility. The environmental advantages of gas as a generation source
are also well documented. Because it is composed primarily of methane,
the main products of natural gas when burned are carbon dioxide and
water vapor. Coal and oil, by contrast, are composed of much more
complex molecules, with a higher carbon ratio and higher nitrogen and
sulfur contents. This means that when combusted, gas releases much
lower levels of harmful emissions than coal or oil. High concentrations of
these pollutants also form PM2.5 (dust particles which measure less than
2.5 microns—small enough to get deep inside human lungs). Producing 23
percent of nitrogen oxide (NOx), 50 percent of the carbon dioxide (CO2), and
virtually no sulfur dioxide (SO2), particulate matter or ash, gas has a much
more favorable environmental profile than other fossil fuels.
More recently there has been growing attention to the need for energy
systems that reduce environmental impact, but also have the ability to
better withstand or recover quickly from disruptions like hurricanes and
sever winter storms. Gas-fired combined heat and power plants, which


22

CHAPTER II.

THE AGE OF GAS

Figure 4. Competitive Strike Zone For Natural Gas Varies By Region
Source: GE Age of Gas Outlook, 2013

HIGHER

180

LOWER
GAS COMPETITIVENESS

LOW EFFICIENCY
GAS GENERATION

160
140
120

$/MWH
(REAL DOLLARS)

HIGH EFFICIENCY
GAS GENERATION

100

ASIA

80

EU

60
40

US
20
0
2

4

6

8

10

12

14

16

DOLLAR PER MMBtu
NOTE: Estimates of high efficiency natural gas are based on 6,200 heat rate, while lower fficiency estimates
e
are based on a 10,000 heat rate.

are highly efficient but can “decouple” from the central grid if necessary,
are an example of resilient and sustainable infrastructure.16 Further,
gas-fired power generation can be combined with renewables to create
a stable source of power that has less price exposure and a much lower
emissions profile. The flexibility, versatility, and relative cleanliness of gas
are well matched to the energy needs and market structures of developing
economies, where demand for new sources of energy is the highest. Gas
technology fits well with a world demanding more resilient and distributed
energy sources along with traditional centralized energy supplies.
To a large degree the Age of Gas is about the ability of natural gas to catch
up with and compete head-to-head with oil and coal. Today, oil, coal, and
natural gas account for 83 percent of primary energy supply. Hydrocarbons
are expected to provide more than 80 percent of the world’s energy in 2025.


23

CHAPTER II.

THE AGE OF GAS

Economic and environmental factors are driving increased fuel substitution
away from oil and coal toward natural gas and renewables. Oil represents 31
percent of global energy use today, but should fall to 27 percent by 2025 as
efficiency gains, conservation, and substitution effects take hold. This decline
is largely from high prices further squeezing oil out of stationary applications,
and the slow but steady adoption of alternative transportation fuels.
Fuel technology choices made over the next fifteen years will largely define
the structure of the energy industry for decades to come. This brings
concerns about path dependency, meaning it will be hard to change the
path of development once technology choices are made—owing to the
long asset life and slow capital turn-over of major energy systems.17 If
coal becomes the primary fuel in emerging power systems, the transition
timeline toward a low carbon system will be extended. Coal has been
the fastest growing fuel over the past seventeen years, gaining more
than 3.5 points in share of primary energy consumption. Coal will clearly
have a large role in generation going forward, and will remain a primary
generation source in many parts of the world, but natural gas is positioned
to capture more of the incremental growth.
There will be challenges for gas to win decisively and edge out the
incumbent fossil fuels. It is uncertain if market forces and policies will align
for natural gas to compete effectively against coal beyond a few regions
of the world. The expectation in the GE Age of Gas outlook is that coal will
hold at about 28 percent of primary energy through 2025, while natural
gas gains another 3 points of share, reaching 26 percent of world primary
energy. However, under the right conditions, including abundant supply,
policy shifts, and network growth, gas could gain an additional 1 to 2 points
of market share (5 percent growth total), achieving 28 percent share of
primary energy consumption equivalent to, or slightly larger than, coal
and oil in 2025.
Expanding the global role of gas will require a new wave of investment,
additional policy adjustments and coordination as well as continued
technology innovation. It will also require focus on the network aspects
of the gas industry. While there has been growing attention to the
multiple benefits of gas and the synergies that are possible with other
energy options, there has been less attention paid to the importance
of establishing gas networks and the options available to facilitate the


24

CHAPTER II.

THE AGE OF GAS

links between various energy systems. To appreciate how gas is likely to
grow and evolve in the coming years, it is valuable to assess the role that
networks play at all stages of the gas industry. There are different types
of networks which operate in different ways and are enabled by different
types of technologies. The primary focus of the remainder of this paper will
be the pivotal role played by these networks in supporting and creating
the Age of Gas.


25

CHAPTER III.

GROWTH AND TRANSFORMATION OF GAS NETWORKS

III. GROWTH AND
TRANSFORMATION OF
GAS NETWORKS
Gas is fundamentally a network industry. Networks are necessary to
move gas from the source of production to the location where it will be
used. There are different elements to these networks that are important
to consider. One is the power of networks themselves; a key element
is that as networks grow they become increasingly valuable. Another
aspect concerns the different transportation modes by which gas can be
transmitted, namely pipelines and oceans but also road and rail networks.
There are also the different levels of network development around
the world, with some large, dense and competitive gas networks, and
others just starting to build connections. Last but not least, there are the
interconnections and interdependencies between gas networks and other
networks, both physical and digital. In short, understanding the Age of Gas
includes an appreciation of the different types of networks that exist, how
these systems operate and how their value changes as they evolve.
Power of Networks
Networks are an important feature of modern economies. Reduced to their
most basic level, they consist of patterns of interconnections between
different things.18 Some networks like telecommunication systems support
the transfer of different forms of data, such as voice, video and computer
files, from one point to another. Other networks have grown to enable
heavy physical goods to be moved, such as rail networks and roads. In the
case of gas, networks are essential to transmitting a valuable fuel from the
point of supply to the point of end use. The most basic is a unidirectional
link in which gas is moved from one point to another point. More advanced
gas networks involve hub and spoke structures and more transmission
options, and some even are designed to permit flows in reverse so that they
can be bidirectional.
An important feature of networks is how their value changes as they
become denser and more complex. Networks tend to become increasingly


27

CHAPTER III.


valuable with size due to reinforcing positive feedback that occurs as more
entities join the network. These characteristics facilitate the development
of adjacent networks, uncovering hidden opportunities to create value as
new links are established. Networks create opportunities to bring buyers
and sellers together both on the upstream to supply the network and
among downstream users of the network. Network growth contributes to
lowering costs and creating greater flexibility in the system, which in turn
fosters further growth. Capturing these economies, or what economists
refer to as economies of scope and scale, serve to lower transaction costs
and create more efficient markets.19 There can, of course, be downsides to
networks. For example, networks, or portions of networks, can become less
valuable if they become congested with excessive use. Parts of a network
can become stranded, or overbuilt, as resources deplete or markets shift,
creating cost recovery challenges. This is where appropriate pricing,
investment, optionality, and storage become critical to optimizing the
scale of the network to match supply and demand.
Network Modes
Natural gas systems around the world depend on three types of networks
to support the transportation of natural gas.20 These network modes and
examples of the technologies that enable these modes are illustrated in
Figure 5. By far the most significant mode today is pipelines, mostly land
based, which transport approximately 89 percent of gas through a global
network of over 1.4 million kilometers. Most of these pipelines, or about
70 percent, are regional lines that support gathering on the upstream
and distribution within their domestic markets. The balance consists of
large-diameter continental scale pipelines found in places like the US,
Canada, Russia and increasingly China.
Pressure is essential to moving gas through the pipeline system. This is
achieved through compressors that are located at regular intervals along
the pipeline. With compression, gas moves about 25 miles per hour (40 km
per hour) through long distance pipelines. For example, gas takes about
three days to travel the 2,000 mainline miles from the Eagle Ford shale in
south Texas to New York City. Another example is the recently constructed
Nordstream offshore pipeline extending 1,224 km from Vyborg, Russia to
Greifsweld, Germany. This pipeline uses special coatings to reduce friction,


28

CHAPTER III.


Figure 5. Gas Network Transportation Options
FIGURE 5. GAS NETWORK TRANSPORTATION

NETWORK
TYPE

% OF GLOBAL
GAS
TRANSPORT

LAND-BASED
PIPELINES

ENABLING TECHNOLOGIES
COMPRESSION

TRANSPORT

REGAS/STORAGE

89%

OCEAN-BASED
LNG SHIPS

OPTIONS

10%

MICRO LNG

PUBLIC
ROADS

RAILROADS

~1%
CNG

Source: GE Global Strategy Analytics

enabling the gas to traverse the Baltic Sea in little over a day. More than the
speed, they move energy; the value of pipelines is that they have the ability
to transport energy relative to other options.
The second mode is the LNG network, which constitutes 10 percent of
global gas trade. This sea-based network is made possible by the invention
of LNG and large special-purpose transport ships that ply the oceans
linking exporters with importers. The facilities that compress the gas to
a liquid state for transportation are highly sophisticated andcomplex
operations that can often cost $10 to $50 billion. These investments enable
large quantities of gas to travel very long distances. For example, it takes
about 20 days for gas to arrive in Japan, the largest LNG importer in the
world, from Ras Laffan, Qatar, the world’s largest exporter.


29

CHAPTER III.


Finally, transportation networks can be used to move gas by piggybacking on already existing road and rail infrastructure. This is made
possible through compression technologies like CNG and small-scale LNG.
Compressing or liquefying gas reduces natural gas so it can be transported
in steel tanks, tube trailers, or tanker trucks. One problem is CNG and LNG
are less dense than gasoline or diesel fuel. A gallon of CNG has about
25 percent of the energy content of a gallon of diesel fuel. LNG has 60
percent of the volumetric energy density of diesel fuel. Liquefying the gas
creates a denser fuel. Lower energy density limits gas efficacy in some
applications, but the cost difference between the fuels can make CNG or
LNG a smart choice—especially if the size of the project or other constraints
preclude pipeline development. Since the LNG trucks or CNG tube trailers
serve the same function as a pipeline, this mode is sometimes called a
“virtual” pipeline. This is a relatively small but a growing portion of gas
transportation. Virtual pipeline concepts are emerging as a way to quickly
enable use of gas as a transportation fuel or in distributed power plants.
While these smaller scale systems have been around for years, economic
and technological factors are creating new opportunities for rapid growth
within integrated energy infrastructure projects.
In contrast to oil, transportation costs comprise a significant portion of the
total cost of delivered gas. Each of these network modes has a different
cost structure, illustrated in Figure 6. The short haul regional pipelines
are the least expensive at less than a dollar per MMBtu. The large-scale
pipelines that move gas 1,000 kilometers can range from $1.50 to $3.75
per MMBtu.
LNG transportation solutions have a much wider range with costs from as
low as $1.75 up to $6.00 per MMBtu or more. Much depends on the location
and scale of the liquefaction facility and the cost of the specialized ships
used to transport the super-cooled liquefied gas. Trucking and rail options
also vary widely in cost, ranging from as low as $1.75 to $6.50 per MMBtu
or more. The compression technology and special pressure vessels make
a significant portion of the investment required for this mode. Economics
plays a large role in determining which solution is selected to move gas
from sources of supply to ultimate demand.


30

CHAPTER III.


Figure 6. Cost Of Natural Gas Transport

$8.00

PIPELINES
REGIONAL

TRUCK/RAIL

SEABORNE

CONTINENTAL

$6.00

DOLLAR PER $4.00
MMBtu
$2.00

0
SHORT
HAUL

OFFSHORE

1000 KM 1000 KM
30 Bcm

1000 KM
15 Bcm

CNG

LNG
SMALL

LNG
LARGE

NOTE: Small CNG and small LNG include local distribution and storage costs.

Network Evolution
There are important differences in the level of network development around
the world. The growth of networks is shaped by two broad elements as
shown in Figure 7. One dynamic involves the level of physical network
development within countries and between countries and regions. There
is the development phase where gas infrastructure is very limited; the
growth phase where infrastructure is being built out, anchoring networks
around large-scale supply, and the mature phase where density is high
and there are many opportunities to build linkages between networks. The
other dynamic concerns the level of market and institutional development.
Markets can be rigid where prices and allocations of gas and infrastructure
are highly controlled by governments.
At the other extreme, markets can be open, highly liquid and very flexible.
There are also hybrid markets, which sit somewhere between, and
have elements of both rigidity and openness. Developing new energy
infrastructure is costly, but there are high levels of systems benefits if
a level of transparency and interoperability can be achieved.


31

CHAPTER III.


Figure 7. Gas Network Growth Curve

OPEN TRADING
LIQUIDITY
FLEXIBLE

UNITED STATES

UNITED KINGDOM
MEXICO

HYBRID
MARKETS
FORMING

GERMANY
SPAIN
ISRAEL

RIGID
HIGHLY
CONTROLLED

NIGERIA

IRAQ

TURKEY
ROMANIA
CHINA
ALGERIA
EGYPT
UAE

BRAZIL
INDONESIA
CHILE
TURKMENISTAN
GHANA

VIETNAM

DEVELOPING PHASE
LIMITED INFRASTRUCTURE
AND LESS-DEVELOPED
INSTITUTIONS.

INDIA
IRAN

AUSTRALIA
ITALY
MALAYSIA

CANADA
JAPAN
KOREA
NETHERLANDS
NORWAY

QATAR

RUSSIA

UZBEK ARGENTINA
KSA

GROWTH PHASE
ANCHORING NETWORKS
AROUND LARGE-SCALE
SUPPLY AND DEMAND
SOURCES.

MATURE PHASE
EXTENSIVE NETWORKS,
OVERLAPPING NETWORKS.

GAS MARKET SIZE
NOTE: Illustrative rankings based on subjective institutional variables related to market liquidity and openness and a combination of quantitative and qualitative
measures related to gas infrastructure. Bubbles show gas market size in 2011.

There is an evolutionary path for gas networks that involves both
infrastructure and markets. Today, the early stage gas grids found in
countries like Ghana, Vietnam and Iraq, are typically point-to-point, based
on monetizing stranded assets. During the growth phase, a more diverse
set of supply and demand sources emerge and delivery systems expand
toward hub-and-spoke or rooted-tree based designs as is happening in
Algeria, Turkey and China. Mature gas networks are complex, with access
to multiple sources of supply, demand, interconnections, and buyers and
sellers. Furthermore, there is typically more interconnection with other
energy networks.
More mature networks will typically have more liquidity, pricing options,
and regulatory structure. In fact, the regulatory structure is a key element

32

CHAPTER III.


in infrastructure development. Uncertain regulation can slow investment,
but static regulation that supports entrenched monopolies reduces
competition and can slow innovation. There are a number of forces that
determine how fast gas networks evolve; factors include the economic
base, demography, climate, geography, resource endowment, technology
access, and strength of governmental institutions. The nature of these
factors determines evolutionary pace from simple to complex, or if a gas
network will evolve at all. As the networks grow, the
options for the users of those networks grow, whether
they are producers or consumers, assuming access to
the networks is allowed. Value can come from trading
in the commodity (natural gas), converting gas into
more easily transportable or useful products (LNG, CNG,
electricity, ethylene, methanol, ammonia, or gas liquids),
or an “intangible asset” like a capacity right to move gas
across a segment of pipeline. The additive nature of gas
networks is one of their essential features.

“Finally, deeper integration of
networks both vertically and
horizontally will enhance the
overall resilience of energy
systems, making them more
impervious to disruption.”

Network Density: LNG
As the network connections grow, there will likely be more inter-regional
trade. Furthermore, increased network density enhances the redundancy
and flexibility of the gas system. Deeper integration will also create the
potential for greater competition across networks. Shorter-term trading
in both gas supply and capacity are likely to increase. However, the old
contractual trading models are not likely to be abandoned. In the future,
there is likely to be more of a hybrid structure designed for greater
customer flexibility. As the complexity of gas systems increase, they tend
to become more flexible, offering expanding options. This contributes to
changing risk profiles for various stakeholders in positive and negative
ways relative to current practices. Finally, deeper integration of networks
both vertically and horizontally will enhance the overall resilience of
energy systems, making them more impervious to disruption. In general,
as networks become larger they also become more efficient, more flexible
and more resilient. While expansion is happening at different rates, the less
developed gas networks of the past are very different from more developed
networks today.


33

CHAPTER III.


Figure 8. Deepening Global LNG Market — More Buyers And Sellers

2001

2012

ALGERIA

RUSSIA
TRINIDAD

MALAYSIA

MALAYSIA

EXPORTS

2020

NIGERIA

CANADA

QATAR

RUSSIA

QATAR

TRINIDAD

INDONESIA

MOZAMBIQUE

INDONESIA

INDONESIA

NIGERIA
ALGERIA

AUSTRALIA

AUSTRALIA

US

QATAR

12 SELLERS

20 SELLERS

INDIA

INDIA

IMPORTS

FRANCE

FRANCE

JAPAN
SPAIN
US

12 BUYERS

S. KOREA

S. KOREA

CHINA

S. KOREA

25 SELLERS

THAILAND
SPAIN

UK

JAPAN

25 BUYERS

SPAIN

CHINA

JAPAN

42 BUYERS

LNG trade provides a good example of network linkages that have grown
over time. As shown in Figure 8, there were 12 countries exporting LNG
and 12 countries importing LNG in 2001. By 2012 the number of exporters
had expanded to 20 and the number of buyers to 25. By 2020, we estimate
that the number of countries involved in trading LNG will grow to 25 sellers
and 42 buyers. Their net position will change. On the export side, Qatar,
which had grown to 30 percent of the market, will fall in relative terms
to approximately 17 percent as Australia and the United States grow as
suppliers. New suppliers will also enter the market, such as Mozambique.

34

CHAPTER III.


On the import side there will be some shift in position, particularly the
greater role that China and India will play as importers. Brand new
importers will also arise with countries like Poland, Bangladesh, Thailand,
the Philippines and South Africa entering the market looking for supply.
While not currently importing, a number of other countries could join the
ranks of LNG importers over the next decade including Uruguay, Croatia,
Lithuania, Ivory Coast, Costa Rica, or Jamaica, creating an even larger pool
of buyers. By 2020, internationally-traded LNG could make up as much
as 20 percent of global gas supply with significant changes in the relative
roles of exporters and importers. The growth in the number of buyers and
sellers will create deeper networks as shown in Figure 9 and open up new
flexibility in the market and new competitive dynamics.
Network Interconnections and Interdependencies
A final element to consider is the relationship between gas infrastructures
and other networks. At this level, there are multiple complex connections
that create a web of functionality. New interconnections create more
supply diversity and customer options. As the layers build, different parts
of the gas system, gathering and processing, storage, LNG systems at
large scale, LNG or CNG systems at small scale, distribution grids, and
the complex control and software systems needed to monitor, track and
trade natural gas, create a powerful network—a system that is far more
than just interconnected pipelines. However, even as pipeline networks
become denser and supply sources diversify, backhaul and other types of
displacement services start to emerge in the pipelines. New supply sources,
coupled with modifications in compression systems, can allow flow from
either end of the pipeline to effectively double throughput capacity. Simply
put, as new components are integrated into gas systems they become
more powerful.21
Not only are we likely to see the various gas transport modes become
more fully integrated horizontally over the next decade, we are likely
to see greater vertical integration as well. The deepening connections
between gas supply and electricity generation is an obvious example.
Another example is the potential for gas to become more commonplace
in supplying fuel to rail and trucking. In the US, 42 billion gallons of diesel
are used to fuel the fleet of approximately 2.3 million heavy trucks and


35

CHAPTER III.


Figure 9. Global LNG Network In 2020

SWEDEN

RUSSIA

NORWAY
CANADA

UNITED KINGDOM
NETHERLANDS
BELGIUM
ITALY

FRANCE

UNITED STATES

MEXICO

PAKISTAN

BAHRAIN

GREECE

DOMINICAN REPUBLIC

CHINA
QATAR

egypt

LIBYA

PUERTO RICO
TRINIDAD

JAPAN

KUWAIT

ALGERIA

BAHAMAS

EL SALVADOR

UKRAINE
TURKEY

SPAIN
PORTUGAL

SOUTH KOREA

POLAND

GHANA

UNITED ARAB EMIRATES (UAE)
OMAN

NIGERIA
YEMEN

INDIA

BRAZIL

TANZANIA
ANGOLA

VIETNAM
THAILAND

EQUATORIAL GUINEA
PERU

TAIWAN

BANGLADESH

SINGAPORE

PHILIPPINES
BRUNEI
PAPUA NEW GUINEA

MALAYSIA
INDONESIA

MOZAMBIQUE
SOUTH AFRICA

CHILE

AUSTRALIA

ARGENTINA

IMPORTER

EXPORTER


36

CHAPTER III.


24,000 locomotives. The higher cost of oil is driving strong interest in gas
substitution through small-scale LNG. Lower cost natural gas can be
tapped with the development of large “joint-use” LNG fueling stations with
capacity of 250,000 gallons per day. Various companies are looking at
the opportunity, and it seems that modest investment could yield big fuel
savings in the heavy-duty fleets. Strategically-located liquefaction plant
investment of $15 to $20 billion has the potential to reduce US diesel use
in transportation by up to 30 percent.22 As long as the economic incentives
remain in place, the technology to transport and utilize gas in heavy-duty
engines will mature as the market grows.
More broadly, many new technologies that support the further development
of gas networks globally are emerging. These enabling technologies are
discussed in more detail in the next section.


37

CHAPTER IV.

ENABLING TECHNOLOGIES AND THE INDUSTRIAL INTERNET

IV. ENABLING
TECHNOLOGIES AND THE
INDUSTRIAL INTERNET
Technology innovation has been a critical enabler throughout the history
of the gas. This will continue to be true as gas networks expand over
the next decade. Innovations are occurring both at the component and
systems levels. The building blocks of gas networks including compressors,
valves, turbines, and engines continue to be pushed to design limits.
These advances are important, but the transformational impact is coming
from new combinations of existing, and even mature, technology into
smarter, cleaner, and more efficient systems. New technology systems
like those developed for unconventional gas, floating LNG, and advanced
monitoring and control will be important to gas network growth. These
and other new technologies can be divided into the roles that they play
in supporting future gas network development. There are innovations
taking place upstream focusing on supplying gas networks. Others
contribute to securing and optimizing gas systems from a productivity as
well as environmental and safety standpoint. Lastly, there are technology
innovations focused on growing and expanding the range of applications
for gas. Each of these technology developments will play a key role in to
the development of the Age of Gas.
Supplying the Network
Innovations in the upstream natural gas industry are taking place at
the fastest pace in decades. We are seeing a proliferation of new ways
to produce natural gas more efficiently at lower cost and in a more
sustainable way. Two big drivers of gas supply growth over the next
decade will be remote gas mega-projects and the rise of unconventional
gas. Each of these supply categories has different attributes and will
require special technologies unique to its development. We turn first to
the role that technology plays in determining the cost of gas supply.


39

CHAPTER IV.


Figure 10. Indicative Costs Of Gas Supply
Source: GE Global Strategy and Analytics estimates, IEA Resources to Reserves 2013,
EIA stranded gas 2013, USGS

$8.00
$6.00

DOLLAR PER
MMBtu

$4.00

$2.00

0
% OF GLOBAL NG
RECOVERABLE RESOURCES*

9%

8%

13%

11%

10%

27%

18%

5%

ASSOC.
GAS

CONV.
SHALLOW
OFFSHORE

CONV.
GAS

DEEP
WATER

CBM

SHALE
GAS

SOUR
GAS

CONV.
MARGINAL

INDICATIVE COST OF GAS SUPPLY

WITH NGL CREDITS

NOTE: Technically recoverable gas resources are approximately 800 trillion cubic meters (28,248 trillion

cubic feet) or about 230 years of gas consumption at currentrates; NGL (natural gas liquids) credits refer to
the additional revenue generated fromextracting ethane, butane, and other oil liquids within the gas stream
as it is prodouced.

Costs of Gas Supply
To understand the impact of technology on the cost of gas supply, it is
useful to look at some of the types of supply available and the range of
costs required to bring those supplies out of the ground. Supply costs,
combined with the transportation costs previously discussed, determine
the full cost of natural gas shipped to end-users. Figure 10 shows ranges
of costs for various types of gas supplies. The actual costs of gas from any
particular location are dependent on a large variety of factors including
gas reserve potential, field equipment and operational costs, tax and land
costs, gathering or processing requirements, and the necessary return on
capital investment.
It is clear from these estimates that there is a wide range of costs from
most potential gas sources. We think a large quantity of gas supply,

40

CHAPTER IV.


perhaps 65 percent of the recoverable gas resource base, can likely be
produced when gas price in production areas range from $4.00 to $8.00 US
dollars per million British thermal units (MMBtu). As technologies advance,
more gas resources will likely become economical within this range.
The lowest cost gas comes from supplies that are co-produced with oil
(associated gas). For associated gas, the oil production “pays” for the
infrastructure to drill for gas, but specialized separation and processing
equipment is required to make the gas viable. The highest cost sources of
gas are marginal gas supplies that come from small fields with low quality
prospects or from fields laden with contaminates like hydrogen sulfide (H2S).
Gas fields that contain toxic gases like H2S are called “sour gas” operations
and require specialized equipment that resists corrosion and provides
leak-proof operations. Gas fields with varying degrees of “sourness” make
up nearly 20 percent of potential recoverable resources—so they remain
an important source of future gas supply. For example, many parts of the
Middle East and the Caspian region have successfully and safely developed
sour gas, and are expected to continue to do so.
Shallow and deepwater offshore gas are additional sources requiring a
variety of specialized technologies. Offshore systems consist of a variety of
fixed and floating technologies along with unique logistical, communication,
and safety considerations related to a marine environment. Deepwater
gas plays are estimated at about 11 percent of the global recoverable
gas resource base. The cost of deepwater gas depends on issues like the
water depth and subsurface conditions including reservoir temperature
and pressure. The development of technology that sits on the sea floor
has been one way to access new resources without using large, expensive
floating platforms. This has made new gas fields cost-effective to develop
and is an exciting area for technology development. Deepwater plays
based on large conventional gas resources with NGL’s have the lowest
costs. Deepwater gas based on medium-sized reserves is expected to cost
in the range of $3.50 to $4.50 per MMBtu including the costs of bringing gas
to shore on dedicated gathering lines.
Unconventional gas sources like CBM and shale gas are potentially
30 percent of global recoverable gas reserves.23 CBM and shale are
fundamentally different than traditional gas supply sources because the
hydrocarbon source rock is also the reservoir (the rock formation that


41

CHAPTER IV.


holds the gas). The potential cost of unconventional gas depends more on
the ability to produce the gas from the reservoir than the absolute amount
of gas in place. Next-generation CBM and shale gas sources are expected
to have similar costs in the range of $4.00 to $8.00 per MMBtu. The mature
developments of shale gas in North America are on the low-end of the cost
range. Expected costs for other regions will initially be 2 to 3 times the cost
of North American supply. Hopefully, technology can be deployed to drive
these costs down.
Two broad supply categories will be the focal points for gas technology
development over the next decade. The first is remote gas mega-projects
including many deepwater, sour gas, and large conventional gas
developments. The second category is unconventional gas, which includes
shale gas and CBM. Each of these categories has different attributes and
will require special technologies unique to their development.
Remote gas mega-projects
The term mega-project typically refers to any gas development that requires
capital investment in excess of one billion dollars. Some natural gas megaprojects can have capital cost 10 to 20 times this level especially if LNG
liquefaction plants are part of the development plan. The increasing scarcity
of low cost oil, and limits on the ability of international oil companies to
access conventional oil resources, have supported mega-gas developments
of remote or stranded gas resources in recent years. This, in turn, has driven
waves of technology development to bring these supplies to market.
Remote gas mega-projects tend to feature:
• Concentrated resources, typically conventional gas integrated
with LNG or pipelines;
• Large upfront capital outlay and long lead time to first gas;
• Harsh environments, often in deepwater or arctic conditions; and
• Vertically-integrated project structures with risk sharing.
There are a number of examples around the world. In Russia, the
Sakhalin Island LNG project in far eastern Russia or the Bovanenkovo
field development in the Yamal peninsula feature Arctic gas challenges


42

CHAPTER IV.


with the need for significant supporting infrastructure (railroads, roads,
port facilities). Large offshore gas projects can also need integrated
infrastructure development. For example, the Shah Deniz project in
Azerbaijan is linked to major gas pipeline development efforts into Turkey;
or the Gorgon LNG project in Western Australia has natural gas liquids
extraction facilities, a large CO2 injection system, and an offshore pipeline
to bring domestic gas from Barrow Island to mainland Australia. These
examples highlight the need for complex systems integration and
coordination for remote mega-projects.
The complexity of mega-projects can drive cost inflation. Technologies
that improve hydrocarbon production, reduce expenditures, or decrease
start-up time in the field are essential. Examples include tested modular
designs that can be scaled up, or the ability to fully test critical components
before arriving on location to insure field performance. Two interesting
technology areas, among many, that could be transformational for
mega-projects in the future are new floating LNG systems and the
Industrial Internet.
LNG technology: super-cool floating systems
The core technology in LNG systems cools natural gas to -260 ° Fahrenheit
(-160 ° centigrade) until it condenses into a liquid at atmospheric pressure.
This reduces the gas to 600 times less than its gaseous volume so it can
be transported. Large LNG liquefaction plants contain
massive refrigeration trains and a variety of systems
to prepare the gas for liquid transport. One key trend
in LNG technology is related to the development of
floating LNG liquefaction plants (FLNG).24 FLNG combines
production and liquefaction on a single vessel so there
is no need for an offshore pipeline to shore. Floating LNG
allows gas producers to access medium sized offshore
gas reserves that are not sufficient to support larger
onshore facilities. FLNG ships can potentially be moved
to new gas fields as reserves deplete, giving them mobility that onshore
LNG cannot match. FLNG liquefaction projects (1.2 to 5.0 Bcm per year)
are typically one-fifth to half the size of traditional LNG supply projects
(7-20 Bcm per year). One advantage of FLNG is that many components

“Floating LNG systems
are likely to be one of the
fastest growing parts of
the gas network over the
next decade.”


43

CHAPTER IV.


can be assembled in the controlled environment of shipyards. This reduces
some of the location-specific issues, like skilled worker shortages, that
hurt the economics of onshore plants. Further downstream, FLNG is also
making an impact through floating regasification and storage units (FRSU)
technology. These ships dock with LNG tanker vessels to store and regasify
LNG for delivery in the gas system. FRSU projects can
be developed quickly (12 to 15 months) and can deliver
large quantities of gas (2 to 10 Bcm), allowing rapid
deployment of LNG into new countries where domestic
supply is scarce and pipeline development is slow. FRSUs
are also a good option for countries looking for a quick
back-up to domestic supplies. Floating LNG systems are
likely to be one of the fastest growing parts of the gas
network over the next decade.

“As the shale industry
expands and matures with
a continuous improvement
mindset, it is likely that
environmental performance
will improve as well.”

Industrial Internet for natural gas mega-projects
Digital and automation technologies will continue to be customized for
upstream oil and gas duty and increasingly be incorporated into next
generation mega-projects. Advanced sensors are allowing real-time
monitoring of operations for safety and efficiency. The combination of
software embedded with hardware allows unprecedented performancemonitoring, as well as field- and asset-level optimization. The new
approaches are moving the industry from a “when it breaks—fix it”
mentality to more asset life-cycle optimization with integrated hardware
and software approaches. Furthermore, remote monitoring and control
tools are becoming more advanced, allowing for improved predictive
analytics. Critical data feeds can be processed and routed to operators
with timeliness and precision, allowing key personnel more time to make
critical decisions and adapt to events. Increasing safety and reducing
down-time will likely shape investment decisions in these technologies,
but the solutions can be leveraged for other benefits like asset optimization
around supply chains or to provide data transparency for regulatory
needs or other reporting purposes.
Unconventional gas: a network of fractures
The most publicized gas supply revolution has come from the unlocking

44

CHAPTER IV.


of unconventional gas resources through horizontal drilling and hydraulic
fracturing. Unconventional gas and oil development has high drilling
intensity, meaning the industry will require constant infusions of drilling
capital to maintain and expand production.25 As a result, unconventional
gas development has a large operational footprint with many services
including drilling rigs and crews, pressure pumping units and crews, water
handling and processing, sand, chemicals, and drill pipe deliveries.
Unconventional gas projects, which have more of a manufacturing type
approach to extraction, often have:
• Distributed resources, typically basin-wide, requiring large land
positions;
• Ongoing capital outlay over the project life to offset rapid decline
rates in individual wells;
• Variation in resource quality that makes identification of productive
“sweet spots” critical;
• Continuous improvement to lower costs, increase productivity, and
boost sustainability.
Fortunately, performance has been improving. The shale industry is taking
less time to drill horizontal wells. Two years ago the average shale well in
the US took 35 days to drill and complete. Today it is being done in 20 days.
These kinds of efficiency gains are being achieved concurrently with higher
productivity from each well drilled. Technologies that improve efficiency
and productivity are critical to unconventional gas. Digital solutions for
shale gas recovery and technologies that support sustainable operations
are two examples.
Advanced imaging and data processing
Industrial Internet solutions are also making an impact on unconventional
operations. New concepts are emerging that can expand shale gas supply
by using data and analysis to more rapidly de-risk unconventional gas in
new regions. One of the reasons shale gas was so successful in the US
was because the sub-surface geology was fairly well understood. There
was more than 50 years of well data accumulated in shale areas that
could be studied and processed before drilling and fracturing began. This is

45

CHAPTER IV.


not the case in emerging shale plays, where only a handful of wells have
been drilled. New technology integrates advanced imaging with well data
cataloging. The idea is to build the knowledge base of rock properties
and then be able to quickly match results to a historic catalog of wells.
This allows producers to design well programs that can be more quickly
adapted to each new piece of information—a critical part of the “learning
by doing” nature of unconventional gas.
Technology for sustainable operations
The sudden success of shale and the impact on the environment has
sometimes created sharp criticism. This has driven keen interest in the
development of new technologies to mitigate the environmental impact
of shale development. If the environmental benefits of utilizing gas are
part of the core value proposition relative to alternative
hydrocarbons, then focus on reducing the environmental
impact is essential for the industry to reach its potential.
A host of technology options are available to improve
well integrity, manage water production and disposal,
reduce fugitive emissions, reduce diesel use, and
optimize operations. Integrating gas and using electricity
to drive pumps and compressors in field operations
is one way to reduce emissions and often lower costs.
Water management is improving through a variety
of processing, purification, and reuse systems. As the
shale industry expands and matures with a continuous
improvement mindset, it is likely that environmental performance will
improve as well. In the end, while it appears shale can be developed safely
relative to other energy sources (all of which hold some negative impact)
individual societies will have to decide if the benefits of shale outweigh
the risks.

“The Industrial Internet
will play a growing role in
securing and optimizing
networks through
technologies that monitor,
analyze, control and help
maintain pipelines.”

Our view is gas supply diversity is increasing. There will be many new
options to supply the gas networks of the future. These gas supplies, with
the help of new technology, will be cheaper and can be produced with
lower environmental impact than ever before. However, the upstream
part of the gas industry is not the only fertile ground for new technology;
midstream and consumer technologies are also advancing.


47

CHAPTER IV.


Securing and Optimizing the Network
There is significant opportunity to further optimize and secure the sea
and land-based components of natural gas systems. Two areas where
technology is making an impact are related to digital monitoring and
control of pipelines, and optimization of CNG/LNG fueling systems. Both
examples feature innovation through integrating existing technology in
new ways.
Digital networks and the intelligent pipeline
In many mature networks, critical infrastructure is aging. For example, in
the US, 50 percent of gas pipelines are more than 25 years old. It is widely
appreciated that the cost of network failure can be enormous. Safety and
the need to better understand asset integrity are the core reasons digital
infrastructure is being more deeply imbedded into the fabric of energy
networks. The Industrial Internet will play a growing role in securing and
optimizing networks through technologies that monitor, analyze, control
and help maintain pipelines.
Some aspects of digital systems are not new; they have grown around the
pipeline networks in the form of supervisory control and data acquisition
(SCADA) systems or through increasingly advanced scheduling systems.
More and more sensors are being deployed to transfer data collected from
inside and outside pipelines to the control stations. However, the volume
of data from increasingly complex systems is outpacing older technologies.
The next generation of digital systems will employ technologies including:
satellite, wireless, cloud storage, and software tools for remote monitoring
and control and predictive analytics.
The goal is to integrate data collection, processing, reporting, and analytics
in smart ways. Physical systems can often mirror biological systems. There
is a growing field of study that is looking for insights from biological systems
to manage complex physical systems in simple and efficient ways. The
lessons from health care can help. How do you create a system that can
“feel pain” or heal in a dynamic way?26 How do we create an intelligent pipe?
Responding to a crisis with “situational awareness” or remotely identifying
weak spots in networks, detecting leaks to reduce fugitive emissions, and
faster asset recovery are just a few benefits of this technology.


48

CHAPTER IV.


“Gas generation technologies
are continuing to be pushed
to new design limits.”

While safety and reliability concerns will drive
deployment, over time we see additional benefits
related to optimization and transparency. Better data
and deeper analytics may allow operators to push
the operating envelope of pipeline systems allowing
additional throughput and revenue due to better business insight. Further,
improved underlying data systems can provide shippers on the network
near-real-time information, allowing for increased transparency and price
fluidity in market-based systems. This becomes even more critical as
constraints and costs of new infrastructure are driving multiple energy
networks to become integrated. The need to manage gas networks for
the hourly variations in electricity generation due to renewables is just
one example. More broadly, the need to capture the value across energy
networks will only increase and digital technologies will play a key role in
allowing this to happen.
Fuel systems for “mini-midstream”
While technologies for small-scale natural gas recovery have been
available for years, new efforts are underway to integrate technology and
use a variety of “mini-midstream” offerings. Midstream refers to the part
of the gas industry between the producing fields and the consumers and
the “mini” explains the scale of these facilities relative to traditional plants.
Integrated designs typically have some element of gas pre-treatment,
CNG compression, LNG conversion, leak-proof operation, and rapid
distribution, along with storage or delivery systems optimized for safety.
The sizes of these systems are very small compared to larger gas options
(0.04 to 0.2 Bcm per year). There are a variety of target markets for these
technologies including the transportation sector (heavy-duty, light-duty, and
marine fleets), small-scale power generation, and for upstream or remote
mining operations. In most applications, natural gas can closely match
performance of gasoline or diesel-based networks. Storage is a challenge
for both CNG and LNG, so this is a key area for technology innovation. The
lower energy density of CNG requires special steel tanks that are heavy.
Lighter and stronger materials are becoming available, but tend to be
more costly. LNG has a much higher energy density, but requires special
insulators and thermal tanks that keep the LNG cool and special cryogenic
systems to pump the LNG.


49

CHAPTER IV.


The critical hurdle to scale-up of these small gas systems is the lack of
fueling stations and infrastructure. New technology solutions will be
focusing on removing this barrier to development. Innovative approaches
feature smaller modular designs, portable and re-deployable solutions,
and factory-tested or preconfigured solutions for shorter permitting and
installation. Rapid deployment is a key element in these new network
systems. Most systems can be running in 12 to 18 months, and even as fast
as 6 months in some cases. Cost savings come from standardized designs
that can be scaled and customized to particular applications.
Growing the Network
Natural gas is a versatile fuel. Environmental advantages coupled with
high efficiency and flexibility make natural gas a great choice for power
generation and many other uses. Unlike coal or nuclear fuel, it can be
cost-effective when used in both large and small-scale applications.
Furthermore, as gas networks become available, it can become an
alternative to oil. The technologies being deployed today are designed
to bring flexibility to operations, help consumers capture value and create
security of supply. Effectively mobilizing these demand-side technologies
are an important part of achieving the sustainability, resilience, and
competitive benefits of natural gas.
In this section, we briefly highlight key gas generation technologies and the
relative costs of gas versus other fuels in power generation. These and other
demand-side technologies will be discussed more fully in the next section
in the context of the future of gas networks, recognizing that this is only a
small sample of the technologies that are available to utilize natural gas.
Flexible power with natural gas
Gas generation technologies are continuing to be pushed to new design
limits. The latest flexible combined cycle power plants are reaching
thermal efficiencies in excess of 61 percent27—meaning almost two-thirds
of the energy in the natural gas is converted into electricity. If built at
large scale, for example 750 megawatts (MW) of power, one plant can
provide the annual needs of almost 600,000 US homes.28 These plants
can start-up in fewer than 30 minutes and increase power output at 100


50

CHAPTER IV.


MW per minute. When necessary they can be turned down to 14 percent
of their baseload capacity to adjust to changes in system demand or the
introduction of intermittent renewables. Simple cycle gas turbines are used
for peaking duty and renewables balancing. For situations where a wider
operating range is necessary, the latest generation of flexible, combinedcycle technology can capture most of the benefits of a peaking unit in a
high efficiency system. Furthermore, the integration with renewables can
occur through the electric grid at the system level or within the design
of the power plant itself. For example, integrated solar combined-cycle
technology is a hybrid system that uses a solar collector system to heat the
water that is fed into the gas plants steam system. This reduces fuel use
and improves thermal efficiency to nearly 70 percent while improving the
economics of solar power.
At a smaller scale (typically 10 to 120 MW), gas-fired combined heat and
power (CHP) systems using gas turbines, or gas engines for small plants,
are an interesting gas technology option. CHP systems use the same
fuel to create both electricity and steam. The steam is then converted
into heat, or through condensers, into cooling for large commercial
buildings, hospitals, airports, or industrial sites. Utilizing CHP, also called
cogeneration, these power plants can achieve thermal efficiencies in excess
of 80 percent, often with lower emissions and losses than grid-supplied
options. Furthermore, CHP operations can be designed to disconnect from
the larger grid in the event of a disruption, allowing critical facilities to be
operated in “island” mode during natural disasters. However, CHP systems
do have disadvantages. CHP projects can require customized designs
and are tricky to develop in existing buildings. Additionally, coordination
between electric grid operators and CHP operators is critical on a number
of issues including excess power flowing back to the grid, back-up power
requirements if the natural gas supply is disrupted, or safety concerns
that might result from miscommunication.29 Finally, the complexity of CHP
relative to traditional boilers requires the training and development of
skilled service technicians so systems run optimally. While barriers do exist,
the potential benefits from a sustainability and resilience perspective can
make CHP an attractive option.
Another gas technology for smaller applications (0.3 to 10 MW) is the natural
gas engine. These engines can have high efficiencies (up to 45 percent
thermal efficiency) relative to other simple combustion technologies. These

51

CHAPTER IV.


engines can be used in CHP configurations to achieve higher efficiency
or in other distributed settings. They have low emissions relative to their
diesel-fired counterparts and can run on a wide range of natural gas
qualities (from rich to lean) and a variety of other gases including biogas,
landfill gas, coal mine gas, sewage gas, and combustible industrial waste
gases. The ability of some gas engines to burn natural gas with higher
liquids content (rich gas) is ideal for oil and gas field power generation
applications such as drilling and enhanced oil recovery.
Combined-cycle technology, CHP, and gas engines are three key gas
generation technologies that will continue to advance. However, other
technologies are emerging, such as fuel cells and small biogas systems.
Gas generation and the Industrial Internet
Like upstream and midstream operators, power generators can benefit
from the same preventative maintenance or fleet optimization ideas
that are being used elsewhere in the gas industry. Data compression
techniques are allowing plant operators to track changes in massive data
streams instead of tracking every piece of data all of the time. As a result,
operators can now better visualize the correlation between key data
streams like temperature, system loads, humidity levels, and poor plant
performance. Operators can query the system concerning an irregularity,
and historic analogs are mined across thousands of units in service. Just
as in shale gas, this enables companies to engage constant learning to
improve efficiencies and reduce costs.
Capital intensity of power generation options
Cost is one of the key factors driving choice of power generation technology.
One of the key advantages of natural gas generation is that it often has
lower capital intensity than other sources of electricity. As shown in Figure
11, on a dollar per kilowatt ($/KW) basis, the cost of installing gas technology
is one-third to one-fifth of the estimated cost of coal or nuclear plants,
respectively.30 Although regional factors can alter the relative capital cost
advantage of gas technologies they typically have lower capital costs,
but higher fuel costs. To understand the full cost of electricity, analysts
examine the cost on a dollar per megawatt hour ($/Mwh) or dollar per


52

CHAPTER IV.


kilowatt hour ($/Kwh) basis. The cost of electricity is driven by a number of
factors including the cost of fuel, the utilization rate of the power plant, the
financing term and asset life of the project, along with the capital costs of
plant construction, and in some regions, costs associated with emissions.
When evaluated on levelized cost basis, gas is still competitive against other
technologies, but as previously discussed, fuel prices are a critical driver of
energy costs. Changing the cost of fuel from $5.00 to $12.00 per MMBtu can
change the cost of electricity for combined-cycle plants from $40 to $110
per Mwh. While the cost is important, other factors like capital intensity or
water requirements can be important in some regions. Multi-billion dollar
projects, like coal and nuclear, have long development timelines and are
difficult to build if institutional structures are weak and or electric networks
are immature. Water use is another limiting factor for some thermal
technologies. Natural gas generation typically has one-quarter the water
requirements of coal or nuclear plants depending on what type of cooling
system is in place.
New technologies are driving network growth
Technological advances have been vital to the expansion of the natural
gas industry over its history and will be just as important in the future. New
technologies are expanding gas supplies, which can now be produced with
reduced environmental impact. Digital technologies and the Industrial
Internet will also play a large role across the value chain. Gas-generation
technologies are becoming a preferred energy platform because of their
versatility and flexibility in supporting other energy sources like renewables.
Technology is playing a critical role in supplying, securing, and growing the
gas networks of the future.


53

CHAPTER IV.


Figure 11. Gas Generation Has Lower Capital Costs
Source: GE Estimates, GE Power and Water, EIA, JISEA, IEA

1500
750
DIESEL ENGINE

375

200

50

SOLAR PV
INDICATIVE
COST RANGE

TYPICAL POWER
PLANT SIZE IN MW

150
ELECTRICITY
COST
$/MWH

GAS
SCGT

100

NG ENGINE

NUCLEAR
WIND

GAS
CGCT

COAL
GAS CHP

50

0
0

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

$/KW CAPITAL COSTS

NOTE: All prices are in real 2010 dollars; no carbon prices included. Gas prices range between $5.00 and $12.00 per MMBtu; coal prices range between $2.00 and
$4.00 per MMBtu; Diesel prices range between $15.00 and $25.00 per MMBtu; Gas SCGT capacity factor 10%; Wind capacity factor ranges between 25% and
40% without tax credits. Solar capacity factor ranges between 25% and 35% without tax credits. 10% IRR and 30 year asset life, except engines and solar have
10 year life.
SCGT: Single Cycle Gas Turbine; CGCT: Combined Gas Cycle Turbine; CHP: Combined Heat and Power


54

CHAPTER V.

FUTURE OF GAS NETWORKS

V. FUTURE OF GAS
NETWORKS
Gas networks will continue to grow and evolve. Exactly how and where this
will happen is uncertain, but several patterns seem likely. Mega-pipeline
and LNG projects will continue to be the anchor systems for global network
growth. This is the traditional growth path to connect large supply sources
with demand centers. Complementing these large-scale systems will be
the next generation of smaller modular systems or satellites. Gas network
development will involve the interplay between these anchors and satellites
around the world. Another important trend will be the continued integration
of gas with other energy network systems. Two are of particular interest—
one involves the synergies that can be achieved by more deeply joining gas
and renewables for electricity generation; the second is the inroads that
gas will continue to make into as a transportation fuel.
Developing New Gas Networks: Anchors and Satellites
The future development of gas will evolve across a range of development
models—from state-owned vertically-integrated systems, where the state
controls all aspects of development and trade; to the highly competitive
networks of North America where government provides only the institutional
structure for private investment.31 Across this spectrum, the development of
large-scale projects combined with smaller offshoots will continue to evolve.
Anchoring big projects in the future
The idea of “anchoring” is fundamental to all large gas developments.32
Projects are physically anchored on large supply and demand centers, but
also anchored in a contractual and financial sense. Anchoring describes
the matching of producer and consumer interests across the value chain
that allows multi-billion dollar gas projects to move forward. The idea of
anchoring is important because these large anchor gas projects become
the critical infrastructure that gives natural gas a foothold in new regions—
becoming the hubs that other smaller projects can build around.


56

CHAPTER V.


The traditional model for anchoring pipeline and LNG projects has been
vertical integration across the value chain.33 For mega-projects, this will
likely be true in the future as well. In fact, this practice has been increasing,
particularly in Asia, as a way to offset mega-project cost pressures.34
Backwards integration by large gas consumers, such as power generators,
into LNG upstream activities is also fairly common and
may be more prevalent in the future as supply diversity
increases. There are strong arguments from producer
countries on the merits of the long-term contracting
model to finance large gas projects and maintain
security of supply and demand.35 The challenge is that
the traditional system can be rigid and poorly equipped
to withstand changes in market conditions.

“In competitive markets
the role of the state is to
establish the institutions
that protect consumers
and let the private players
innovate, take on risks, and
create value.”

In the future, as gas networks expand and market
structures change, it seems likely that competitive gas
market models will advance.36 In competitive markets
the role of the state is to establish the institutions that
protect consumers and let the private players innovate, take on risks, and
create value. Competition is a natural outcome of an increasing diversity of
supply options, more destination-flexible LNG supplies, new unconventional
and conventional gas discoveries, and a larger integrated gas network.
However, the specialized nature of gas network assets and the large
financial risks involved mean that “merchant” approaches will be difficult for
large anchor projects, except in the most mature parts of the gas network.
Around the world, a large number of anchor gas projects are likely to
advance over the next decade. There are a variety of examples, some with
different development models.
Selected examples include:
• Deepwater gas projects in India, China, and West Africa
• Shale-based LNG projects in the U.S. and Canada for export
• New or expanded regional pipelines
• Iraq to Turkey
• Turkmenistan to China


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• Russia to China
• Southeastern Europe (Russia and Azerbaijan)
• Mozambique to Kenya and South Africa
• Indonesia (Sumatra and Java).
• Brazil (Northeast and shale region) and Argentina (shale region)
• US to Mexico
• US Northeast (Marcellus shale region)
Most of these regional anchor projects will use traditional development
models. However, projects within—or originating from—North America,
or connected to Western Europe, will be influenced by competitive
dynamics. How these two development models interact and reshape the
gas market going forward is one of the big questions facing the industry.
Institutional structure and gas networks are evolving simultaneously. The
ability of countries and companies to anchor big network projects are
subject to a host of regional factors and market constraints. In growth
regions, traditional development with long-term contracts will continue,
but the terms will start to reflect a more hybrid gas market. Increasing
options for gas consumers and the competitive dynamics against
alternative fuels, particularly in power generation, will likely drive the
need for multiple approaches.
Satellites
The idea of satellite or “step out” expansions around existing gas
developments will continue to grow over the next decade. The development
of a large offshore platform or pipeline and processing facility creates
opportunity for incremental development of smaller and isolated resources
that otherwise would be uneconomical. An extension of this concept is the
idea of satellite opportunities around existing midstream operations. This
idea is not entirely new. Traditional compression or “looping” expansion of
existing transmission pipelines is an example, as is process de-bottlenecking
at liquefaction or fractioning plants to increase throughput, or simply the
extension of distribution systems to new communities.


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In the future, the combination of new technology with the growth of
major gas infrastructure will offer expanded opportunities for incremental
expansion. This will occur through a new generation of smaller modular
systems and with digital systems—allowing additional optimization of
latent capacity. For example, there may be an opportunity to squeeze LNG
cargo out of an existing liquefaction plant, or better
measurement and control of pipeline operations that
allow safe operation at higher pressures and increased
throughput. Clearly expansion around existing systems
brings questions of security, interconnection, access, and
collaboration that need to be managed in order for these
opportunities to be realized. However, the increasing
network density and interoperability of gas systems are
creating new growth opportunities.

“Given uncertainties and the
pace at which larger central
generation projects may
be built to meet demand,
distributed energy provides
a viable alternative.”

Distributed power with natural gas
Distributed power is poised for rapid growth. As gas engine and smallerscale gas turbine technology has evolved and become more efficient,
distributed power options are able to compete more effectively against
centralized generation. Moreover, in emerging markets, where infrastructure
is limited and regulatory and financial institutions are underdeveloped,
distributed energy is an attractive choice. The flexibility of natural gas makes
it an ideal fuel for a variety of distributed power opportunities including:
• Electricity and heating or cooling in cogeneration applications
• Pipeline and processing plant compression in gas networks
• Electricity islands in developing markets with weak or unstable grids
• Off-shore applications like ships and drilling platforms
• Electricity generation for remote sites, such as mines and oil and
gas fields
• Fast-track deployment of generation to meet emergency power
needs
• Next generation fuel cell or micro-turbine technologies


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The lower levels of capital expenditure (lower capital intensity) and the
faster timeline to “first power” or the initial production of electricity are
key attributes of distributed power with natural gas. The trade-off is that
unit costs can be higher. However, to the extent that modular growth is
possible, these distributed sites can be replicated and integrated into larger
transmission networks as they develop. Distributed power, and/or virtual
pipeline concepts, can be a smart way to trigger economic development
by initiating new energy networks or leveraging existing networks for
incremental benefits.
Today, the high-cost oil and environmental concerns are driving incentives
for oil/diesel substitution. The costs of oil-fired generation can easily be
in excess of $0.25 per kWh. Small-scale gas solutions, like gas engines,
can often cut the cost of power by more than 50 percent, even after
accounting for the cost of gas delivery. However, building dedicated gas
infrastructures for smaller gas projects is challenging. Instead, leveraging
existing gas pipeline infrastructure, and/or using small LNG or CNG systems
are solutions, especially if stranded or low cost gas supplies are relatively
close geographically. Furthermore, there are now opportunities to combine
gas with other sources like solar. Gas can also complement small PV solar
systems to overcome intermittency issues. This is where gas generation is
an option to “firm-up” solar.
Distributed power opportunities are, by nature, driven by very region
specific-issues. Developments that are taking place in Mexico, Egypt and
Myanmar, and the special case of flare gas reduction, provide specific
examples that help define the opportunities as well as challenges.
Mexico
Mexico provides an example of how distributed power opportunities are
emerging—anchored on larger natural gas projects and tapping neighbors
with lower cost gas supply. There are currently proposals to build 8,800 km
of new gas pipelines across the country.37 Most of the projects are looking
to draw on lower-cost US shale gas to displace the use of heavy fuel oil in
centralized power generation. As a side benefit, these investments have
the potential to expand the availability of decentralized gas-fired power.
New pipelines will improve gas access to over 280 cities and towns across
the country. It also has the potential to significantly reduce the cost of

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CHAPTER V.


energy to these communities. Today, the commercial rate of electricity
is $0.20 per kWh. Electricity for industrial consumers is $0.12 per kWh.
The Federal Electricity Commission (CFE) is the sole public power utility in
the country. However, Mexico does allow small self-supply, cogeneration
and renewables with various payment structures including net-metering
(credits for self-generated power). The cost of electricity could fall to
$0.7-0.8 per kWh if gas can be delivered for around $8 per MMBtu.38 With
gas coming into Mexico at the US border at $4.00 per MMBtu this seems
possible. Leveraging the expansion, low-cost gas supply is likely to create
new opportunities for commercial and small industrial users, as well as
possibilities for remote mining or oil and gas operations to switch to gas.
Egypt
Egypt is at a critical juncture in the development of its energy system.
Egypt has the advantage of fairly mature gas and power grids, but it
is concentrated along the Nile river region. Most of Egypt’s oil and gas
resources are relatively remote—in the midst of deep desert or in deep
water off the coast. The existing power grid into greater Cairo and points
south has stressed capacity at times with reserve margins falling below 10
percent in recent years. A diversified electricity strategy is attractive as fuel
risk increases and new large centralized generation projects face delays.39
Given uncertainties and the pace at which larger central generation
projects may be built to meet demand, distributed energy provides a
viable alternative. Industries facing electricity disruptions are looking to
add capacity in smaller blocks; leveraging available space in the gas
system, and diversifying with gas, solar, and wind to increase electricity
reliability. Recently, peaking power prices have been in the range of $0.06
to $0.08 per kWh and gas prices have been around $2.00 to-$4.00 per
MMBtu for small industry and commercial sites.40 Low gas and power
prices have hurt distributed renewables, but gas-based distributed
power can serve to avoid peak-period constraints even at current prices.
While distributed gas generation is increasingly attractive to overcome
supply bottlenecks in the near-term, Egypt will need both centralized and
distributed resources from a variety of sources to meet growing energy
needs over the long-term.


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Myanmar
Recent reforms are spurring new economic opportunities in Myanmar. The
prospects for demand growth are enormous and the country’s electrification
rate is estimated at only 26 percent. Power market reforms and progress on
new pricing policies will be critical to drive investment, but if these efforts
advance, the potential for growth is good. Conservative expectations call
for a doubling in power consumption in 3 to 5 years if supplies can be made
available.41 While Myanmar is fortunate to have large natural gas resources,
the current gas infrastructure is highly limited. The gas pipelines serving the
domestic market are in need of upgrading and repair. The gas generation
capacity in service today in Myanmar is highly inefficient.42 The leveraging
of existing gas export infrastructure offers the potential to accelerate
domestic gas-based power generation.
Taking advantage of these opportunities and making improvements
to the existing domestic distribution system could roughly triple gas
availability into the capital city of Yangon and surrounding areas.43 This
expansion will create opportunities for small and medium-sized generation
and cogeneration plants. These high-efficiency generation “islands” can
be built within a few years and set the stage for larger, more integrated
development down the road. Electricity prices in Myanmar are in the range
of $0.08 to $0.10 per kWh. Even assuming natural gas prices near export
parity of around $10.00 per MMBtu delivered, medium-sized combined
cycle (less than 100 MW or smaller distributed power options) should be
economical. To be successful, the government and operators will need
to consider how these modular and isolated systems can be efficiently
integrated into the larger centralized grids over the long-term. A building
block approach of small island grids with appropriate voltage and
network protocols will ensure that the larger transmission systems can
be linked together to benefit the overall evolution of the integrated gas
and power networks.
These examples illustrate only some of the ways in which gas can
complement or substitute for centralized power as gas networks evolve:
• The potential to lower electricity costs and potentially drive
economic development and industrial competitiveness


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CHAPTER V.


• The ability to overcome constraints on the development of new
centralized generation
• The potential to utilize distributed gas-power “islands” for fast
access to energy with the option to integrate these “islands” into
the larger grid as transmission expands.
Flare gas reduction
Natural gas flaring traditionally occurs in places where remoteness or
economic considerations have driven governments and producers to burn
away unmarketable gas during oil extraction.44 The economics of gathering
and transport can be marginal and if gas infrastructure does not exist, gas
flaring occurs.
Despite progress in this area, natural gas flaring remains an important
issue. At present 140 BCM gas is flared each year on a global basis.45 This
is equivalent to approximately 5 percent of global production. Since gas
is often present when drilling for oil, gas flaring has been part of the oil
industry since its inception. What is striking in the recent data is that in just
a few years the US, largely as a result of oil growth in the Bakkan in North
Dakota, has become a top-five flaring nation. The World Bank’s Global Gas
Flaring Initiative has challenged gas producers to reduce gas flaring by 30
percent by 2017.46 The Age of Gas outlook is more optimistic, envisioning
50 percent reduction by 2020. New technology, strong regulatory practices,
and finding ways to utilize new and existing gas networks will contribute to
making this happen.
Leveraging existing gas infrastructure has traditionally been one of the
best ways to reduce flaring at smaller onshore fields. Often, smaller
satellite plants can be managed with modest gathering pipeline and
processing investments. In other cases where little infrastructure exists,
possible solutions might include mobile power generation to utilize gas
in field operations, reinjection of gas back into the formation, and micro
LNG or CNG offer solutions. Natural gas is cleaner burning—and typically
less expensive—than diesel trucked onsite, making it a great option if gas
recovery is viable. All of these technology solutions effectively leverage
power generation technology or road systems as ways to reduce flaring.


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CHAPTER V.


Another option that is gaining traction is the use of onsite flare gas to power
artificial lift technologies. Artificial lift includes a range of technologies that
are used to increase oil production from existing facilities after natural
reservoir pressure begins to decline. Power generation is integrated with
the lift technologies and a common set of monitoring and control systems.
The advantage is that there is no waiting for availability of new electric
grids. Also the systems are modular and can be redeployed at new fields
as necessary. This approach will grow as a solution to flaring.
Offshore gas flaring poses a different set of issues. Space is limited at
offshore sites, so reinjection or power generation is a good option. More
recently, mid-scale gas-to-liquids (GTL) technology has advanced. The
advantage of GTL is that it can leverage existing oil takeaway infrastructure
and avoid costly gas pipelines for low gas flow rates.
Finally the expansion of gas networks will also make a contribution to the
reduction of gas flaring. Projects like Angola LNG, Kuwait’s one-percent
flaring program, Iraq’s southern gas system, Mexico’s gas processing
expansion, Qatar’s Al-Sheenan associated gas projects, or Russia’s use of
gas reinjection and remote power generation have reduced gas flaring.
Going forward, the oil and gas industry will continue to have to find
innovative solutions to avoid the waste and environmental impact from gas
flaring. In addressing these issues, it will be critical to identify opportunities
to deploy technology to leverage gas, power, and transport networks.
Future Network Integration
The economics of energy transportation are greatly improved when there is
an ability to leverage existing infrastructures. The incumbent hydrocarbons
in the world today, oil and coal, have been able to avoid some measure of
transportation cost by leveraging existing road and rail networks that had
been built to meet other transport needs. Over the last few decades, robust
digital networks have been built upon early defense-related communication
systems and other fiber-optic communications links. Natural gas pipelines
and LNG networks have followed a similar evolutionary path to power
systems. At times, gas systems have been able to utilize conversions of
existing oil pipelines, but for the most part the gas network has been
built-up over decades. More recently, the networks supporting shale gas
development have expanded. For example, rail and trucking systems are

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CHAPTER V.

“As economies diversify and
expand, more regions will
have highly variable electric
load profiles similar to
advanced economies.”


used to bring sand and water into the well sites and
move natural gas liquids and produced water away.

Constraints in one network can provide incentives to
expand other networks. Constraints on the bulk power
transmission system create opportunities for gas-fired
power close to load centers. Constraints related to
building oil pipelines create the opportunity for liquids
shipments by terminal and rail. Similarly constraints on
the gas pipeline network create opportunities for distributed LNG systems
to provide peak-period support or present new options for distributed
generation. Constraints on fuel or allowable emissions drive renewable
development. Figure 12 shows a schematic representation of various energy
networks. The natural gas system is uniquely situated to support other
energy networks. From flexible and high efficiency power generation options
to a variety of industrial, transportation, marine, or remote applications,
multi-network optimization is about the role of technology in facilitating
network switching in a proactive way.47 The intersection of the various
technology and market trends discussed so far offers a picture of what we
will see in the energy networks of the future.
Several broad topic areas offer insight on gas network evolution including
the role of gas in supporting renewables development and natural gas as
a transport fuel. While not exhaustive, both of these topics feature issues
related to the overlap between gas, power and gas and oil networks,
respectively. Natural gas and carbon policy is a third topic where we
highlight a few issues relevant to the future of gas networks. Collectively,
these topic areas with the earlier distributed energy discussion, illustrate
how energy networks work together today. Furthermore, they highlight
the potential for further integration to drive economic development,
sustainability, and energy security.
Joining Capabilities: Gas and Renewables
How the relationship between gas and renewables will evolve is one the
most important questions facing the power sector over the next decade.
Gas is considered a threat to renewables in some regions because it is a
low cost option to wind and solar.48 Our view is they both will grow and
complement each other more often than compete.49 The partnership


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CHAPTER V.


Figure 12. Multi-Network Integration: Gas, Power, Road and Rail

INTERNATIONAL TRADE

PORT

OIL/GAS FIELD
MARINE SOLUTIONS

MINE
POWER PLANT
REFINERY
INDUSTRY USE

WIND FARM
FLEXIBLE POWER

INTERNATIONAL TRADE
GAS PLANT
L N G

TRANSPORT FUEL
LINKAGES

SOLAR
FLEXIBLE POWER

PORT

HIGH EFFICIENCY
POWER

GAS FIELD
REMOTE POWER
COMPRESSION

GAS
POWER
ROAD
RAIL
GENERATION

INTER-REGIONAL TRADE

PROCESSING
L N G

LNG/CNG


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CHAPTER V.


between gas and renewables is built on supporting each other’s
weaknesses. The variability of renewable sources can be complemented
with the flexibility of gas-fired power. At the same time, the zero fuel cost
associated with renewable generation can provide a valuable hedge
against potential gas price volatility. When combined, the resulting energy
source has a relatively low emissions profile and lower capital intensity
than other options.
Managing the increasing load variability from supply and demand sources
is a growing challenge for network operators. Because electricity is
created as it is used, consumption varies significantly hour-to-hour
depending on the climate and economic base. As economies diversify
and expand, more regions will have highly variable electric load profiles
similar to advanced economies. Further, as renewables penetration
increases, electric supply will be more intermittent. As a result, more
regions of the world, like parts of Europe and North America today, will
face growing power system integration issues.50 There are various options
available to grid operators. Conservation and “load shedding” in peak
periods is one option. However, consumers dislike having their power shut
off. Large-scale electricity storage options are available but expensive
today.51 “Smart grid” and incentive-based mechanisms using price signals
are expanding. For example, demand response technology that is fully
automated and invisible to the end-user shows increasing promise. As
a result, natural gas used as a stand-by option is often the most cost
effective way to manage this variability.
While gas generation is well suited for highly variable power loads, this
creates complications in the gas network. Rapid changes in gas generation
create large swings in the need for high volume, high pressure supply
from the gas network. Hourly variations can be substantial and must be
managed through the inherent flexibility of the pipeline, underground
storage, or LNG systems. However, when generator demand is coincident
with other loads, like winter heating needs, shortages can develop.52
Generators that can comfortably rely on excess pipeline capacity and
interruptible services in the summer season can be caught short in the
winter.53 The opposite problem happens when gas networks are dedicated
only to variable and intermittent generators. For example, this is a problem
in Brazil where gas-fired power is used to balance variations in abundant


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CHAPTER V.


hydro generation. Low utilization rates hurt pipeline development
economics by driving up costs to provide flexible services.
Coordinating grid operations will be important for gas and renewables
to work together effectively. In gas and power networks, the industry
debate centers on how to allocate systems costs; who benefits and
who pays. Solutions are elusive, but finding ways to increase real-time
communications between operators, build new infrastructure, and expand
system flexibility is vital. If generator gas supplies are going to need to be
more firm, yet more variable, there are costs transferred back to the gas
network that need to be addressed. However, when flexible electric grids
can be expanded at the same time, the ultimate integration costs across
both the gas and power sectors might be less. A purely gas-based or
power-system based solution is likely to be sub-optimal to a more holistic
approach. And furthermore, there may be ways to leverage other networks
as well. For example, in mature grids it might be possible to use small LNG
or CNG facilities in a flexible way—perhaps by serving power generation
or heating needs during peak periods, but then switching back to serving
transport markets in other periods.
Going forward, renewables will be a bigger part of the energy mix for a
variety of reasons. Natural gas will be as well. Both power and gas network
operators will have to adapt to that reality for the potential of these two
energy sources to be realized.
Links to Transportation
Natural gas vehicle growth is expected to grow sharply over the next
two decades. However, since 2008, the natural gas vehicle (NGV) fleet
has grown at around 15 percent annually, and today there are about 15
million light duty vehicles (CNG) and one million heavy duty vehicles and
buses (LNG).54 Most of this recent growth has been in emerging markets.
Iran, Pakistan, China, India, Brazil, and Argentina have large and growing
numbers of vehicles. Government policies have incentivized NGV growth,
mostly as a way to avoid importing finished oil products. As natural gas has
become scarce or more expensive in some of these countries, this model
for NGV growth is slowing.


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Today there is growing promise for a new NGV development model in
countries with extensive energy networks. Economic incentives based on
the upward structural shift in global oil prices, coupled with low natural gas
prices, are driving growth.55 Oil is and will continue to be a highly-prized
fuel. However, higher prices are creating incentives to find substitutes.
In the last three years, the divergence between gas and oil has become
sizable. Today, in North America, the cost of natural gas is less than onethird the cost of diesel or gasoline on a wholesale basis. Even in Europe,
spot-traded natural gas is 60 percent below wholesale diesel prices. Other
regions with abundant natural gas like Russia, Qatar, and Nigeria, are
investigating the possibilities for further development. The GE Age of Gas
outlook anticipates global NGV gas use to grow at 6 to 8 percent annually,
led by growth in North America and China.
Heavy-duty fleets, railroad operations, and some shipping applications
have great potential as a market for LNG. The pro forma economics are
compelling for high-mileage vehicles that return to a central depot like
buses, taxis, refuse trucks, and some trucking operations. In North America,
payback on new natural gas powered “class 8” trucks can be in the range
of 3-5 years.56 Payback on engine and fuel system investments relative to
diesel for larger vehicles like locomotives or small vessels like tugboats, is
4-9 years depending on assumptions.
The full environmental consequences of moving to NGVs are uncertain.
The use of natural gas sharply reduces traditional pollutants like sulfur
and nitrogen oxide. Additionally, carbon emissions are typically 30 percent
less than oil. However, methane is a potent greenhouse gas and there are
concerns about upstream fugitive emissions and leaks from the LNG and
CNG delivery infrastructure. In the case of large vessel shipping, the lower
sulfur emissions from LNG solutions are a positive and should drive gas
growth as regulations on burning heavy fuel oil in coastal areas become
more restrictive. The elimination of fugitive emissions will rely on the
technology options discussed earlier, and if successful, should not create
a major constraint on NGV growth.
Infrastructure is the critical issue in expanding the NGV market. The share
of NGV vehicles relative to the global fleet today is around 1 percent.57
The costs of development depend greatly on what kind of fleet is adopting
natural gas. Urban fleets that operate in a concentrated area or private


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CHAPTER V.


heavy-duty vehicle fleets that have a concentration of demand are likely
to be the first to switch. Later as broader networks are assembled, lightduty and personal vehicles will adopt.58 There are several ways to expand
fuel delivery networks including leveraging existing gas infrastructure,
developing NGV corridors, and hybrid vehicle options.59 Another important
factor is the need to develop new business models to advance the market,
since traditional fuel and natural gas distributors may not have strong
incentives to develop new infrastructure. It may also involve shifting
natural gas back to a utility or LNG into small-scale power generation when
economics dictate. Retaining options in the fuel network may also help if oil
prices cycle down for a period of time. In general, taking advantage of the
NGV’s potential can provide a new source of flexibility for the gas, oil, and
power markets, but also a new element of competition.
Natural Gas and Carbon
The discussion of natural gas from a long-term carbon policy perspective
is an important topic within the overall natural gas debate. Detailed
technology and policy discussions are beyond the scope of this paper,
but a few observations related to the development of gas networks are
worthwhile to outline. Carbon concentrations are continuing to climb.
Global carbon emissions are reported to have increased by 1.4 percent
in 2012, with CO2 concentrations hitting nearly 400 parts per million—5
percent higher than a decade ago.60 International government response
to climate change has been slow, and within the climate debate there is
more focus on adaptation strategies in addition to mitigation. Natural
gas is seen by some as a pragmatic fuel option that offers environmental
benefits and lower costs. This may be a sub-optimal outcome to some,
in terms of the desire to shift away from all hydrocarbon energy, but one
that is happening anyway because of the relative energy costs of gas to
renewables, and the relative environmental attractiveness of natural gas
to oil or coal in many parts of the world.
There are a mix of environmental benefits and costs to natural gas. In
advanced power generation, carbon-dioxide from natural gas combustion
is roughly 50 percent lower relative to coal-fired technologies and 30
percent lower than oil. There are significant local pollution benefits in terms
of reduced sulfur, nitrogen, and volatile organic compounds. However, gas


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CHAPTER V.


is still a hydrocarbon and there are losses that occur in the development
and transmission of natural gas, which is mostly methane. Methane,
when vented directly to the atmosphere, is a powerful greenhouse gas.
Issues related to water pollution and shale development are also welldocumented. For the most part these facts are undisputed.
However, the scale of waste and leakage from the global gas system
remains uncertain today. Furthermore, there are questions on how fast
fugitive emissions may increase with the advent of new supplies like shale
gas. These are legitimate concerns; however, with a focus on reduction
technologies, and appropriate regulatory policies, many of these negative
externalities can likely be mitigated. Actions that can improve emissions
monitoring and ensure greater adoption of technologies that can costeffectively reduce methane leakage, while maintaining safety and reliability
of the network, should be pursued. More broadly, natural gas is more likely
to reach its potential if it is accepted as a safe, sustainable, efficient,
and reliable energy source.
Perhaps the larger issue is what will happen if natural gas is not competitive
in Asian power markets and other developing nations. The scale of carbon
emissions growth from the emerging economies will dwarf the growth
rates from advanced economies if coal maintains a dominant share of the
generation growth. Even if the US and Europe pursue aggressive renewables
policies with significant increases in energy efficiency and sharp declines
of coal use, the future of Asian coal growth will likely mean a future of
increasing carbon emissions globally. The unfortunate implication is that the
developing world will likely see more negative effects from climate change
and have fewer resources for adaptation. Alternatively, the successful
development of shale gas and aggressive development of the global natural
gas network over the next decade is part of the foundation for a lower
carbon energy system in the long-term.


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CHAPTER VI.

CATALYSTS AND CONCLUSIONS

VI. CATALYSTS AND
CONCLUSIONS
The natural gas industry is set to take on a larger role in the global energy
landscape. However, there are still tremendous challenges to overcome.
The high cost of network development and entrenched institutions in
the gas industry could cause slower energy market transformation than
envisioned here. There will need to be greater systematic attention to the
importance of building out gas networks and taking advantage of the
vertical linkages between various energy systems. As a result, policy and
innovation catalysts will be important in facilitating network growth and
enabling the Age of Gas.
Three broad areas for policy efforts include:
• Investment
• Technology innovation
• Environment, health and safety
Driving Network Investment
Policy catalysts that support investment in anchor gas projects in new
regions are essential. As networks mature, the role of government to drive
investment will change with each stage of network evolution. In mature
networks, market forces have been successful in creating innovation and
investment. However, in many parts of the world, state-sponsored energy
companies will be the key actors driving expansion of the gas industry.
Governments need to explore the way investments in gas infrastructure
and other associated energy networks can help state utilities deliver
improved operations and lower transaction costs. There are strong
indications from North America that successful gas development can foster
economic growth and job creation. In this way, gas network development
is a vehicle for economic development and increasing energy access in
developing economies.
International cooperation is another important catalyst for investment.
Supplies of gas and the location of ultimate gas demand are often not well


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CHAPTER VI.


“Creating durable, yet flexible,
international relationships
that foster investment even
as the industry changes will
be crucial.”

aligned. A significant portion of gas must cross state
borders. There remains significant need for international
cooperation to support expansion of gas networks and
trade across these networks. The ability to find common
ground between buyers and sellers, importer and
exporters will be pivotal in mobilizing new mega-project
investments. As a result, buyers and sellers need to
recognize that security of supply and demand not only
comes from traditional transactional models, but from increasing diversity
and flexibility in the marketplace. Those forces will create contractual
practices that are more often shaped by the competitive dynamics
between natural gas and alternative fuels. Creating durable, yet flexible,
international relationships that foster investment even as the industry
changes will be crucial.
Pricing policies are another fundamental issue pacing gas network
investment in the developing regions of the world. There are numerous
examples of places where an aggressive subsidy policy has driven
rapid growth of inefficient consumption, while placing large burdens
on government budgets. As early discoveries are depleted, insolvent
national utilities are unable to make incremental investments in networks
or resources until shortages become acute—creating further stress on
governments and populations. Subsidy reform for fuel and electricity is
challenging but there are examples of efforts that have been deemed
successful including Brazil, Chile, Turkey, Philippines, Indonesia, and
Kenya.61 Individual countries will have to assess the viability of these
types of policies, and in some cases the benefits may outweigh the costs.
For some countries, the inability to address pricing issues may result in
constricted investments and unsustainable growth.
Examining tax policies that distort competition between fuels is also
important. For example, current policies often tax LNG based on fuel
volume rather than energy content. This increases the effective tax on LNG
by 1.7 times the rate applied to diesel fuel. Unequal taxation distorts the
price spread between fuels and therefore influences the pace of capital
investments in LNG refueling infrastructure—effectively slowing opportunities
to provide consumers with a low-cost, cleaner alternative to diesel fuel.


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Supporting Technology Innovation
Technology innovations have been instrumental in unlocking low cost
natural gas in new regions. From a regulatory and policy perspective,
fostering an environment for innovation is critical. Early support through
tax credits and incentives was instrumental in the US’s unconventional
gas development in the 1990’s. Later, shale gas was supported by price
triggers from competitive markets, the ability to draw on a large pool
of talented oil field service professionals and dense accessible pipeline
networks. With the support system for shale gas in place, operators were
able to focus on acquiring and testing the technology to “crack the code”
of individual shale plays and get rewarded for their innovations. Looking
beyond North America, shale gas resources appear abundant, but each
shale play has unique attributes that must be well understood before gas
can be produced economically. Technology will likely need to be adapted,
and unique innovations, like the ones that unlocked the initial opportunity
in the Barnett shale, will have to be replicated. This is where policy and
incentives can help to find ways to customize technology for new regions.
This does not mean that knowledge from other regions is not transferable
or competitive markets need to be replicated all around to find success.
Instead it is about finding the spaces within large national entities to
allow experimentation, drive pilot projects, and establish appropriate joint
ventures to share risks and transfer technology. The benefit of these efforts
will hopefully be more rapid development of valuable domestic resources,
at lower cost, and with fewer environmental implications.
Regulatory policy can also influence how technology is adopted to
help secure and optimize gas and electrical networks. Natural gas and
electricity markets will become more connected over time as networks
continue to grow and system complexity increases with new supply
and demand options. Supporting Industrial Internet innovations can
help drive coordination between networks—with the goal of helping to
standardize business practices, increase transparency for grid operators
and regulators, and improve analytics to better predict operations and
prepare for contingencies. Achieving the benefits associated with the
deeper penetration of digital technologies will require effective security at
both the network level as well as at the level of cutting-edge devices that
are connected to the network. This will require all stakeholders to become
proactive participants in security management.

75

CHAPTER VI.


Encouraging Safety and Sustainable Development
Natural gas will only be able to reach its potential and win share against
coal and oil if technologies are deployed that can support safe, efficient
and reliable capture or extraction. Complex regulatory frameworks often
govern operations today and policy efforts support
technological innovations that can improve the safety
and security of gas networks, particularly in remote
areas. New practices and technologies will be required
as projects push further into deepwater regions and
into Arctic waters. For unconventional gas operations
there will continue to be a learning process as the
industry grows. Specifically, this means redefining what
is possible in gas operations including: enabling oil
substitution, improved water management, reduction
of fugitive emissions, and other new concepts for
efficiency and electrification.

“Natural gas will only be
able to reach its potential
and win share against coal
and oil if technologies are
deployed that can support
safe, efficient and reliable
capture or extraction.”

Conclusion
Countries and regions that move early to get energy infrastructure
models right are likely to be better positioned for future growth. This may
require adapting to new business models and regulatory frameworks.
Expanding gas networks starts with solid national energy planning with
regional government engagement. Early thinking on cross-leveraging
and transitioning energy systems in a scalable and modular way can
be important. For countries in the network development phase, early
consideration should be given to establishing the role of the regulator,
including how access to networks will be managed and what revenue model
will support investment. This can have large implications in terms of how
systems are managed for open access, cost of services, and transparency.
If scaling up with big blocks of energy is problematic in that it creates
vertical integration, rent seeking, and insular negotiations, the ability instead
to drive development along the distributed pathway might be beneficial.
Tailored solutions will be important. For countries trying to develop new gas
infrastructure, having a solid legal foundation and credibility that supports
direct foreign investment and contracting is important. In most parts of the
world, the ability to efficiently develop effective public-private partnerships

76

CHAPTER VI.


is essential. International companies are often willing to take significant
financial and operational risks to develop resources, build infrastructures,
and link markets if governments can create a stable environment for
business. This is even more important for gas supply projects that have
20 to 30 year investment horizons.
A strong enabling environment for gas network development is built on:
• A clear and durable governmental vision with commitment
• Regulation that is transparent, reasonable and responsive to the
pace of business
• Market structures that support investment
• Public outreach and worker education and training
• Support for innovation
• Attention to environmental externalities
• Building the service eco-systems around the network
Without significant focus on gas network development from a physical
infrastructure and a market development perspective, the industry will not
reach its potential. Traditional energy network revenue models will struggle
to work in much of the emerging market or they will work too slowly. The
need for diversity, scalability, and sustainability makes distributed energy
increasingly attractive. Joining power, gas, and renewables in distributed
settings in optimized networks is likely to bring latent benefits that
traditional isolated business models fail to capture.
A world in which natural gas can take on a much larger role in the global
energy mix is not only possible, but perhaps likely, with the combination
of innovative technology, externality management, and continuing
collaboration. There will continue to be significant regional variation in gas
dynamics around the world. However, the broad points remain. Harnessing
the power of networks and investing in the technologies that enable them,
promises to yield significant benefits. Many elements are coming together
to create the opportunity for a much more significant role for gas on the
world stage, with valuable contributions to national competitiveness,
sustainability and energy system resilience. This is the Age of Gas and the
power of supporting networks.

77

CHAPTER VII.

DATA APPENDIX, ENDNOTES, REFERENCES, ACKNOWLEDGMENTS

VII. DATA APPENDIX,
ENDNOTES, REFERENCES,
ACKNOWLEDGMENTS
Global Fuel Share of Primary Energy Consumption
GE “Age of Gas” Outlook 2013
CAGR
‘90 –’12
Primary Energy MTOE

8,848

10,096

13,292

15,594

16,905

‘12–’25

2.3%

2.1%

Change in Share
Energy Source (%)

‘90

‘00

‘12

‘20

‘25

‘90–’12

‘12–’25

Oil

36%

36%

31%

29%

27%

-4.8%

-4.4%

Gas

20%

22%

23%

26%

26%

3.1%

2.4%

Coal

25%

23%

28%

27%

27%

2.8%

-0.8%

Nuclear

6%

7%

5%

5%

6%

-1.1%

1.5%

Hydro

2%

2%

2%

2%

2%

0.2%

-0.2%

Wind, Solar Other

0%

1%

1%

3%

4%

0.8%

2.6%

Biofuel and Waste

10%

10%

9%

8%

8%

-1%

-1%

100%

100%

100%

100%

100%

Total

Note: These data are based on IEA World Energy Statistics, EIA, BP Statistical Report information, and GE
internal analysis and modeling.


79

CHAPTER VII.


Global Gas Balance
Billion Cubic Meters per Year (BCM)
CAGR
Sector

‘00

‘12

‘15

‘20

‘25

‘00–’12

‘12–’25

Power Gen

880

1,433

1,592

1,887

2,097

5.2%

3.6%

Industrial

724

853

921

1,036

1,111

1.5%

2.3%

Buildings

644

717

774

811

871

0.9%

1.7%

Other

352

515

580

676

728

3.8%

3.2%

Total

2,600

3,518

3,867

4,410

4,807

2.9%

2.8%

2,456

3,003

3.282

3,654

3,952

1.9%

2.4%

144

495

582

793

898

20.3%

6.3%

2,600

3,498

3,865

4,447

4,850

2.9%

3.0%

1

-20

-2

37

43

Demand:

Supply:
Conventional
Unconventional
Total
Imbalance

internal analysis and modeling. Imbalance differences between supply and demand statistics are the result
of variations in stocks at storage facilities and liquefaction plants, together with unavoidable differences in
data, resulting from gas composition and quality isses and other measurement or conversion issues related
to the range sources underlying the supply, demand, and trade data.


80

CHAPTER VII.


Global Power Generation by Fuel Type
TerraWatt Hours per Year (Twh)
CAGR
Fuel Type

‘00

‘12

‘15

‘20

‘25

‘00–’12

‘12–’25

Oil

1,126

1,111

935

779

678

-0.1%

-3.0%

Gas

2,730

5,177

5,784

6,962

8,134

7.5%

4.4%

Coal

5,909

8,931

9,709

10,946

12,988

4.3%

3.5%

Nuclear

2,591

2,443

2,968

3,276

4,097

-0.5%

5.2%

Hydro

2,687

3,491

3,725

3,896

4,150

2.5%

1.5%

Wind, Solar Other

84

654

1,078

1,611

2,588

56.5%

22.8%

Biofuel and Waste

324

526

582

711

1,013

5.2%

7.1%

15,452

22,332

24,781

28,181

33,647

3.7%

3.9%

Total Global Power

internal analysis and modeling. These data include utility and independent power generation including
industrial cogeneration and the electricity sector’s own use. Gas demand for power estimates are based on
the wider definition of the power sector, which may create differences with other sector forecasts.


81

CHAPTER VII.


GE “Age of Gas” Outlook

Billion Cubic Meters per Year (BCM)
Regional Gas Balance Summary
CAGR
Fuel Type

‘00

‘12

‘15

‘20

‘25

‘12–’25

Power Gen

158

282

256

296

312

1%

Industrial

237

214

231

244

249

1%

Other Buildings

359

334

355

383

400

2%

Production

774

858

865

1,030

1,087

2%

5

5

7

-66

-76

Pipeline (Net Trade)

-3

-19

-21

-30

-40

Imbalance

14

5

0

0

0

Power Gen

171

295

364

485

534

6%

Industrial

92

167

191

227

263

4%

Other Buildings

92

208

246

312

357

6%

300

515

623

768

800

4%

LNG (Net Trade)

29

133

123

162

218


-0

27

66

121

157

Imbalance

-30

-51

-29

-29

-30

Power Gen

239

294

323

338

344

1%

95

129

130

135

132

0%

Other Buildings

185

178

184

190

191

1%

Production

687

803

915

1,043

1,136

3%

0

-13

-14

-26

-61

-138

-197

-273

-359

-410

Imbalance

27

-10

-12

-9

-6

Power Gen

145

194

205

236

293

4%

Industrial

163

122

131

141

145

1%

Other Buildings

North America

Sector

207

251

254

257

262

0%

Production

315

281

267

253

236

-1%

33

62

73

107

131

166

204

255

275

331

-3

-23

5

0

-2

LNG (Net Trade)

China,
OECD Asia Pacific,
Other Asia

Production

Industrial

Eurasia

LNG (Net Trade)

Europe

LNG (Net Trade)
Imbalance


82

CHAPTER VII.


CAGR
Fuel Type

‘15

‘20

‘25

‘12–’25

91

201

249

294

329

5%

54

110

117

138

161

4%

Other Buildings

67

142

155

169

190

3%

Production

237

556

640

721

843

4%

LNG (Net Trade)

-26

-123

-128

-116

-126


3

7

9

-2

-35

Imbalance

0

-15

-1

0

0

Power Gen

31

74

90

109

125

5%

Industrial

17

28

33

48

59

9%

Other Buildings

17

30

34

41

49

5%

Production

137

240

285

341

413

6%

LNG (Net Trade)

-37

-64

-78

-93

-113


-34

-46

-50

-43

-60

Imbalance

-0

-3

-1

4

4

Power Gen

44

93

105

130

160

6%

Industrial

65

81

89

103

116

3%

Other Buildings

47

88

93

95

107

2%

151

245

270

291

334

3%

LNG (Net Trade)

0

-3

8

21

19


Latin America

‘12

Industrial

Africa

‘00

Power Gen

Middle East

Sector

7

20

21

28

37

-2

-12

-0

-0

-0

Production

Imbalance


83

CHAPTER VII.


GE “Age of Gas” Outlook
TerraWatt Hours per Year (Twh)
Regional Generation by Fuel Summary
CAGR
Fuel Type

Sector

‘00

‘12

‘15

‘20

4,658

4,706

5,088

5,319

5,563

1%

Oil

128

21

6

4

3

-7%

Gas

668

1,302

1,168

1,313

1,467

1%

Coal

2,240

1,604

1,995

1,940

1,928

2%

Nuclear

871

876

915

963

968

1%

Hydro

639

637

650

651

652

0%

Wind, Solar and Other

21

175

267

341

415

11%

Biofuel and Waste

92

92

86

108

130

3%

4,244

9,092

10,573

12,815

16,757

6%

353

392

286

225

226

-3%

Gas

2,145

5,544

6,003

7,187

9,443

5%

Coal

2,145

5,544

6,003

7.187

9,443

5%

Nuclear

505

394

858

1,064

1,705

26%

Hydro

530

1,234

1,396

1,469

1,611

2%


26

180

372

612

1,067

38%

Biofuel and Waste

99

129

145

198

393

16%

1,246

1,501

1,579

1,684

1,832

2%

Oil

57

43

43

42

41

0%

Gas

484

659

718

753

786

1%

Coal

257

323

315

339

376

1%

Nuclear

210

224

247

282

331

4%

Hydro

227

228

229

232

239

0%

0

2

4

11

25

83%

11

22

22

24

34

4%

3,429

3,794

3,870

4,127

4.495

1%

Oil

183

68

68

60

55

-1%

Gas

527

773

819

898

1,194

4%

Coal

991

1,034

947

964

719

-2%

Nuclear

971

902

904

880

915

0%

Hydro

627

558

568

575

592

0%

29

267

358

504

726

12%

101

193

206

247

294

4%

Total Generation

North America

Total Generation
Oil

China, OECD
Asia Pacific,
Other Asia

Total Generation

Eurasia

Biofuel and Waste
Total Generation

Europe

Biofuel and Waste


‘25 ‘12–’25

84

CHAPTER VII.


CAGR
Fuel Type

‘00

‘12

‘15

‘20

Total Generation

471

1,031

1,195

1,407

1,620

4%

Oil

195

315

275

277

206

-3%

Gas

237

628

819

961

1,123

6%

Coal

29

44

33

32

35

-1%

Nuclear

0

0

0

40

90

Hydro

8

17

19

20

21

2%


0

2

4

29

94

438%

Biofuel and Waste

0

25

46

48

51

8%

435

722

843

991

1,234

5%

Oil

47

74

71

46

46

-3%

Gas

91

233

313

363

357

2%

Coal

207

287

315

363

357

2%

Nuclear

13

12

12

12

38

16%

Hydro

75

101

103

118

157

4%


1

5

18

38

91

133%

Biofuel and Waste

1

9

10

13

22

11%

Total Generation

971

1,485

1,643

1,838

2,145

3%

Oil

163

197

186

126

102

-4%

Gas

Middle East

Sector

137

362

434

576

727

8%

Coal

40

96

102

122

130

3%

Nuclear

20

35

32

35

50

3%

583

716

761

831

878

2%

8

23

53

75

169

49%

20

57

65

72

88

4%

Total Generation

Africa

Latin America

Hydro
Biofuel and Waste


‘25 ‘12–’25

85

CHAPTER VII.


Author Bios
Dr. Peter C. Evans is Director of Global Strategy and Analytics at
General Electric and served for five years as Head of Global Strategy
and Planning at GE Energy. Prior to joining GE, he was Director of Global
Oil, and Research Director of the Global Energy Forum at Cambridge
Energy Research Associates (CERA). He also worked as an independent
consultant for a variety of corporate and government clients, including the
US Department of Energy, the Organization for Economic Co-operation
and Development (OECD), and the World Bank. Dr. Evans has extensive
international energy experience, including two years as a visiting scholar
at the Central Research Institute for the Electric Power Industry in Tokyo,
Japan. His many articles and policy monographs include: “The Industrial
Internet: Pushing the Boundaries of Minds and Machines” (General
Electric, 2012); “Japan: Bracing for an Uncertain Energy Future,” (Brookings
Institution, 2006), and “Liberalizing Global Trade in Energy Services,” (AEI
Press, 2002). He is a lifetime member of the Council on Foreign Relations
and a board member of the National Association for Business Economics.
Dr. Evans holds a bachelor’s degree from Hampshire College and a master’s
and doctoral degree from the Massachusetts Institute of Technology.
Michael F. Farina is Leader of GE’s Fuels Center of Excellence (COE) and
part of GE’s Corporate Strategy and Analytics team. Mr. Farina has been in
the energy industry for almost two decades, primarily focusing on natural
gas and power markets economics, technology, and policy. Prior to joining
GE, he was Director of North America Natural Gas, at Cambridge Energy
Research Associates (CERA). He was contributing author on global natural
gas issues for CERA’s global energy scenario studies “Dawn of a New Age:
The Energy Future to 2030” and “Crossing the Divide: The Future of Clean
Energy.” In 2007, he was awarded CERA’s Danny Award for excellence
in writing and insight for “Is the Relationship Over? Oil and Gas Prices in
North America.” Prior to joining CERA, he served as a senior consultant
with Platt’s/RDI Consulting. Mr. Farina led RDI’s gas forecasting services. He
assisted clients with scenario planning, model development, pipeline and
storage asset valuation, and fuel procurement strategies. Mr. Farina holds
a bachelor’s degree in economics from Colorado State University and a
master’s degree in economics from the University of Colorado.


86

CHAPTER VII.


Acknowledgments
We would like to extend our gratitude to the many contributors to this
paper. We would like to acknowledge, in particular, Brandon Owens,
Markus Becker, Georges Sassine, Michael Leifman, and David Keefer. We
also would like to thank a number of colleagues from GE Oil and Gas, GE
Power and Water, and GE Energy Management for their many unique
insights on technology and the future of the natural gas industry. Lastly,
we would like to offer many thanks to David Victor, Amy Jaffe, and Laszlo
Varro for carefully reviewing the draft text and offering incredibly useful
comments and critique.


87

CHAPTER VII.


Endnotes
1. Peter C. Evans and Marco Annunziata, “Industrial Internet: Pushing the Boundaries of Minds and
Machines,” General Electric, November 26, 2012.
http://www.ge.com/docs/chapters/Industrial_Internet.pdf.
2. Malcolm Peebles, Evolution of the Gas Industry (New York: New York University Press, 1980), 9-17.
3. Arlon Tussing and Bob Tippee, The Natural Gas Industry: Evolution, Structure, and Economics, 2nd edition
(New York: PennWell Books, 1995), 61-65.
4. Ernest Freeberg, The Age of Edison: Electric Light and the Invention of Modern America (New York:
Penguin Press, 2013), 35.
5. James J. Parsons, “The Geography of Natural Gas in the United States,” Economic Geography, vol. 26,
no. 3 (Jul., 1950): 162-178.
6. Jim Watson, “The Technology that Drove the ‘Dash for Gas’,” Power Engineering Journal, vol. 11, (1997).
7. David Newbery, Privatization, Restructuring, and Regulation of Network Utilities (Cambridge: MIT Press,
1999), chap. 8.
8. We use metric measures for gas supply and demand in this paper as it is more consistent with
international reporting. Dividing billion cubic meters per year (BCM) by ten approximates the conversion
to billion cubic feet per day (Bcfd) commonly used in the US gas industry. The generic conversion between
BCM and BCF is 35.31. For example, 100 BCM per year multiplied by 35.31 and divided by 365 days equals
9.67 Bcfd.
9. John Curtis, “Fractured shale-gas systems,” AAPG Bulletin, vol. 86 (November 2002): 1923-1924.
10. The US National Petroleum Council’s Prudent Development study (2011) indicated 1,500, 2,500, and
4,000 trillion cubic feet (Tcf) in their low, mid, and high gas resource estimates, respectively.
11. For past estimates, see International Energy Agency, Natural Gas Prospects to 2000, OECD, Paris 1982,
Table 5.18.
12. The “Age of Gas” outlook is based on a view of future economic growth, energy prices, environmental
policy, and infrastructure development. The outlook assumes a return to the economic growth potential
of the advanced industrial countries and continued stable, relatively strong economic growth in the
developing countries; relatively high oil prices; and ongoing decoupling of gas prices from oil that allows
gas to be increasingly competitive against coal and oil. Environmental policies are significant in some
regions, but this outlook does not, for example, incorporate aggressive carbon policy assumptions.
Instead, we assume a collection of country-specific and regional environmental programs that remain
active through the forecast horizon. New gas infrastructures are assumed to be built in a cost effective
way. Advanced technologies are assumed to be deployed to increase the efficiency and productivity of
the energy, but no hyper-disruptive technologies, for example ultra-low cost solar panels, emerge over
the horizon to 2025. The “Age of Gas” outlook assumes moderate improvements in electricity intensity
of GDP with significant variation on a regional basis. These assumptions determine how much energy is
required to meet the economy’s needs. Energy intensity improvements are assumed to occur at about
1 percent per year through 2025. These rates are a slightly faster improvement than the annual average
improvement over the past 15 years. Some nations like China (1.8 percent) and US (1.5 percent) are
expected to show faster energy intensity improvements. However, for some emerging markets we expect


88

CHAPTER VII.


modest increases in energy intensity to increase over this horizon as access to electricity and electricity
use rapidly increases. Examples include India, Indonesia, and parts of Africa.
13. These resources are more costly, but also will yield more valuable natural gas liquids that can help
offset the decline in the mature oil fields of Russia.
14. Reuters, ”Turkmenistan has High Hopes as Giant Gas Field Nears Output,” May 22, 2013.
15. The “Age of Gas” outlook assumes further growth in nuclear power. While costs are a challenge for
nuclear, the outlook assumes that policy and industry action will align to expand nuclear by approximately
200 GW. Most of this new nuclear capacity will only become available toward the end of the 2025 forecast
horizon. The capacity included in the outlook comes from currently identified nuclear projects and existing
plants. Japanese nuclear capacity is assumed to return to about 60 percent of pre-Fukushima levels.
China is assumed to build about 100 GW of new capacity representing nearly 50 percent of global new
nuclear capacity additions. In addition, France and the US are assumed to keep most of their existing
nuclear capacity online through this time period. Other regions balance out the nuclear growth outlook.
India adds about 18 GW; Saudi, UAE, and Turkey add about 15 GW; S Korea adds about 14 GW; ASEAN
countries add about 5.5 GW; Russia and other eastern European countries add about 11.5 GW. To the
extent that these nuclear projects are unable to advance as projected, there will be additional potential for
natural gas in power generation along with coal and renewables. Shifting any of these assumptions in a
meaningful way would clearly lead to different outcomes.
16. Peter C. Evans and Peter Fox-Penner, “Resilient and Sustainable Infrastructure for Urban Energy
Systems,” The Solutions Journal (forthcoming).
17. The high upfront capital costs of coal also make plants difficult to displace once they are built. This is
because the variable costs of the fuel are typically lower. Furthermore, with large state-owned entities as
the primary builders of coal-fired power in many parts of the world, access to low-cost capital relative to
independent developers drives utilities to more capital-intensive technologies.
18. David Easley and Jon Kleinberg, Networks, Crowds, and Markets: Reasoning about a Highly Connected
World, Cornell University, Cambridge University Press (2010); www.cs.cornell.edu/home/kleinber/
networks-book/networks-book.pdf.
19. Jeff D. Markholm, “The Political Economy of Pipelines,” 2012, University of Chicago Press. See Markholm
for a detailed and fascinating discussion of the economics of pipelines including issues on institutional
drivers, asset specificity, and the development of competitive markets of gas transportation services.
20. Other transportation modes might be considered such as gas to oil liquids (GTL), or gas to chemicals
or fertilizers. Gas could be converted to power and transported by wire. While these gas conversion
pathways are effectively gas transportation modes, they are also gas uses; to simplify the discussion we
use the three primary modes: pipeline, LNG, and CNG.
21. Jean Michel Glachant and Michelle Hallack, “The Gas Transportation System as a LEGO Game: How to
Play with It?” EUI working papers, Robert Shuman Center for Advanced Studies, Loyola de Palacio Program
on Energy Policy, 2010.
22. D. B. Lewis, “Natural Gas for Freight Transportation” (presentation at the National Association for
Business Economics Industry Conference, Houston, TX, May 16, 2013).
23. For this discussion of supply costs, tight sands gas sources are included as part of conventional gas
resources. There is considerable overlap between conventional and tight sands developments as both


89

CHAPTER VII.


tend to use hydraulic fracturing to some degree.
24. Shell Oil and Gas is pioneering the development of large floating LNG at its prelude development in
offshore Australia. They are trying to standardize the technology for replications for other medium-sized
offshore gas fields. Other developers are also working on various types of simpler and modular floating
LNG designs.
25. Leonardo Maugeri, “The Shale Oil Boom: A U.S. Phenomenon,” (Harvard Kennedy School, Belfer Center
for Science and International Affairs) June 2013. This report has an in-depth discussion on North American
shale and upstream production dynamics. The concept of drilling intensity and the implications for the
elasticity of gas and oil supply explain how unconventional gas development differs from conventional gas
development.
26. Massoud Amin,“Toward Self-healing Energy Infrastructure Systems,” IEEE Computer Applications in
Power, 2001.
27. Combined cycle refers to the combination of two gas combustion turbines and one steam turbine
operated in sequence in which the exhaust heat from the gas turbines heats the steam that drives the
generators of the steam turbine. GE’s FlexEfficiency combined-cycle plant can deliver 61 percent thermal
efficiency. See www.ge-flexibility.com for more information on the GE combined-cycle portfolio.
28. Source: US Energy Administration Agency. Assumes average US household electricity consumption of
11,040 kilowatt hours per year or 1.259 kilowatts per home based on 8,765 hours per year.
29. For more on combined heat and power (CHP) systems see Center for Climate and Energy Solutions
(C2ES), “Leveraging Natural Gas to Reduce Greenhouse Gas Emissions,” Technology Survey, June 2013,
pp. 59-60.
30. The dollar per kilowatt capital costs are based on indicative North American costs. Actual project costs
can be significantly different depending on regional conditions. These costs are indicative to show the
general relationship between the technologies.
31. David Victor, Amy Myers Jaffe, Mark Hayes, “Natural Gas and Geopolitics 1970-2040,” Cambridge
University Press (2006) p. 322. David Victor and Amy Myers Jaffe et al. categorize the role of the state in gas
markets into two “worlds.” In the “old world,” the state controls production, pricing, and terms of trade,
which are dictated by state-to-state negotiations. The alternative is the “new world,” where the state
creates the institutional structure for private companies to take risks and capture value. However, the
point is made that there is no pure example on either end of the spectrum as governmental oversight and
market forces are always present.
32. The term “anchor” shipper is used quite often in the gas industry to describe the key customer that has
committed to the project through long-term contracts.
33. Gas systems have a high degree of asset specialization (for example gas pipelines only move gas) and
high costs. This means that producers or consumers at either end of the pipe are beholden to each other.
As noted by Markholm in “The Political Economy of Pipelines” p.159, and others, this drives buyers and
sellers toward vertically integrated structures. There are several studies on the level of vertical integration
in the LNG industry. A good summary of recent research is in SECURE, “Vertical Integration in Natural Gas,”
Project 213744, 2009. Accessed at http://www.feemproject.net/secure/plastore/Deliverables/SECURE_D52-5.pdf
34. Examples include China’s Sinopec that in 2011 initiated a 20-year annual purchase of 4.3 million metric


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tons of (MTPA) LNG from the first train of the Australia Pacific LNG (APLNG) project along with a 15 percent
stake in upstream operations. Later in 2012, Sinopec bought another 3.3 MTPA of LNG and increased its
upstream operating stake to 25 percent of the LNG plant. Source: Gastech News and Resource Center
“Legendary Growth of an LNG Giant,” January 2013. Accessed at http://www.gastechnews.com/lng/
legendary-growth-of-an-lng-giant-2/
35. One example “Gas Exporters Defend Oil Link,” Platts’ International Gas Report, Issue 728, July 15, 2013.
36. Competitive gas markets are an alternative model to vertically integrated project structures. North
America is the primary example. Private companies engage in a bidding process to develop projects.
“Open seasons” are held to identify shipper interest, hopefully culminating in a group of “anchor”
customers that sanction the pipeline, storage, processing plant, or LNG terminal. Gas supply is then
purchased separately and transported, stored, or converted through the asset on a contractual basis.
Price signals play a major role in driving investment and create efficient gas flows to end-users. While
efficient in allocating capital and mobilizing investments, competitive markets are subject to price volatility,
gaming, and “boom and bust” cycles. As a result, even in competitive gas markets there is often a high
level of government oversight.
37. Platts’ International Gas Report, “Mexico’s Impact on SW US,” June 17, 2013. Canadian company
TransCanada has a 25-year contract from CFE to build the Mazatlan and Topolobampo pipelines; US-based
Sempra Energy also has a contract to build part of the Northwest pipeline system.
38. GE Distributed Power marketing analysis, 2012.
39. Ahram Online, “Construction of 3 New Power Plants Across Egypt Delayed by Strikes,” February 2013.
40. Hussam Beides, Hossien Razavi, Venkataraman Krishnaswamy, “Regional Gas Trade Projects in Arab
Countries,” Report No. 76114-MEN, World Bank-PPIAF, February 2013.
41. Thura Swiss Research, “Electricity Myanmar,” April 2012.
42. David Dapice, “Electricity Demand and Supply in Myanmar,” December 2012. Rajawali Foundation
Institute for Asia, Harvard Ash Center for Democratic Governance and Innovation.
43. Id. David Dapice (2012). Current onshore domestic capacity is estimated at around 70 MMcf per day.
The pipeline from Yadana gas field to Yangon is being expanded from 150 to 200 MMcf per day in 2014.
Upgrading of the southeast pipeline now flowing about 30 MMcfd could bring an additional 150 MMcf per
day into the domestic market. In addition, almost 100 MMcf per day from the new Shwe pipeline to China
is expected to serve generation or industry close to the pipeline route.
44. Michael F. Farina, “GE Flare Gas Reduction,” January 2011. See for a detailed discussion of the
gas flaring issue and technology solutions available at GE reports. http://www.genewscenter.com/
ImageLibrary/detail.aspx?MediaDetailsID=3691.
45. Source: World Bank GGFR site. http://go.worldbank.org/G2OAW2DKZ0
46. World Bank, “World Bank Urges Oil Producers to Reduce Gas Flaring, Increase Gas Utilization for
Development,” press release, October 24, 2012.
47. There is substantial literature on pipeline and gas system optimization and gas and power system
optimization in the context of cogeneration and district heating. Literature review finds less discussion
of these concepts at a strategic level. One example is the complex discussions on regulatory and market
design concerning NERC gas and power market cooperation efforts.
48. See IEA “Are We Entering a Golden Age of Gas?” for concerns about gas replacing renewables. See


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CHAPTER VII.


Citigroup Equities Research, “Shale Renewables: a Symbiotic Relationship,” September 2012 for a
detailed discussion on the economics of gas versus renewables.
49. Renewable energy sources, like wind and solar, are continuing to grow. The costs of renewables are
falling with expectations that this trend will continue. Wind costs could decline by another 20 percent over
the next decade and photovoltaic (PV) solar costs could fall by 40 percent. The increasing competitiveness
of renewables relative to fossil fuels, (even without policy drivers) will increase in the future. Today,
renewables only account for about 1 percent of global primary energy supply, but about 5 percent of
electricity generation. In this outlook, renewables will grow to 4 percent of primary energy and 11 percent
of electricity generation by 2025, assuming modest policy support.
50. A detailed exploration of these issues is beyond the scope of this report, but the core issues are:
How much load variation? What resources are available at peak? Is there operational impact (voltage,
frequency, pressure)? How big is the pool of resources available to balance the system safely? Many of
these questions are related to how the renewable system will be deployed and how easy is it to expand
the gas and power network in a particular region.
51. Energy storage costs like pump hydro-storage can cost as much as $35 Mwh with significant capital
outlay to develop.
52. North American Electric Reliability Council (NERC), “2013 Special Reliability Assessment:
Accommodating an Increased Dependence on Natural Gas for Electric Power Phase II: A Vulnerability and
Scenario Assessment for the North American Bulk Power System,” May 2013.
53. Id. NERC.
54. Morgan Stanley Global Research, “Natural Gas as a Transportation Fuel: Energy Market Wild Card,” April
2013. Accessed at http://wacleantech.org/wp-content/uploads/2011/07/Natural-Gas-in-TransportationMS-Blue-Paper-4.16.13.pdf
55. Id. L Maugeri, “The Shale Oil Boom.” This report discusses the marginal costs of new oil supplies,
including light tight oil from shales, indicating support for long-run marginal full-cycle costs in the $70 to
$90 per barrel range.
56. Robert LaCount, M.J. Bradley Associates, “Natural Gas and the US Transport Sector,” presentation at
the National Association of Business Economics, Energy Industry Conference, Houston, TX, May 2013.
57. Id. Morgan Stanley, “Natural Gas as a Transportation Fuel.”
58. U.S. National Petroleum Council (NPC), “Future of Transport Fuels,” August 2012.
59. Id. NPC, “Future of Transport Fuels.”
60. International Energy Agency (IEA), “Redrawing the Energy-Climate Map,” July 2013. Accessed at http://
www.iea.org/publications/freepublications/publication/name,38764,en.html
61. International Monetary Fund (IMF), “Case Studies on Energy Subsidy Reform: Lessons and Implications,”
January 2013. Accessed at http://www.imf.org/external/np/pp/eng/2013/012813a.pdf


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GE Report: The Age of Gas & The Power of Networks

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