Role of Stranded Gas in Increasing Global Gas Supplies

By Emil D. Attanasi and Philip A. Freeman

Open-File Report 2013–1044

U.S. Department of the Interior

U.S. Geological Survey
U.S. Department of the Interior

SALLY JEWELL, Secretary

U.S. Geological Survey

Suzette M. Kimball, Acting Director

U.S. Geological Survey, Reston, Virginia: 2013

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Attanasi, E.D., and Freeman, P.A., 2013, Role of stranded gas in increasing global gas supplies: U.S. Geological Survey 

Open-File Report 2013–1044, 57 p., http://pubs.usgs.gov/of/2013/1044. (Available only online.)
iii

Contents

Abstract...........................................................................................................................................................1

Introduction.....................................................................................................................................................1

Estimates of Stranded Gas outside North America .................................................................................2

Recoverable Gas in Stranded Gas Fields .........................................................................................3

Recoverable Stranded Gas in Oil Fields............................................................................................6

Structure of Global Natural Gas Markets................................................................................................15

Trade Patterns .....................................................................................................................................15

Transportation and Infrastructure....................................................................................................15

International Pipelines..............................................................................................................15

Terminals Receiving Liquefied Natural Gas ..........................................................................19

Price Formation in Global Markets ..................................................................................................19

Potential Growth in Europe’s Demand for Imported Gas .............................................................25

Potential Growth of Demand for Imported Gas in Japan, China, South Korea, and 

India.........................................................................................................................................25

Potential Additions to Supply from Development of Stranded Gas.....................................................27

Economic Cost Calculations and Assumptions .............................................................................27

Resources Evaluated for Europe’s Markets ...................................................................................27

Resources Evaluated for Asia’s Markets........................................................................................29

Landed Costs of Stranded Gas for Europe’s Markets............................................................................30

Gas from the Atlantic Basin and North Africa ...............................................................................30

Gas from Russia and Central Asia ...................................................................................................33

Implications for Meeting Europe’s Future Demand for Imported Gas .......................................36

Landed Costs of Stranded Gas for Asia’s Markets.................................................................................36

Gas from Russia and Central Asia ...................................................................................................36

Liquefied Natural Gas from Southeast Asia, Australia, and Russia...........................................37

Implications for Meeting Asia’s Future Demand for Imported Gas............................................41

Conclusions and Implications....................................................................................................................41

Acknowledgments.......................................................................................................................................42

References Cited..........................................................................................................................................42

Appendix 1. Stranded Gas Resources in the Middle East.................................................................47

Distribution of Stranded Gas Resources ........................................................................................47

Prospects for Expanded Gas Exports..............................................................................................47

Appendix 2. Field Development, Production, and Transportation Cost Estimates.........................51

Onshore Field Cost Estimation..........................................................................................................51

Offshore Field Cost Estimation..........................................................................................................51

Transportation of Gas to Market ......................................................................................................51

Appendix 3. Estimation of Liquefaction Cost and the Transportation Costs of Liquefied 

Natural Gas......................................................................................................................................53

Liquefaction Plant Complex ..............................................................................................................53

Shipping Costs for Liquefied Natural Gas.......................................................................................53

Existing and Potential Capacity for Liquefied Natural Gas Production .....................................53

Appendix 4. Countries in Each Region..................................................................................................57
iv

Figures

1. Bar graph showing volumes of remaining stranded gas in gas fields by region and

by whether the field is onshore or offshore .............................................................................3

2. Map showing LNG liquefaction plants, a collection location, trans-Mediterranean

pipeline inlets, clusters of stranded gas fields, and U.S. Geological Survey

petroleum provinces in north Africa..........................................................................................7

3. Map showing an LNG liquefaction plant, a collection location, clusters of stranded

gas fields, and U.S. Geological Survey petroleum provinces in Nigeria.............................8

4. Map showing U.S. Geological Survey petroleum provinces with clusters of 

stranded gas fields in central Asia and western Russia that were analyzed for 

delivery to markets in Europe .....................................................................................................9

5. Map showing selected U.S. Geological Survey petroleum provinces in

eastern Russia and central Asia with clusters of stranded gas fields analyzed for 

delivery to markets in Asia........................................................................................................10

6. Map showing LNG liquefaction plants, clusters of stranded gas fields, and 

U.S. Geological Survey petroleum provinces in Indonesia, Malaysia, and Brunei in 

Southeast Asia ............................................................................................................................11

7. Map showing LNG liquefaction plants, clusters of stranded gas fields, and 

U.S. Geological Survey petroleum provinces in Australia...................................................12

8. Map showing LNG liquefaction plants, LNG regasification terminals, clusters 

of stranded gas fields, and U.S. Geological Survey petroleum provinces in the 

Middle East..................................................................................................................................13

9. Map showing the approximate location and routes of gas pipelines from Africa 

to Europe ......................................................................................................................................17

10. Map showing clusters of stranded gas fields and approximate locations of 

existing and proposed pipelines for delivery to transshipment points en route to 

Europe...........................................................................................................................................20

11. Map showing clusters of stranded gas fields and a schematic of approximate

location of existing and proposed pipelines for delivery to China and Vladivostok,

Russia ...........................................................................................................................................21

12. Graph showing estimated costs by region of developing, producing, and

transporting stranded gas destined for Europe’s markets to coastal transshipment

locations.......................................................................................................................................30

13. Graphs showing estimated costs by region of developing, producing, and 

transporting stranded gas destined for Europe’s markets to the market point 

at the European Union border at Uzhhorod, Ukraine............................................................34

14. Graph showing estimated costs of developing, producing, and transporting

stranded gas to Shanghai, China, from the West Siberian Basin, eastern Siberia,

and central Asia (Turkmenistan, Uzbekistan, and Kazakhstan)..........................................37

15. Graph showing estimated costs by region of developing, producing, and

transporting stranded gas to coastal LNG plant locations..................................................38
v

Tables

1. Volumes of remaining recoverable stranded and other natural gas onshore and

offshore in oil and gas fields by region outside North America ...........................................4

2. Distribution of gas by field size category for onshore and offshore stranded gas

fields by regions............................................................................................................................5

3. Volumes of stranded gas in oil fields having at least 1 TCF in original recoverable

gas by region outside North America .....................................................................................14

4. Volumes of gas in billions of cubic feet (BCF) marketed in North America, Europe,

and Asia from 2008 through 2011 .............................................................................................16

5. Pipeline capacity to transport gas to Europe.........................................................................18

6. Pipeline capacity to transport gas to China and Singapore................................................22

7. Location and capacity of terminals receiving liquefied natural gas (LNG) in 

Europe...........................................................................................................................................23

8. Location and capacity of liquefied natural gas (LNG) regasification terminals in 

Asia ...............................................................................................................................................24

9. Two demand scenarios for net natural gas imports by country showing 

historical imports and projections into the future for Japan, South Korea, China, 

and India.......................................................................................................................................26

10. Stranded gas resources evaluated for European and Asian markets ..............................28

11. Estimated cost by country in north Africa and the Atlantic Basin for developing,

producing, and transporting stranded gas destined for Europe’s markets to coastal

transshipment locations ............................................................................................................31

12. Estimated cost of liquefying and transporting natural gas as LNG from the source

country to the destination regasification facility if the process gas cost were $3.00

per thousand cubic feet.............................................................................................................32

13. Estimated cost of developing, producing, and transporting gas from stranded gas

fields in Russia by petroleum province or producing area to the border of the

European Union at Uzhhorod, Ukraine....................................................................................33

14. Estimated cost of developing, producing, and transporting gas from stranded gas

fields in central Asia by country to the border of the European Union at Uzhhorod,

Ukraine .........................................................................................................................................36

15. Delivered threshold prices of the first tranche of gas as liquefied natural gas (LNG)

from stranded gas fields in Australia, Malaysia, Indonesia, and Russia to four Asian

markets.........................................................................................................................................39

16. Estimated cost of developing, producing, and transporting gas to various operating

and planned LNG complexes....................................................................................................40

A1–1. Volumes of remaining recoverable stranded natural gas onshore and offshore in

Middle East oil and gas fields by country...............................................................................48

A1–2. Distribution of gas by field size category for stranded gas in gas fields in Iran, Iraq,

Saudi Arabia, the United Arab Emirates, Oman, and Yemen...............................................49

A2–1. Prototype model designs for onshore gas field development ............................................52

A2–2. Prototype model designs for offshore gas field development ............................................52

A3–1. Estimated costs of transporting liquefied natural gas (LNG) from LNG complex to

destination regasification facility and market .......................................................................54
vi

A3–2. Existing LNG capacity outside North America ......................................................................55

A3–3. LNG capacity under construction accessible to Asian importers from Southeast

Asia and Oceania........................................................................................................................56

A4–1. List of countries reporting stranded gas in gas fields by regions as used in figure 1

and tables 1, 2, 3, and 4..............................................................................................................57

Conversion Factors

Multiply By To obtain

Length

foot (ft) 0.3048 meter (m)

mile (mi) 1.609 kilometer (km)

mile, nautical (nmi) 1.852 kilometer (km)

Volume

barrel (bbl), (petroleum, 

1 barrel=42 gallons)

0.1590 cubic meter (m3

) 

cubic foot (ft3

) 0.02832 cubic meter (m3) 

cubic meter (m3

) 35.31 cubic foot (ft3)

Velocity

knot 1.852 kilometers per hour (km/h)

knot 0.5144 meter per second (m/s) 

Energy

British thermal unit (Btu) 1.055 kilojoule (kJ)
vii

Unit Abbreviations

$/MCF dollars per thousand cubic feet in constant 2008 U.S. dollars 

$/MMBtu dollars per million British thermal units in constant 2008 U.S. dollars 

BCF billions of cubic feet

BCF/D billions of cubic feet per day

Btu British thermal unit

ft feet

MCF thousands of cubic feet

mi mile

MMBtu millions of British thermal units

MMCF/D millions of cubic feet per day

MT megaton or millions of metric tons

MTY millions of metric tons per year

nmi nautical mile

TCF trillions of cubic feet

TCF/Y trillions of cubic feet per year

USD/t U.S. dollars per metric ton

Acronyms

CNPC China National Petroleum Corporation

EIA U.S. Energy Information Administration

GIS geographic information system

ICE IntercontinentalExchange, Inc.

IEA International Energy AJHQF\

IGU International Gas Union

LNG	 liquefied natural gas

NBP National Balancing Point

NGL natural gas liquids

NOC national oil company

OPEC Organization of the Petroleum Exporting Countries

TEPCO Tokyo Electric Power Company

UAE United Arab Emirates

UK United Kingdom

USGS U.S. Geological Survey

Role of Stranded Gas in Increasing Global Gas Supplies

By Emil D. Attanasi and Philip A. Freeman

Abstract 

This report synthesizes the findings of three regional studies in order to evaluate, at the global scale, the contribution that

stranded gas resources can make to global natural gas supplies. Stranded gas, as defined for this study, is natural gas in discovered conventional gas and oil fields that is currently not commercially producible for either physical or economic reasons. The

regional studies evaluated the cost of bringing the large volumes of undeveloped gas in stranded gas fields to selected markets.

In particular, stranded gas fields of selected Atlantic Basin countries, north Africa, Russia, and central Asia are screened to

determine whether the volumes are sufficient to meet Europe’s increasing demand for gas imports. Stranded gas fields in Russia,

central Asia, Southeast Asia, and Australia are also screened to estimate development, production, and transport costs and corresponding gas volumes that could be supplied to Asian markets in China, India, Japan, and South Korea. 

The data and cost analysis presented here suggest that for the European market and the markets examined in Asia, the 

development of stranded gas provides a way to meet projected gas import demands for the 2020-to-2040 period. Although this 

is a reconnaissance-type appraisal, it is based on volumes of gas that are associated with individual identified fields. Individual

field data were carefully examined. Some fields were not evaluated because current technology was insufficient or it appeared

the gas was likely to be held off the export market. Most of the evaluated stranded gas can be produced and delivered to markets at costs comparable to historical prices. Moreover, the associated volumes of gas are sufficient to provide an interim supply

while additional technologies are developed to unlock gas diffused in shale and hydrates or while countries transition to making 

a greater use of renewable energy sources.

Introduction

Recent studies (Massachusetts Institute of Technology, 2011; U.S. Energy Information Administration (EIA), 2011b) predict a bright future for the expansion of global natural gas supplies for the 25-year period starting with 2011 as a result of new 

technology used to extract gas in unconventional settings. In a recent article in Foreign Affairs, Deutch (2011), former director 

of the United States Central Intelligence Agency, outlined far-reaching domestic and foreign policy implications of the anticipated expansion of gas supplies. Over a long term, natural gas can be substituted for oil in some transportation uses. If global 

natural gas prices decline or if carbon emissions are constrained, gas-fired electrical power generation plants will likely replace

coal- and oil-fired facilities.

Natural gas from unconventional sources was postulated to provide additional energy security benefits by weakening the

Organization of the Petroleum Exporting Countries (OPEC), as natural gas can gradually be substituted for oil use either directly 

or with the conversion to vehicles powered by electricity (Deutch, 2011). The new supplies also reduce chances of a successful attempt to form a gas cartel based on the very uneven distribution of conventional natural gas resources. Deutch (2011) also 

articulated a vision of an integrated global gas market leading to the improved efficiency of all energy markets. Finally, the

global benefits of replacing coal with natural gas in electrical power generation would be immense because traditional coal-fired

electricity generation plants emit twice as much carbon dioxide as modern gas-fired plants when compared on a per-kilowatthour basis. Deutch (2011) argued that unconventional gas development could provide a reasonable transition to a future era of 

greater use of renewable resources that would bring meaningful reductions in carbon emissions.

This report synthesizes the findings of three regional studies (Attanasi and Freeman, 2011, 2012a,b) in order to evaluate, at

the global scale, the contribution that stranded gas resources can make to global natural gas supplies. Stranded gas, as defined

for this study, is natural gas in discovered conventional gas and oil fields that is currently not commercially producible for either

physical or economic reasons. The regional studies evaluated the cost of bringing the large volumes of undeveloped gas in 

stranded gas fields to selected markets, and this study considers the global role that stranded gas might have in bridging the gap
2 Role of Stranded Gas in Increasing Global Gas Supplies

to increased reliance on production of unconventional gas resources, such as shale gas, gas in tight formations, coalbed methane 

(coal-seam gas), and gas from hydrates. 

First,	the	geographical	and	size	distribution	of	stranded	gas	fields	is	examined.	The	volumes	of	stranded	gas	in	oil	fields	are	

also described and discussed, conditions for the development of this gas are enumerated, and commercial valuation is considered. Natural gas is sold into three regional gas markets: North America, Europe, and Asia. Earlier studies examined the future 

demand for the regional markets of Europe (Attanasi and Freeman, 2011, 2012a) and selected markets in Asia (Attanasi and 

Freeman, 2012b) and the potential contribution that stranded gas could make to supplies of these regional markets. A summary 

of	these	findings	is	presented	in	this	global	synthesis.	The	concluding	section	discusses	the	role	that	stranded	gas	resources	

might have in the transition to greater dependence on unconventional gas resources and renewable resources.

Estimates of Stranded Gas outside North America 

Published natural gas reserves as of the beginning of 2008 for the world were estimated at 6,230 trillion cubic feet (TCF) 

(BP, 2012). This represents almost 55 years of global gas consumption at the current rates. This estimate is, however, not 

adequate for planning purposes because no internationally accepted standards were followed in the compilation of these reserve 

data.	In	the	United	States	and	Canada,	volumes	of	gas	identified	as	proved	reserves	are	defined	very	narrowly	because	these	

estimates are used in the declaration of assets for publicly traded companies and as collateral for commercial loans. U.S. and 

Canadian	estimates	of	proved	reserves	are	entirely	based	on	data	from	individual	producing	reservoirs	and	fields.1 For reserve 

estimates	to	be	verifiable,	the	data	should	be	tied	to	individual	fields.	

The stranded gas studies used the IHS International Petroleum Exploration and Production database (IHS Inc., 2009) as the 

basis	for	estimates	of	discovered	resources	at	the	field	and	reservoir	level.	Documentation	states	that	IHS	estimates	of	recoverable	field	volumes	should	be	associated	with	a	probability	level	of	0.50,	or,	for	short,	p50	(Timothy	R.	Klett,	U.S.	Geological	

Survey, oral commun.).2 An estimate is said to be at the p50 level when the actual volume has a 50-percent chance of being less 

than the estimate and a 50-percent chance of exceeding the estimate. The stranded gas studies discussed above presented cost 

estimates of gas from conventional gas	fields3 that could contribute to international gas supplies. Fields having estimates of 

original recoverable gas of less than 48 billion cubic feet (BCF) were excluded from this analysis because it was assumed that, 

in	most	cases,	these	fields	were	too	small	to	be	commercial	targets	for	gas	exports.	Although	in	some	instances,	small	fields	may	

be commercially developed for local markets, in most cases, their production and transportation costs exceeded export market 

prices	examined.	Fields	were	classified	into	oil	and	gas	fields	on	the	basis	of	the	ratio	of	estimated	recoverable	gas	to	estimated	

recoverable crude oil.4	Gas	fields	were	initially	classified	as	“producing	-	not	stranded”	if	at	least	5	percent	of	the	estimated	

recoverable	gas	had	been	produced.	The	fields	that	remained	were	individually	scrutinized	to	determine	their	status.	Fields	were	

classified	as	“producing”	if	reported	production	was	consistent	with	early	stages	of	commercial	production.	Remaining	gas	fields

not	classified	as	“producing”	were	subsequently	considered	stranded.

Several	very	large	fields	having	only	minimal	development	are	considered	stranded.	These	fields	include	Yoloten-Osman	

(Turkmenistan),	Shah	Deniz	(Azerbaijan),	Russkoye	Yuzhnoye	(Russia),	and	Bovanenkovskoye	(Russia).	In	2011,	the	recoverable	gas	estimate	of	the	Yoloten-Osman	field	was	increased	to	between	460	and	750	TCF	(Gurt,	2011)	after	completion	of	this	

analysis. This is substantially greater than the IHS estimate (which was slightly less than 200 TCF) used in this analysis.

Gas	volumes	in	oil	fields	were	not	stranded	if	the	oil	field	was	producing	and	at	least	5	percent	of	the	recoverable	gas	had	

been	produced.	The	remaining	gas	in	the	oil	field	was	considered	stranded	and	potentially	recoverable	at	a	future	time	if	not	

meeting	these	criteria.	Some	gas	in	oil	fields	may	be	re-injected	to	maintain	oil	field	pressure	to	extend	the	field’s	production	life	

and	may	not	be	reported	as	produced.	Stranded	gas	in	oil	fields	was	treated	differently	than	gas	in	gas	fields.	Even	if	this	gas	is	

re-injected,	the	gas	may	not	be	marketed	for	an	indefinite	period	of	time	into	the	future.	

1

In particular, proved reserves are tied to individual proved reservoirs, which are proved by production, production tests, or core or log data to assure 

producibility. Areas of reservoirs can only be considered proved if they are delineated by drilling or if they adjoin proved areas where engineering and geologic 

data support an inference of producibility (U.S. Energy Information Administration, 2009c). 

2

Although IHS estimates are stated to be p50, no other information about their probability distribution is provided, and so the aggregation of the estimates was 

performed arithmetically.

3

A	conventional	field	is	a	discrete	accumulation	or	set	of	accumulations	that	are	bounded	by	a	downdip	water	contact	(U.S.	Geological	Survey	World	Energy	

Assessment	Team,	2000);	hydrocarbons	in	liquid	or	gaseous	forms	are	extracted	from	the	field.

4

A	field	is	classified	as	a	gas	field	if	its	gas-to-oil	ratio	is	at	least	20,000	cubic	feet	of	gas	to	1	barrel	of	oil	(U.S.	Geological	Survey	World	Energy	Assessment	

Team, 2000).
Estimates of Stranded Gas outside North America 3

Recoverable Gas in Stranded Gas Fields

Table 15 shows that for the world outside North America, the estimated stranded gas in gas fields totals 2,612 TCF, while

remaining gas in producing gas fields is 2,854 TCF. Figure 1 shows the stranded gas data as a bar chart that delineates onshore

and offshore resource volumes in gas fields. The leading regions for stranded gas in gas fields are Russia with 33 percent; Southeast Asia and Oceania, 17 percent; the Middle East, 12 percent; and central Asia, 12 percent. Overall, about 60 percent of the

2,612 TCF is in onshore stranded gas fields, and the remainder is offshore. However, 87 percent of the stranded gas of Southeast

Asia and Oceania is offshore, and for Europe, 70 percent of the gas in stranded fields is offshore. Stranded gas volumes reflect

the degree an area has been explored, the gas endowment, and the maturity of the area’s transportation infrastructure.

Table 2 shows the field size distributions of the stranded gas fields by regions, including the Middle East. Field size

distributions for Europe, south Asia, and east Asia are not shown because these regions are all major importers of gas, and so 

their stranded gas will not be exported outside of their regions. More detailed descriptions of the stranded gas field size distributions by country for the major supply regions outside the Middle East are presented in Attanasi and Freeman (2010, 2012a,b). 

Appendix 1 discusses the gas in the stranded gas fields of the Middle East, and its table A1–2 provides the stranded gas field

size distributions for those countries in the Middle East with at least 10 TCF in stranded gas. In table 2, the columns show the 

number of fields in each size class, the cumulative percentage of fields starting from the largest to the smallest size fields, the

volume of gas contained in each size class, and the cumulative percentage of the total region’s gas volume from the largest to the

smallest size fields. In most regions, gas is unevenly distributed by size category. Field sizes are important because, to a degree,

gas extraction exhibits technical economies of scale; unit extraction costs are inversely related to field size. For this study, a field

with at least 6 TCF of recoverable gas is significant in size (~1 billion barrels of oil). Data in table 2 show by region the share of

gas in significant gas fields. For Africa, it is 4.7 percent; Southeast Asia and Oceania, 34 percent; South America, 38 percent; the

Middle East, 54 percent; central Asia, 81 percent; and Russia, 82 percent.

Figure 1. Bar graph showing volumes of remaining stranded gas in gas fields by region and by whether the field 

is onshore or offshore. Volumes plotted here are in table 1. Field data through the end of 2008 are from IHS Inc. 

(2009). Countries are listed by region in appendix 4 in table A4–1.

5

South America includes stranded gas in fields in the Caribbean and Central America except Mexico; south Asia is Afghanistan, Bangladesh, India, and 

Pakistan; east Asia is China, Japan, South Korea, and Taiwan; central Asia is Azerbaijan, Georgia, Kazakhstan, Kyrgyzstan, Tajikistan, Turkmenistan, and 

Uzbekistan; Southeast Asia and Oceania are Australia, Brunei, Burma, Cambodia, Indonesia, Malaysia, New Caledonia, New Zealand, Papua New Guinea, 

Philippines, Thailand, and Vietnam. Please see table A4–1 in appendix 4 for a country listing for Europe, South America, the Middle East, and Africa. Russia

is discussed separately from regional groups for Europe and Asia.
4 Role of Stranded Gas in Increasing Global Gas Supplies

Table 1. Volumes of remaining recoverable stranded and other natural gas onshore and offshore in oil and gas fields by region outside North 

America.

[Gas volumes are in trillions of cubic feet (TCF). Countries are listed by region in appendix 4 in table A4–1. Field data through the end of 2008 are from IHS

Inc. (2009). Numbers may not add up due to rounding]

Onshore or offshore 

environment

Gas in gas fields Gas in oil fields

Stranded Other Total Stranded Other Total

South America

Onshore 77 47 124 20 104 125

Offshore 67 11 78 35 7 42

 South America total 145 57 202 55 112 167

Europe

Onshore 36 37 73 6 7 13

Offshore 83 99 182 13 15 29

 Europe total 119 136 255 20 23 42

Middle East

Onshore 202 85 287 486 326 812

Offshore 102 1,482 1,584 98 105 203

 Middle East total 304 1,567 1,872 584 431 1,015

Africa

Onshore 114 93 207 47 77 124

Offshore 104 22 127 53 30 83

 Africa total 219 115 334 100 107 207

South Asia

Onshore 21 38 59 1 4 5

Offshore 36 4 40 1 4 6

 South Asia total 57 42 98 3 8 11

East Asia

Onshore 156 9 165 18 6 24

Offshore 15 3 18 8 1 8

 East Asia total 171 12 183 26 6 32

Central Asia

Onshore 255 140 396 12 23 35

Offshore 46 2 48 32 8 40

 Central Asia total 301 143 443 44 31 75

Southeast Asia and Oceania

Onshore 57 16 73 5 7 12

Offshore 376 65 441 39 23 62

 Southeast Asia and 

 Oceania total 433 81 514 43 31 74

Russia

Onshore 611 700 1,311 68 68 136

Offshore 253 0 253 22 0 22

Russia total 864 700 1,564 90 69 159

Grand total of all regions except North America

Onshore 1,530 1,165 2,695 664 623 1,287

Offshore 1,082 1,689 2,771 302 194 496

 Grand total 2,612 2,854 5,466 966 817 1,783
Estimates of Stranded Gas outside North America 5

Table 2. Distribution of gas by field size category for onshore and offshore stranded gas fields by regions.

[Field data through the end of 2008 are from IHS Inc. (2009). Regional totals here differ slightly from those in table 1 because the minimum field size in this

table is 0.048 TCF. Stranded gas in regions shown has export potential. TCF, trillions of cubic feet. Numbers may not add up due to rounding]

Gas field size 

class range 

(TCF)

Number 

of fields

Cumulative 

percentage 

of fields 

Volume in 

size class 

(TCF)

Cumulative 

percentage 

of gas 

volume

Number 

of fields

Cumulative 

percentage 

of fields 

Volume in 

size class 

(TCF)

Cumulative 

percentage 

of gas 

volume

South America Central Asia 

 >49.2 0 0 0 0 1 0.6 181 60.7

24.6–49.2 0 0 0 0 1 1.3 42 74.8

12.3–24.6 1 0.6 13 9.2 0 1.3 0 74.8

6.14–12.3 5 3.8 40 37.6 2 2.5 17 80.5

3.07–6.14 3 5.8 14 47.4 3 4.4 12 84.7

1.54–3.07 11 12.8 25 64.9 5 7.6 10 87.9

0.768–1.54 20 25.6 22 80.3 10 13.9 11 91.6

0.384–0.768 28 43.6 15 90.6 15 23.4 9 94.6

0.192–0.384 28 61.5 8 96 24 38.6 6 96.8

0.096–0.192 23 76.3 3 98.2 43 65.8 6 98.8

0.048–0.096 37 100 3 100 54 100 3 100

 Total 156 142 158 299

Middle East Southeast Asia and Oceania

 >49.2 0 0 0 0 0 0 0 0

24.6–49.2 3 1.9 108 35.6 1 0.2 46 10.9

12.3–24.6 2 3.1 34 46.9 3 0.7 50 22.6

6.14–12.3 3 5 21 54 6 1.8 50 34.3

3.07–6.14 14 13.7 57 72.8 16 4.7 69 50.5

1.54–3.07 13 21.7 29 82.5 31 10.3 68 66.5

0.768–1.54 23 36 27 91.3 44 18.2 50 78.2

0.384–0.768 26 52.2 14 95.7 70 30.9 37 86.8

0.192–0.384 30 70.8 8 98.3 119 52.3 31 94.2

0.096–0.192 28 88.2 4 99.6 114 72.9 15 97.7

0.048–0.096 19 100 1 100 150 100 10 100

 Total 161 303 554 426

Africa Russia 

 >49.2 0 0 0 0 2 1 277 32.1

24.6–49.2 0 0 0 0 6 4 216 57.2

12.3–24.6 0 0 0 0 8 8 134 72.7

6.14–12.3 1 0.2 10 4.7 10 13 83 82.3

3.07–6.14 8 1.9 32 19.7 17 21.5 73 90.8

1.54–3.07 17 5.4 39 37.9 15 29 35 94.9

0.768–1.54 46 15 48 60.5 18 38 20 97.2

0.384–0.768 73 30.1 39 78.5 18 47 10 98.3

0.192–0.384 96 50.1 25 90.4 24 59 7 99.1

0.096–0.192 93 69.4 11 95.7 35 76.5 5 99.7

0.048–0.096 147 100 9 100 47 100 3 100

 Total 481 215 200 862
6 Role of Stranded Gas in Increasing Global Gas Supplies

Figures 2 through 8 show the locations of clusters of stranded gas accumulations. Clusters of stranded gas fields are commonly in remote areas that tend to require large investments to develop, including facilities and infrastructure for gas production. The stranded fields also require large investments in infrastructure to transport gas to markets. Field volumes and costs for

stranded gas clusters shown in north Africa (fig. 2) and Nigeria (fig. 3) are presented in Attanasi and Freeman (2010). Similarly,

the costs of developing and transporting the stranded gas from fields in central Asia and western Russia (fig. 4) to markets in

continental Europe are presented in Attanasi and Freeman (2012a). The costs of developing stranded gas for markets in Asia 

from the field clusters in eastern Russia and central Asia (fig. 5), Southeast Asia (fig. 6), and Australia (fig. 7) are presented in

Attanasi and Freeman (2012b). A description of the stranded gas clusters shown in figure 8, representing the Middle East, is

provided in appendix 1, along with a brief discussion of the development of natural gas exports from that region. 

To summarize, although stranded gas fields are widely distributed, the largest concentrations by gas volumes are in Russia, Southeast Asia and Oceania, the Middle East, and central Asia (fig. 1). Concentrations of the large fields are in even fewer

areas: Russia, the Middle East, and central Asia (table 2). Large stranded gas accumulations are important because they will

allow scale economies and support development of necessary infrastructure. Not all of the stranded gas in table 1 is available 

for export to world markets because some volumes have been reserved for domestic consumption by the individual countries or 

there are technical reasons why some stranded fields cannot be safely developed.

Recoverable Stranded Gas in Oil Fields

Table 1 shows 664 TCF of technically recoverable gas in onshore oil fields outside of North America and 302 TCF in offshore oil fields. There is no assurance that these volumes will be brought to markets because the gas is a byproduct of the development of these oil fields. Natural gas in oil accumulations may occur as dissolved gas or as a gas cap. Produced natural gas is

commonly used as a fuel in oil field operations. Gas that is produced with the oil must be separated before the oil enters the oil

sales pipeline. If there are sufficient volumes of gas and there is infrastructure to transport the gas to market, the excess gas can

be sold as a byproduct of oil production. The recovered gas may also be re-injected into the oil-producing reservoir to offset the 

natural decline in reservoir pressure and to improve overall oil recovery. The disposition of the gas depends on the infrastructure, market conditions, and oil-production regulations. Gas purchasers who require high reliability of gas supply are sometimes 

reluctant to purchase associated gas because gas production is subject to the vagaries of the oil market.

For commercial recovery of the re-injected gas, there must be a sufficient volume of gas remaining in the reservoir at the

end of the oil field’s productive life to justify investments in field conversion and facilities to transport the gas to market. The

original volume of gas in the reservoir will be reduced by losses in the gas recycling process and by the gas used for fuel during 

the commercial life of the oil field. Over a 20- to 30-year field life, the gas consumed for fuel can be substantial. At this time, the

oil field data do not provide details about the disposition of gas in the oil fields.

If gas recovery is considered likely only from oil fields having an original recoverable stranded gas resource of at least 1

TCF, then this size cutoff reduces the total volume of 664 TCF (table 1) in onshore oil fields to 532 TCF (table 3). Similarly,

for offshore fields, the total volume of 302 TCF reduces to 192 TCF. Table 3 shows the regional distribution of the volumes of

stranded gas in oil fields that have at least 1 TCF of recoverable gas. The oil fields in the Middle East account for 439 TCF of the

532 TCF of stranded gas in onshore oil fields and 84 TCF of the 192 TCF of stranded gas in offshore fields. In the Middle East,

the stranded associated gas is in oil fields that have not begun to produce and in producing oil fields where gas is re-injected to

maintain reservoir pressure or where gas is used in enhanced oil recovery. Oil volumes in Middle East fields are large, as are

the volumes of associated gas. However, the immediate gas markets are limited. The leading oil producers in the Middle East 

are members of OPEC. In these countries, oil production, as well as the byproduct gas production, is subject to changing OPEC 

quotas. The profitability of conversion of gas to LNG requires a constant gas production stream so that a high utilization of the

LNG facilities is attained. Consequently, it is not likely these oil fields will provide significant supplements to gas export supplies. The gas from these fields could provide feedstock to large petrochemical complexes after the oil is sufficiently depleted so

that the oil fields are “converted” to gas fields.

For large onshore oil fields that are already producing and re-injecting large volumes of gas, the conversion of oil fields to

natural gas fields consists of construction or upgrading of the gas processing facilities and gas sales pipelines to a hub or LNG

plant. For offshore fields, the conversion might follow the pattern established by Statoil’s Statfjord field in the North Sea, where

production platforms were modified, some additional wells were drilled, and new gas sales pipelines were constructed (Statoil,

2012). Although conversion of oil fields to gas fields is more complex for offshore fields, the Statfjord conversion demonstrates

that such projects can be commercially successful. The required conversion investments are specific to each offshore field and its

original oil development configuration.
Estimates of Stranded Gas outside North America 7

Figure 2. Map showing LNG liquefaction plants, a collection location, trans-Mediterranean pipeline inlets, clusters of stranded 

gas fields, and U.S. Geological Survey (USGS) petroleum provinces (U.S. Geological Survey World Energy Assessment Team, 2000) 

in north Africa. LNG, liquefied natural gas.
8 Role of Stranded Gas in Increasing Global Gas Supplies

Figure 3. Map showing an LNG liquefaction plant, a collection location, clusters of stranded gas fields, and U.S. Geological Survey 

(USGS) petroleum provinces (U.S. Geological Survey World Energy Assessment Team, 2000) in Nigeria. LNG, liquefied natural gas.
Estimates of Stranded Gas outside North America 9

Figure 4. Map showing U.S. Geological Survey (USGS) petroleum provinces (U.S. Geological Survey World Energy Assessment Team, 

2000) with clusters of stranded gas fields in central Asia and western Russia that were analyzed for delivery to markets in Europe. Figure 

modified from Attanasi and Freeman (2012a). 
10 Role of Stranded Gas in Increasing Global Gas Supplies

Figure 5. Map showing selected U.S. Geological Survey (USGS) petroleum provinces in eastern Russia and central Asia (U.S. 

Geological Survey World Energy Assessment Team, 2000) with clusters of stranded gas fields analyzed for delivery to markets in Asia. 

Figure modified from Attanasi and Freeman (2012b).
Estimates of Stranded Gas outside North America 11

Figure 6. Map showing LNG liquefaction plants, clusters of stranded gas fields, and U.S. Geological Survey (USGS) petroleum 

provinces (U.S. Geological Survey World Energy Assessment Team, 2000) in Indonesia, Malaysia, and Brunei in Southeast Asia. Figure 

modified from Attanasi and Freeman (2012b). LNG, liquefied natural gas.
12 Role of Stranded Gas in Increasing Global Gas Supplies

Figure 7. Map showing LNG liquefaction plants, clusters of stranded gas fields, and U.S. Geological Survey (USGS) petroleum 

provinces (U.S. Geological Survey World Energy Assessment Team, 2000) in Australia. Figure modified from Attanasi and Freeman 

(2012b). LNG, liquefied natural gas.
Estimates of Stranded Gas outside North America 13

Figure 8. Map showing LNG liquefaction plants, LNG regasification terminals, clusters of stranded gas fields, and U.S. 

Geological Survey (USGS) petroleum provinces (U.S. Geological Survey World Energy Assessment Team, 2000) in the Middle 

East.
14 Role of Stranded Gas in Increasing Global Gas Supplies

Table 3. Volumes of stranded gas in oil fields having at least 1 TCF in original recoverable gas by 

region outside North America.

[Gas volumes are in trillions of cubic feet (TCF). Field data through the end of 2008 are from IHS Inc. (2009). South 

Asia is not in this table because it does not have any oil fields with at least 1 TCF of gas that is classified as stranded

gas. Numbers may not add up due to rounding]

Onshore or offshore environment Remaining gas Original recoverable gas

South America

Onshore 11 12

Offshore 26 26

 South America total 37 37

Europe

Onshore 0 0

Offshore 4 4

 Europe total 4 4

Middle East

Onshore 439 446

Offshore 84 84

 Middle East total 523 530

Africa

Onshore 20 20

Offshore 13 13

 Africa total 33 33

East Asia

Onshore 2 2

Offshore 4 4

 East Asia total 6 6

Central Asia

Onshore 6 6

Offshore 30 30

 Central Asia total 37 37

Southeast Asia and Oceania

Onshore 1 1

Offshore 12 13

 Southeast Asia and Oceania total 14 14

Russia

Onshore 52 52

Offshore 19 19

 Russia total 71 72

Grand total of all regions except North America

Onshore 532 539

Offshore 192 193

 Grand total 725 732
Structure of Global Natural Gas Markets 15

Structure of Global Natural Gas Markets

Trade Patterns

From a global perspective, analysts commonly identify the three regional natural gas import markets as North America, 

Europe, and Asia (Siliverstovs and others, 2005; International Gas Union (IGU), 2011; Rogers, 2012). Table 4 shows the

primary supply regions with stranded gas and their exports to the three global gas import markets. The transactions labeled for 

the European market do not include gas originating from or gas imported and consumed by Turkey, Belarus, Moldova, and 

Ukraine. Overall, the LNG supplied to the three markets grew by 43 percent over the period from 2008 to 2011, with the largest 

increase coming from the Middle East. Although this LNG capacity was developed for the North American market (Flower, 

2008), exports were marketed principally to Europe and Asia. Asia’s increase in LNG imports from 2010 to 2011 was driven by

closure of all of Japan’s nuclear facilities following the Tohoku earthquake (magnitude 9.0) in northern Honshu, Japan, and the

related tsunami on March 11, 2011, that damaged the Fukushima Dai-ichi nuclear powerplant. In Europe, new LNG supplies 

replaced 10 to 12 percent of pipeline gas from Russia. Russian gas sales to Europe declined about 12 percent from 2008 to 2009

and remained at least 10 percent below 2008 levels for 2010 and 2011. In 2009, Russia began to supply LNG from the Sakhalin

Island LNG plant (in far eastern Russia; see fig. 5), which was marketed entirely to Asia.

Transportation and Infrastructure

International Pipelines 

The growth in LNG supplies and marketing has been a force in integrating world gas markets (Hayes, 2006a). However, in 

the process of liquefaction, about 15 percent of the inlet gas is commonly used to power the plant, and additional volumes are 

lost as the seagoing LNG tankers use the boiloff gas to fuel the ship. The capital and operating cost of the LNG plant and tankers, as well as the losses in gas, are part of the transportation cost of bringing the gas to markets. Natural gas is also transported 

internationally by pipelines. Such pipelines can traverse countries called transit countries that are not the ultimate market for 

the gas. Shipping gas by pipeline across transit countries is costly and can be very risky. Transit countries may demand 4 to 6 

percent of the gross value of the pipeline gas as transit fees. Moreover, risks include thievery, disruptions due to instability inside 

the transit country, and potential political and contract conflicts between the transit country and the pipeline operators. All three

of the global markets are served by pipelines and LNG supplies. The North American market in recent years has become nearly 

self-sufficient, and there also is the possibility it could become a net supplier to other markets.

The north African country of Algeria exports pipeline natural gas across the Mediterranean Sea to continental Europe by the 

Maghreb-Europe pipeline, the trans-Mediterranean pipeline, and the MEDGAZ pipeline (fig. 9). The GALSI (Gasdotto Algeria 

Sardegna Italia) pipeline to Italy is planned. Libya exports natural gas across the Mediterranean Sea to continental Europe via 

the GreenStream pipeline. Table 5 shows the installed capacity of these individual pipelines from Africa to Europe, totaling 

5.9 billion cubic feet per day (BCF/D). 

The natural gas export pipelines from Russia to Europe (fig. 10) are owned by Gazprom, the Russian Government-controlled integrated company that produces, transports, and markets gas. Gazprom owns the gas pipeline network inside Russia

and has exclusive or monopoly rights to export gas from Russian territory (Sagers, 2007). Gazprom does not permit third-party

access to its pipelines, and so historically it purchases and then resells gas from central Asian gas producers to European purchasers (Ericson, 2009). Gas originating in central Asia or Russia is transported to Germany by way of the Nord Stream system

(underneath the Baltic Sea), to Poland through Belarus, or to Hungary through the Ukraine (fig. 10). In 2009, the Blue Steam

pipeline delivered 0.95 BCF/D to Turkey (Gazprom, 2011a), which is well below its pipeline capacity of 1.5 BCF/D. Table 5 

presents a list of the operating pipelines from Russia to Europe shown in figure 10, along with origin, destination, and capacities.

Table 5 also includes a list of proposed pipeline projects with planned capacities. Current capacity is 19.6 BCF/D for pipelines 

from Russia serving continental Europe exclusive of Turkey. The combined additional capacity of the proposed pipelines is 14.4

BCF/D. A more detailed discussion is presented in Attanasi and Freeman (2012a). 

Asia includes the Far East as well as India and surrounding countries. The market is fragmented with a number of island 

nations. The earlier analysis (Attanasi and Freeman, 2012b) of imported gas into the Asian market focused on leading Asian 

importers of LNG: Japan, South Korea, China, and India (BP, 2012). China, which currently consumes about half of the world’s

coal produced annually, has announced plans to increase gas usage (Aibing, 2012). Although coal is commonly priced much 

cheaper than gas on a calorific basis, the capital costs involved in constructing new environmentally acceptable coal-fired electrical generation plants are substantially greater than such costs for new gas-fired generation plants, which can offset any direct

fuel cost advantage. More than 400 million people, or one-third of India’s population, do not have electrical service (Wolfram

and others, 2012). Current projections of India’s demand for electricity and fuels neglect the added demands that will occur as
Table 4. Volumes of gas in billions of cubic feet (BCF) marketed in North America, Europe, and Asia from 2008 through 2011. [Data are from BP (2009, 2010, 2011a, 2012). Numbers may not add up due to rounding] Supply source 2011 2010 2009 

North America Europe* Asia North America Europe* Asia North America Europe* Asia No

Ame

Liquefied natural gas (LNG) North America 0 10 48 0 12 30 0 0 30 

South America 214 205 72 274 235 86 270 264 66 3

Europe* 15 108 52 30 98 17 33 79 3 

Central Asia 0 0 0 0 0 0 0 0 0 

Russia 0 0 508 0 0 473 0 0 219 

Africa 79 1,101 529 199 1,226 309 283 1,183 276 1

Middle East 295 1,556 2,567 136 1,004 2,038 23 512 1,665 

Southeast Asia and Oceania 9 0 3,409 66 0 3,314 3 3 3,116 

 LNG total 612 2,980 7,185 705 2,576 6,266 611 2,040 5,375 4

Pipeline gas

North America 4,546 0 0 4,363 0 0 4,307 0 0 4,6

South America 0 0 0 0 0 0 0 0 0 

Europe* 0 6,383 0 0 6,674 0 0 6,315 0 

Central Asia 0 0 503 0 0 125 0 65 0 

Russia 0 4,134 0 0 4,022 0 0 4,080 0 

Africa 0 1,242 0 0 1,558 0 0 1,383 0 

Middle East 0 0 0 0 0 0 0 0 0 

Southeast Asia 

and Oceania 0 0 1,022 0 0 1,052 0 0 676 

 Pipeline gas 

 total 4,546 11,758 1,525 4,363 12,254 1,177 4,307 11,843 676 4,6

LNG and pipeline gas

Grand total 5,158 14,739 8,710 5,068 14,830 7,443 4,918 13,883 6,051 5,0

	Former	theor	urkeyT		include	not	does 	Soviet 	Belarus,of		Republics and	ldova,		Mo Ukraine. *Europe
Structure of Global Natural Gas Markets 17

Figure 9. Map showing the approximate location and routes of gas pipelines from Africa to Europe. Figure modified 

from Attanasi and Freeman (2012a).
18 Role of Stranded Gas in Increasing Global Gas Supplies

Table 5. Pipeline capacity to transport gas to Europe.

[See footnotes for sources. BCF/D, billions of cubic feet per day. Numbers may not add up due to rounding]

Pipeline Origin Destination Capacity

(BCF/D)

From Africa to Europe (fig. 9)

Trans-Mediterranean1 Algeria Italy 2.9

Maghreb-Europe1 Algeria Spain and Portugal 1.2

MEDGAZ2 Algeria Spain 0.8

GreenStream3 Libya Italy 1.1

 Total from Africa to Europe 5.9

From Russia to Germany and central Europe (fig. 10) 

Yamal–Europe4 Russia Belarus 6.4

Northern Lights5 Russia Belarus 4.4

Urengoy-Pomary-Uzhhorod6 Russia Ukraine 3.1

Soyuz4 Russia Ukraine 3.1

Nord Stream, Phase 17 Russia Germany 2.7

 Total from Russia to Germany and central Europe 19.6

From Russia and Azerbaijan to Turkey (fig. 10) 

Blue Stream8 Russia Turkey 1.5

South Caucasus9 Azerbaijan Turkey 1.9

 Total from Russia and Azerbaijan to Turkey 3.5

Proposed (figs. 9 and 10)

Nord Stream, Phase 27 Russia Germany 2.7

South Stream10 Russia Bulgaria 6.1

Trans-Anatolia11 Azerbaijan European gas system 1.6

Nabucco12 Mid East Austria 3.0

GALSI13 Algeria Italy 1.0

 Total proposed 14.4

1

Hayes, 2006b.

2

MEDGAZ, 2009.

3

Alexander’s Oil and Gas Connections, 2004.

4

IHS Inc., 2007.

5

Pirani, 2009.

6

For-UA, 2011.

7

Nord Stream, 2011.

8

Gazprom, 2011a.

9

1.9 BCF/D (BP, 2006) with planned additional compression stations; current capacity is 0.7 BCF/D (BP, 2011b).

10Gazprom, 2011b.

11Capacity expandable to 2.3 BCF/D (Socor, 2012).

12Pickl and Wirl, 2010.

13Algeria Ministry of Energy and MinLQJ, 2009.
Structure of Global Natural Gas Markets 19

a greater proportion of India’s population is provided with electricity. Elsewhere in Asia, Bangladesh has 94 million, Indonesia

has 81 million, Pakistan has 70 million, and Burma has 42 million people without electrical service (Wolfram and others, 2012).

The potential future demand for Asian gas imports for electrical power generation goes well beyond that of Japan, South Korea, 

China, and India.

Figure 11 shows the route of the central Asia-China gas pipeline from Turkmenistan, through Uzbekistan, and to the 

Kazakhstan border with China. The First West-East pipeline was constructed years ago to bring domestic gas production from

northwest China’s Tarim Basin as gas production shifted to Xinjiang Province (Fridley, 2008). The Second West-East pipeline

was constructed to bring the gas from the Kazakhstan border to Guangdong Province with a spur to Shanghai. A third WestEast pipeline will bring additional gas delivered to western China from central Asia east and to southern China. Table 6 lists 

the name, status, and capacity of each of the operating and hypothetical pipelines. The Turkmenistan-China pipeline has capacity of 2.9 BCF/D. In 2011, China imported about 1.4 BCF/D by pipeline and 1.6 BCF/D as LNG and consumed 12.6 BCF/D 

(BP, 2012). The additional pipelines from Russia listed in the table are hypothetical, and no official pipeline route has been put

into the public domain. Table 6 also lists interregional pipelines from Malaysia and Indonesia to Singapore and from Burma to 

China. 

Terminals Receiving Liquefied Natural Gas

Table 7 lists the terminals receiving LNG in the United Kingdom and continental Europe. The table shows that in 2011 they

could receive 18.5 BCF/D in gas. Planned additions could increase the receiving capacity by about 5.6 BCF/D. The send-out 

capacity is a technical term and is the same as what is called here receiving capacity. It is the daily volume of gas that the terminal can send out to the local distribution systems. In 2011, Europe (including Turkey) imported 8.8 BCF/D as LNG (BP, 2012). 

It also imported 18.2 BCF/D of pipeline gas from outside of Europe. The United Kingdom (UK) accounts for about one-third 

of the send-out capacity. In 2011, the UK exported 1.5 BCF/D of gas to continental Europe. Additional regasification capacity

could be added as floating facilities or as components to LNG tankers, allowing regasification directly. Natural gas markets in

Europe and in the Far East that were examined commonly had large seasonal demand components. Although the capacity of the 

LNG regasification facilities appears to be more than adequate on an annual basis, the seasonal nature of demand means that in

some months, users require 20 percent above the average monthly consumption. 

Table 8 lists the regasification terminals in Asia by country along with the send-out capacity. In contrast to Europe, the Asian

regional market is fragmented, and there are no import gas pipelines to Japan, South Korea, or India. Although Asia has 48 BCF/D 

of regasification capacity, its LNG imports averaged about 20 BCF/D in 2011. Japan and South Korea account for more than

three-fourths of the capacity shown in the table. Demand for gas in both countries had very significant seasonal components.

Price Formation in Global Markets

The differences in natural gas price formation in the three regional markets reflect the historical development of the

markets, as well as the relative endowment of conventional natural gas resources. For North America, the Henry Hub prices are 

representative of prevailing prices (International Gas Union (IGU), 2011). In both Canada and the United States, natural gas 

prices from the wellhead to the wholesale level have been deregulated for at least a decade. In the United States, several decades 

were needed for the process of deregulating wellhead prices, implementing third-party access for gas pipeline facilities, and 

establishing the hubs where prices reflect market conditions efficiently (Herbert and Kreil, 1996).

Natural gas prices in Europe are in transition. The National Balancing Point (NBP) is a virtual sales and exchange hub for 

wholesale natural gas transactions in the UK. It serves as the delivery and pricing reference point for the IntercontinentalExchange, Inc. (ICE), natural gas futures contract (International Gas Union, 2011). Alternatively, in continental Europe, natural gas 

prices have historically been determined by oil-product-indexed long-term contracts (IGU, ). When 

gas field was developed in the Netherlands, producers priced the natural gas to be competitive with the refined oil products used

in industrial processes and electrical power generation. On an energy-equivalent basis, natural gas is more difficult than petroleum products to transport, and demand growth is historically limited to that of a replacement fuel for oil and coal (IGU, 20). 

Hence, gas demand growth depends on the rate that equipment using fuel other than natural gas will be replaced by equipment 

using natural gas. 

Norway’s, Russia’s, and north Africa’s gas suppliers adopted a similar policy of tying natural gas prices to prices of petroleum products and also of indexing gas price changes to changes in oil prices. Further, “take or pay” provisions were implemented to mitigate the supplier’s risks associated with capital-intensive pipeline and LNG projects (Stern and Rogers, 2011).

The European Union facilitated the development and integration of the continental Europe gas market with its evolving rules to 

eliminate transportation and trade barriers. 
20 Role of Stranded Gas in Increasing Global Gas Supplies

Figure 10. Map showing clusters of stranded gas fields and approximate locations of existing and proposed pipelines for delivery to 

transshipment points en route to Europe. Figure modified from Attanasi and Freeman (2012a).
Structure of Global Natural Gas Markets 21

Figure 11. Map showing clusters of stranded gas fields and a schematic of approximate location of existing and proposed 

pipelines for delivery to China and Vladivostok, Russia. Figure modified from Attanasi and Freeman (2012b).

Stern	and	Rogers	(2011)	reviewed	the	natural	gas	price	formation	history	of	continental	Europe	and	predicted	that	the	

major gas purchasers in continental Europe will abandon the oil-indexed pricing of natural gas and will index contract prices and 

changes	to	actual	market	prices.	During	the	period	from	the	latter	part	of	2008	through	2009,	significant	volumes	of	short-term	

shipments of LNG entered the UK and continental Europe. These shipments were priced according to current global gas market 

conditions. The desire to index long-term contracts to market-based prices came about because of the losses incurred by utilities 

that	were	obligated	by	take-or-pay	contract	provisions	in	their	oil-indexed	long-term	contracts	to	buy	gas	that	reflected	soaring	

oil prices. The oil-indexed gas prices that were paid were well above market-based prices. These utilities then had to resell the 

gas to customers who had access to the market-priced LNG shipments. In order to sell the gas to these customers, the utilities 

had to price the gas below what they paid for the gas (Melling, 2010). In the aftermath, the litigation by the utilities to re-open 

contracts and partially restructure indexation provisions has met with some success (Andresen and Shiryaevskaya, 2012), as 

Gazprom is negotiating out-of-court settlements with its major European purchasers. 

Natural gas exports to Asian markets have typically been supplied as LNG, and prices have commonly followed the pattern 

set	by	Japan’s	purchases	of	LNG.	The	Japanese	Government’s	reaction	to	the	oil	disruptions	of	the	1970s	was	to	implement	a	

policy	that	subsidized	the	substitution	of	natural	gas	for	oil	in	its	industrial	sector	and	for	electricity	generation.	In	the	1970s,	

LNG	was	the	only	practical	way	Japan	could	import	natural	gas.	The	Japanese	Government	assisted	in	financing	LNG	projects	

where Japanese electrical power and gas distribution utilities had equity positions and where utilities had long-term gas supply contracts. Long-term LNG contract prices were indexed to prices of a suite of crude oils. In most LNG supply projects in 

Southeast Asia and Australia, the national oil companies (NOCs) or utilities of the major gas-purchasing countries take equity 

positions in the liquefaction plants. Because these participating entities will sell their purchased gas into captive markets, they 

are likely less concerned about their purchase price than with other product dimensions, such as reliability of supply. 
22 Role of Stranded Gas in Increasing Global Gas Supplies

Table 6. Pipeline capacity to transport gas to China and Singapore.

[See footnotes for sources. Some pipelines are shown in figure 11. BCF/D, billions of cubic feet per day; NA, not available]

Pipeline Origin Destination Status Capacity

(BCF/D)

From central Asia to China

First West-East gas pipeline1 Tarim Basin, China Shanghai, China Built 1.2

Second West-East gas

pipeline2

Korgas, China Guangzhou, China Built 2.9

Turkmenistan-China gas 

pipeline3

Türkmenabat, 

Turkmenistan

Korgas, China Built 2.9

Incremental upgrade to 

Turkmenistan-China 

pipeline4

Türkmenabat, 

Turkmenistan

Korgas, China Proposed 3.4

Western Kazakhstan-Western 

China gas pipeline5

Beyneu, Kazakhstan Korgas, China Proposed 1.0

From Russia to China 

Gazprom pipeline networkChina6West Siberian Basin,

Russia

China Proposed 2.9

Kovykta gas field-China/Korea

gas pipeline6

Kovykta gas field, Russia China, South Korea Dropped 2.9

From Burma (Myanmar) to China 

Myanmar-China gas pipeline7 Bay of Bengal, Burma Kunming, China Under construction 1.2

From Southeast Asia to Singapore

NA Sumatra, Indonesia Singapore Built NA8

NA Malaya, Malaysia Singapore Built NA8

1

Gray and others (2003).

2

China-Wire (2008).

3

Yenikeyeff (2008).

4

Socor (2012).

5

Yenikeyeff (2008).

6

Fridley (2008).

7

Smith (2011).

8

Pipeline deliveries to Singapore for 2011 according to BP (2012) were 0.7 BCF/D from Indonesia and 0.2 BCF/D from Malaysia.
Structure of Global Natural Gas Markets 23

Table 7. Location and capacity of terminals receiving liquefied natural gas (LNG) in Europe.

[Data are from Gas Infrastructure Europe (2011). BCF/D, billions of cubic feet per day; dash (-), no data]

Country Name or location Existing capacity 

(BCF/D)

New or additional 

capacity (BCF/D)

Belgium Zeebrugge 0.9 0.3

France Fos Cavaou 0.8 -

Fos Tonkin 0.5 -

Montoir de Bretagne 1.0 -

Dunkerque - 1.3

Greece Revithoussa 0.5 0.2

Italy Panigaglia 0.3 -

Porto Levante 0.7 -

Toscana - 0.4

Netherlands Rotterdam 1.2 0.4

Poland Swinoujscie - 0.5

Portugal Sines 0.6 0.1

Spain Barcelona 1.7 -

Bilbao 0.7 0.3

Cartagena 1.1 0.3

El Ferrol 0.3 0.4

Huelva 1.1 0.1

Sagunto 0.9 0.5

Gijon - 0.7

Gran Canaria - 0.1

Tenerife - 0.1

Turkey Aliaga 0.6 -

Marmara Ereglisi 0.6 -

United Kingdom Dragon 0.6 -

Isle of Grain 1.9 -

South Hook 2.0 -

Teesside 0.4 -

 Europe total 18.5 5.6
24 Role of Stranded Gas in Increasing Global Gas Supplies

Table 8. Location and capacity of liquefied natural gas (LNG) regasification terminals in Asia.

[Data are from True (2012). For each country, terminals are ordered from the earliest to the latest put into operation except that expansions are kept with the 

original terminal. BCF/D, billions of cubic feet per day; TBD, to be determined]

Site 

(start-up year for new capacity)

Capacity 

(BCF/D)

China

Guangdong, Dapeng LNG 0.9

Fujian 0.3

Shanghai 0.4

Shanghai expansion (TBD) 0.4

Dalian 0.4

Zhejang Nigbo 0.4

Jiangsu Rudong 0.4

Shandong Quindao 0.4

Zhuhai Jinwan 0.4

Zhuhai Jinwan expansion (2015) 0.4

 China total 4.6

India

Dahej, Gujarat 1.5

Hazira, Gujarat 0.5

Hazira expansion (2013) 0.2

Dabhol, Maharashtra 0.7

Kochi, Kerala 0.3

Kochi expansion (2012–13) 0.3

 India total 3.5

Japan

Negishi, Yokohama 1.5

Senboku I, Osaka 0.3

Senboku II, Osaka 1.6

Sodegaura, Chiba 3.7

Chita Joint Terminal, Aichi 1.0

Tobata, Kitakyushu City 0.9

Himeji, Hyogo 1.1

New Chita, Aichi 1.5

Higashi Ohgishima, Kawasaki City 2.0

Higashi-Niigata, Higata Higashi Port 1.2

Himeji II, Hyogo 0.6

Futtsu, Chiba 2.6

Yokkaichi, Mie 0.9

Yanai 0.3

Oita, Oita City 0.6

Yokkaichi Works, Mie 0.1

Site 

(start-up year for new capacity)

Capacity 

(BCF/D)

Japan—Continued

Fukuoka Prefecture 0.1

Omuta satellite, Fukuoka Prefecture 0.1

Hatsukaichi, Hiroshima 0.1

Kagoshima, Southern Kyushu 0.03

Kawagoe, Mie 0.7

Sodeshi, Shizuoka 0.1

Ohgishima, Yokohama 0.8

Shin-Minato, Sendai City 0.04

Chita Midorihama, Aichi 0.7

Nagasaki 0.01

Mizushima, Okayama 0.1

Mizushima expansion (2012) 0.1

Sakai, Osaka 0.3

Sakaide, Shikoku 0.2

Okinawa 0.04

Naoetsu, Joetsu City, Niigata (2014) 0.1

 Japan total 23.3

South Korea

Pyeong Taek 4.0

Incheon 4.2

Tong Yeong 1.9

Kwangyang 0.2

Samcheok (2013) 2.3

 South Korea total 12.7

Malaysia

Mukim Sungai Udang, Melaka 0.5

Singapore

Jurong Island (2013) 0.4

Taiwan

Yung An 2.3

Taichung 0.4

 Taiwan total 2.7

Thailand

Map Ta Phut, Rayong Province 0.6

Grand total for Asia

 Asia total 48.3
Structure of Global Natural Gas Markets 25

Potential Growth in Europe’s Demand for Imported Gas 

Neither this study nor the previous studies discussed above developed independent natural gas import demand projections 

for Europe. Instead, the projection from Volkov and others (2009) is used to provide a rough target for assessing the sufficiency

of supply over a 20-year period starting in 2020. In 2008, Europe (or the EU27 plus group6) consumed 20.5 TCF of gas and 

produced 11.1 TCF of gas7 (U.S. Energy Information Administration (EIA), 2009a,b) and imported nearly 9.4 TCF of gas. The 

projection made by Volkov and others (2009) of Europe’s gas imports was based on demand growth of 20 percent to 2020 over

2008 consumption and Europe’s expected production decline of 11 percent from 2008 production. This trend widens the 2008

import gap between consumption and production by another 5.3 TCF per year (TCF/Y), or more than 14.5 BCF/D. Even if gas 

imports stabilize at the projected 2020 level, a 106-TCF tranche of imported gas is required over the next 20 years to accommodate the 5.3-TCF/Y import increase, and an additional 180 TCF is required to meet the 2008 baseline import demand of 9.4 

TCF/Y from 2020 through 2040. The original projections by Volkov and others (2009) take into account the desire of the European Union to reduce carbon dioxide emissions by reducing coal consumption. However, in May 2011, the German Government 

announced that it would no longer approve extensions to the permitted operating life of nuclear powerplants (Mufson, 2011).8

If natural-gas-fired plants were substituted for nuclear power generation, they would add about 2.5 BCF/D, or about another 0.9

TCF/Y, to the baseline gas demand. 

Several factors could moderate growth in the demand for imported gas over this period. The most notable is the possibility 

of commercially produced gas from gas-charged shale intervals. Producers in North America obtain commercial flow rates by

drilling production wells with long horizontal laterals and hydraulically fracturing the reservoir rock in multiple locations along 

the lateral wellbore. Fracture treatments liberate the gas from the reservoir rock and provide pathways for the released gas to 

migrate to the well. In 2011, the EIA published a reconnaissance assessment of global shale gas resources prepared by Advanced 

Resources International (U.S. Energy Information Administration, 2011c). It estimated Europe’s technically recoverable shale

gas resources at 557 TCF with 187 TCF assigned to Poland, 180 TCF assigned to France, and 83 TCF assigned to Norway.

There are mixed reports regarding the commercial producibility of the resource based on the early results of drilling. However, 

France has already prohibited the application of hydraulic fracturing, and other countries are considering similar prohibitions. 

The EIA (2011b) projected that even without any opposition to hydraulic fracturing, any European production of unconventional 

gas, such as shale gas, to 2020 would be very small. 

Potential Growth of Demand for Imported Gas in Japan, China, South Korea, and India 

The import demand projections for natural gas for Japan, China, South Korea, and India (Asia’s current and potential

leading importers of gas) are based on the EIA’s reference case projection published in the 2011 International Energy Outlook

(U.S. Energy Information Administration, 2011b). The gas import projections start at the historical base of 5.1 TCF/Y in 2008, 

grow to 9.5 TCF/Y in 2020, and reach 11.5 TCF/Y in 2030 (see table 9). The gas import demand projections may be derived 

as the difference in EIA’s projections for each country’s domestic gas demand and domestic gas supply. Over the projection

period, Japanese and South Korean gas demands increase 0.3 percent per year and 1.4 percent per year, respectively. Domestic 

production of gas by Japan remains at about 0.2 TCF/Y, and production by South Korea is much less than 0.05 TCF/Y. Demand 

projections show growth in gas usage of 5.5 percent per year for China and 4.5 percent per year for India. During the forecast 

period, China’s conventional gas production declines but is more than offset by production of unconventional gas to the point

that by 2030, unconventional gas accounts for two-thirds of China’s domestic production. The EIA reported China as having no

unconventional gas production as of 2008. India’s gas production increases to 3.6 TCF/Y in 2030 with 0.2 TCF/Y from unconventional gas. 

The EIA reference case projection of future international gas trade is very conservative. Their gas and energy demand 

projections are predicated upon standard macroeconomic demand analysis. However, Wolfram and others (2012) argued that

this approach inevitably underestimates the actual demand for developing countries such as India because it implicitly assumes 

that households are already served by electricity or the fuel in question. Projections of demand growth should also account for 

6

Europe’s EU27 group includes Austria, Belgium, Bulgaria, Cyprus, Czech Republic, Denmark, Estonia, Finland, France, Germany, Greece, Hungary, Ireland,

Italy, Latvia, Lithuania, Luxemburg, Malta, the Netherlands, Poland, Portugal, Romania, Slovakia, Slovenia, Spain, Sweden, and the United Kingdom. The

“EU27 plus group” includes Norway and Switzerland.

7

If the European former Soviet Republics outside of Russia are included, Europe’s 2008 total consumption was 24.6 TCF and its 2008 production was 11.8

TCF.

8

Switzerland will also close its nuclear powerplants by 2034, representing 0.5 BCF/D (Mufson, 2011). There is a potential of an additional 15-BCF/D 

increment to demand if all European countries with nuclear powerplants take similar action.
26 Role of Stranded Gas in Increasing Global Gas Supplies

Table 9. Two demand scenarios for net natural gas imports by country showing historical imports and 

projections into the future for Japan, South Korea, China, and India.

[EIA reference case projections are from U.S. Energy Information Administration (2011b). Volumes are in trillions of cubic 

feet per year (TCF/Y). Numbers may not add up due to rounding]

Country

Historical Projection

2008 2009 2015 2020 2025 2030 2035

Scenario 1: EIA reference case

Japan 3.5 3.4 3.4 3.5 3.7 3.8 3.8

South Korea 1.2 1.2 1.5 1.6 1.8 1.8 1.9

China 0.0 0.1 2.4 3.3 4.1 4.5 4.6

India 0.4 0.4 0.8 1.1 1.3 1.4 1.4

 Total 5.1 5.1 8.1 9.5 10.9 11.5 11.7

Scenario 2: Alternative case

Japan 3.5 3.4 5.8 6.1 6.4 6.8 7.0

South Korea 1.2 1.2 1.5 1.6 1.8 1.8 1.9

China 0.0 0.1 6.0 8.2 12.5 16.3 18.9

India 0.4 0.4 1.9 3.4 5.3 7.5 10.1

 Total 5.1 5.1 15.2 19.3 26.1 32.4 37.9

the provision of electrical service to some of the more than 400 million people in India without it.9 Since the publication of the 

EIA projections, Japan announced it will close down it nuclear power generation industry (Inajima and Okada, 2011). China has 

announced a policy to increase gas usage for electricity generation to mitigate urban air quality degradation resulting from coalfired electricity generation (Aibing, 2012). India faces similar urban air quality issues.

A variation of the EIA reference project was devised that provided a plausible alternative gas import scenario. Although 

China consumes 46 percent of the global coal produced each year, EIA’s reference projection assumed that China would continue to increase coal consumption by importing increasing volumes of coal. India consumes 7 percent of global coal supplies

annually and imports about 22 percent of what it consumes annually, and its coal consumption under the reference projection 

continues to increase. As a plausible alternative scenario, it was assumed that gas is substituted for half of the projected incremental growth in coal use for electricity generation. This assumption added 4.9 TCF/Y to China’s 2020 imports and 11.8 TCF/Y

to its 2030 imports. This assumption, if applied to the EIA reference projection for India, would add 0.55 TCF/Y to imports in 

2020 and 1.5 TCF/Y of gas in 2030, which accounts for only part of the difference between the EIA and alternative projections. 

The EIA reference forecast for imported gas for India was also adjusted to bring electrical service by 2035 to about 70 percent of those now without electrical service. In particular, it was assumed that by 2035, 90 percent of India’s projected population of 1,525 million people would be served by electricity. A linear extrapolation implies that 1.01 percent of the population is 

added annually between 2010 and 2035. If this incremental electricity demand were met by gas-fired generation powerplants,

the additional gas imports to India would amount to 1.7 TCF/Y in 2020 and 4.6 TCF/Y in 2030.

Table 9 presents the EIA reference case and the alternative scenario. The alternative scenario is plausible for the following 

reasons: Japan has committed to closure of its nuclear power industry, predictions for China and India assumed that substitution of gas for coal would only slow the increases in coal usage for electricity generation, and India’s expansion of the electrical

service is a fundamental marker of its progress in economic development. The volumes of gas demand projected by the two scenarios for Asia are different. In order to meet demands starting in 2020 and going through 2040, under the EIA reference case, 

importers must secure 224 TCF of gas, and for the alternative import demand scenario, they must secure 625 TCF of gas without 

even allowing for additional growth in gas import demand beyond 2035.10

9

By contrast, as of 2008, electrical service had been extended to 99.9 percent of China’s population.

10This volume calculation was simply based on the average annual import demand for each of the 5-year blocks from 2020 to 2035, and the imports for 2035 

were extended to 2040.
Potential Additions to Supply from Development of Stranded Gas 27

Potential Additions to Supply from Development of Stranded Gas

Results	of	the	regional	stranded	gas	studies	are	briefly	reviewed	before	discussing	the	synthesis.	First,	a	summary	of	the	

economic assumptions that were uniformly applied to each area is provided. The resources that were evaluated in each supply 

region	are	then	discussed,	and,	finally,	the	cost	functions	are	presented.	Appendix	2	discusses	the	sources	of	cost	data	and	the	

development	assumptions	used	to	compute	those	costs	for	representative	onshore	and	offshore	gas	fields.	

Economic Cost Calculations and Assumptions

The	economic	analysis	assigns	costs	to	the	volumes	of	gas	and	liquids	at	stranded	gas	fields	in	the	IHS	International	

Petroleum Exploration and Production database (IHS Inc., 2009). Production facilities and transportation facilities are built with 

anticipation that revenues from production will repay all operation costs, taxes, and capital investments, as well as provide an 

after-tax return of at least 12 percent on investment. Costs include extraction and delivery of produced gas to a transshipment 

location near a proposed international pipeline or to a coastal area for conversion to LNG where it can be loaded onto seagoing 

tankers.	The	producer’s	unit	cost,	in	U.S.	dollars	per	thousand	cubic	feet	of	gas,	is	defined	as	the	threshold	price	that	must	be	

paid	at	the	transshipment	or	market	location	that	is	just	sufficient	to	repay	all	capital	investments,	operating	costs,	taxes,	and	a	

12-percent	after-tax	return	on	investment.	If	a	representative	gas	field	in	a	particular	size	and	depth	class	(discussed	in	appendix	

2)	is	commercially	developable	as	indicated	by	a	non-negative	discounted	net	present	value	for	a	given	price,	then	all	fields	in	

that size class and depth class located in the same cluster are assumed to be commercially developable. 

In	order	for	the	resource	cost	functions	for	gas	in	stranded	gas	fields	to	reflect	the	physical	differences	in	the	field	size	

distributions,	depth	(water	and	drilling),	and	remoteness,	identical	sets	of	fiscal	parameters	(income	tax	rate,	royalty	rate,	

required	rate	of	return)	were	adopted	for	all	areas.	The	common	set	of	fiscal	assumptions	includes	a	20-percent	royalty	rate,	a	

50-percent income tax (with recovery of capital through depreciation charges), and a 12-percent required after-tax return on 

investment.	Costs	are	based	on	those	that	prevailed	in	the	first	quarter	of	2008,	and	all	computations	are	made	in	constant	U.S.	

dollars.	Onshore	and	offshore	field	development	includes	facilities	to	extract	natural	gas	liquids	(NGLs)	from	the	production	

gas stream.11	The	valuation	attached	to	natural	gas	liquids	was	based	on	the	assumption	that	crude	oil	prices	were	$70	per	barrel.	

Except where otherwise noted, costs of extraction and product transport to a transshipment location represent the cost of new 

facilities.

Transportation	and	liquefaction	costs	were	based	on	a	“cost	of	service”	concept	where	tariffs	and	liquefaction	tolls	are	set	

to recover operating costs, taxes, capital investment over the economic life of the pipeline or plant, and a 12-percent after-tax 

return	on	investment.	For	transporting	gas,	the	“cost	of	service”	concept	used	here	assumes	that	new	pipelines	will	be	built	along	

the	rights-of-way	of	existing	pipelines	and	that	the	computed	tariffs	reflect	the	full	cost	of	service	and	the	recovery	of	investment	

capital	along	with	a	return	to	capital.	Within	Russia,	central	Asia,	and	most	gas-consuming	countries	of	eastern	Europe	and	east	

Asia, the gas pipeline network is controlled by the government or its operating company, which has been given monopoly status. 

The actual tariffs charged may be unrelated to the true cost of service and therefore may correspond poorly with the tariffs 

computed here. Similarly, some liquefaction plants in north Africa are owned by the government or state companies where costs 

are not transparent. Gas pipeline and liquefaction plants were assumed to be subject to a 50-percent income tax with recovery of 

capital through depreciation charges.

Resources Evaluated for Europe’s Markets

The	natural	suppliers	for	Europe’s	gas	market	are	the	gas-exporting	countries	of	north	Africa	and	the	Atlantic	Basin,	Russia,	

and selected gas-producing countries of central Asia. For the immediate future, Qatar is the only country in the Middle East with 

exports	to	Europe,	and	any	expansion	plans	for	production	are	tied	to	the	North	field	(see	appendix	1).	Table	10	is	a	summary	

list of the volumes of resources evaluated for each supply region examined. The Atlantic Basin countries studied were Venezuela 

and	Trinidad	and	Tobago	in	the	Western	Hemisphere	and	Nigeria	in	the	Eastern	Hemisphere.	Both	onshore	gas	and	offshore	gas	

in	stranded	gas	fields	in	Nigeria	(see	fig.	3)	were	evaluated.	In	north	Africa,	the	onshore	stranded	gas	fields	of	Algeria	and	Libya	

and	the	offshore	stranded	fields	of	Libya	and	Egypt	were	evaluated	(see	fig.	2).	A	total	of	178	TCF,	or	81	percent,	of	the	219	

TCF	of	gas	in	African	offshore	and	onshore	stranded	gas	fields	shown	in	table	1	was	evaluated.	About	48	TCF	was	evaluated	

for	offshore	gas	fields	in	Venezuela	and	Trinidad	and	Tobago,	and	15	TCF	was	evaluated	for	onshore	stranded	gas	in	Venezuela.	

This	represented	about	half	of	the	145	TCF	of	gas	in	stranded	gas	fields	in	South	America.	

11Although	NGLs	add	significant	economic	benefits,	the	stranded	gas	field	database	did	not	provide	consistently	reliable	estimates	for	NGLs.	The	U.S.	

Geological	Survey’s	estimates	of	the	ratio	of	natural	gas	liquids	to	dry	gas	for	undiscovered	gas	were	applied	to	calculate	expected	liquids	recovery	(U.S.	

Geological	Survey	World	Energy	Assessment	Team,	2000).	For	areas	without	U.S.	Geological	Survey	estimates,	liquids-to-gas-ratio	estimates	of	analog	areas	

were used.
28 Role of Stranded Gas in Increasing Global Gas Supplies

Table 10. Stranded gas resources evaluated for European and Asian markets.

[Field data through the end of 2008 are from IHS Inc. (2009). Gas volumes are in trillions of cubic feet (TCF). Numbers may not add up due to rounding]

Supply region Subregion Onshore gas Offshore gas

European market

North Africa Algeria 49 0

Libya 18 12

Egypt 0 44

 North Africa total 67 56

Atlantic Basin Nigeria 28 28

Venezuela, Trinidad and Tobago 15 48

 Atlantic Basin total 42 76

Russia West Siberian Basin 531 40

Timan-Pechora Basin 17 0

Volga-Ural Region 3 0

Caspian Sea region 5 9

 Russia total 555 49

Central Asia Azerbaijan 0 42

Turkmenistan 213 2

Kazakhstan 5 0

Uzbekistan 31 0

 Central Asia total 249 44

 European market total 913 225

Asian markets

Russia West Siberian Basin 95 0

Eastern Siberia 102 0

 Russia total 197 0

Central Asia Turkmenistan 211 0

Uzbekistan 31 0

Kazakhstan 4 0

 Central Asia total 246 0

Southeast Asia & Australia Australia 8 105

Indonesia 10 44

Malaysia 0 48

 Southeast Asia & Australia total 18 197

 Asian markets total 461 197

Europe is also currently supplied with pipeline gas from Russia. All of the central Asian gas-producing countries—Azerbaijan, Turkmenistan, Kazakhstan, and Uzbekistan—sell gas to Russia, which in turn, sells to domestic users and the former Soviet

Republics of Belarus, Ukraine, and Moldova, besides Europe. Gas-exporting countries located on the eastern side of the Caspian

Sea sell their gas exports to Russia, to neighboring countries, or to China. The seabed territorial claims of countries bordering

the Caspian have not been adjudicated, and so underwater gas pipelines cannot be constructed. Some Azerbaijani gas flows to

Europe through Turkey. 

The Russian stranded gas fields that were evaluated for Europe’s gas markets are located in the Timan-Pechora Basin, the

West Siberian Basin, the Volga-Ural Region, and the bordering onshore and offshore areas of the Caspian Sea (see fig. 4). For

these fields in Russia, a total of 555 TCF is in onshore stranded gas fields, and 49 TCF is in offshore stranded fields (table 10).

The Russian stranded gas fields in the Barents Sea and a very small field in the Timan-Pechora Basin were not evaluated, nor

were fields east of the West Siberian Basin. The volumes in stranded gas fields of Azerbaijan, Turkmenistan, Kazakhstan, and

Uzbekistan (fig. 4) that were evaluated amounted to 249 TCF in onshore fields and 44 TCF in offshore fields, representing nearly
Potential Additions to Supply from Development of Stranded Gas 29

all the gas in gas fields shown in table 1 for central Asia. As republics of the former Soviet Union, Azerbaijan, Turkmenistan,

Kazakhstan, and Uzbekistan are already connected to the Gazprom pipeline system. However, without a trans-Caspian pipeline, 

the Gazprom pipeline network is the only way for Turkmenistan, Kazakhstan, and Uzbekistan to move gas to the west (see fig.

10). The cost calculations for the new pipelines to transport the additional supplies from stranded fields are assumed to use the

established rights-of-way of the operating pipeline routes in figure 10, unless otherwise stated.

Resources Evaluated for Asia’s Markets 

Figure 5 shows the clusters of stranded gas fields in Russia and central Asia evaluated for supply of China. The far north

cluster in the West Siberian Basin contained about 92 TCF of gas, and the other cluster due south in the same West Siberian

Basin had 2.6 TCF of gas. Figure 11 shows the proposed route from these clusters south to the junction with China’s West-East

pipeline system. The five Russian stranded gas field clusters shown in figure 5 in the petroleum provinces of eastern Siberia

contain 102 TCF in 35 stranded fields. One option for this gas is to supply Beijing, China. Gazprom has also announced plans to

develop and transport some of the gas from the stranded gas fields of the Angara-Lena Terrace, the Baykit Arch, Nepa-Botuoba

Arch, and the Lena-Vilyuy Basin of eastern Siberia (fig. 5) to planned LNG facilities at Vladivostok, Russia (Gazprom, 2012).

The other undeveloped gas resources in the far eastern part of Russia, specifically the Sakhalin Islands, were not evaluated

because much of the gas was considered associated gas or there were insufficient data on the gas accumulations in the database.

The transportation facilities shown for Russia in figure 11 include hypothetical pipelines that were posited to originate

from the Gazprom network connecting the eastern clusters of the West Siberia basin at Urengoy to Proskokovo (due south), then

connecting to China’s Second West-East pipeline to either Shanghai or further south to Guangzhou. The route in figure 11 from

the stranded gas clusters in eastern Siberia to Beijing, China, or Vladivostok, Russia, skirts Mongolia as a transit country. The

hypothetical route originates near Irkutsk, then travels northeast to connect clusters within Russia. The pipeline then either enters

China north of Beijing at Blagoveshchensk, Russia, or alternatively moves gas to a proposed LNG terminal at Vladivostok

(Gazprom, 2012). The distance from Beijing to Shanghai, China, is about 670 miles (mi).

The market options for central Asian exporting countries east of the Caspian Sea are sales to Gazprom, sales to neighboring 

gas-consuming countries, and, more recently, sales to China. Total gas evaluated for the Asian market is 246 TCF, or 82 percent 

of the total stranded gas for central Asia shown in table 1.12 Gas from central Asia is delivered to China’s West–East pipeline by

the Turkmenistan–China pipeline or the Western Kazakhstan–Western China pipeline (fig. 11). Within China, pipeline routes

were posited to deliver gas to Shanghai in eastern China (see fig. 11) and Guangzhou in south-central China. Many of these

routes would follow pipelines built or proposed by China National Petroleum Corporation (CNPC). CNPC is building a network 

linking many industrial cities in eastern China with producing regions in the western part of China (China National Petroleum 

Corporation, 2012). The Turkmenistan-China pipeline shown in figure 11 is established, and expansions and (or) upgrades are

scheduled to increase transport capacity from 2.9 BCF/D (Yenikeyeff, 2008) to 6.3 BCF/D (Socor, 2012). 

The Southeast Asian countries of Indonesia and Malaysia have exported LNG for decades. All of Malaysia’s stranded gas

is offshore (fig. 6, table 10). The two offshore clusters adjacent to the Malay Peninsula together account for 29 TCF of gas and

were excluded from consideration of LNG export development because this resource is likely to be dedicated to the domestic 

market. About 70 percent of the country’s population lives in the Malay Peninsula (Ledesma, 2008). Stranded Malaysian gas

fields holding 48 TCF of gas were evaluated for export of LNG to the designated markets.

Indonesia has an estimated 81 million people (35 percent of its population) without electricity (Wolfram and others, 2012).

Natural-gas-fueled generating plants have lower capital investment per kilowatt hour of installed capacity than either coal-fired

plants or nuclear generating plants. However, because domestic prices are set much lower than international gas prices, gas 

producers are reluctant to sell gas to domestic users. The popular perception that gas exports cause domestic gas shortages has 

resulted in civil unrest (U.S. Energy Information Administration, 2011a). The government is under increasing pressure to ban 

exports from some projects and to require export projects to devote some of their production to the domestic market. Of the 

approximately 25 TCF of gas in onshore stranded gas fields, 15 TCF was located near dense population centers and was judged

unlikely for export. Another 7 TCF of offshore gas resource was excluded from LNG evaluation because the field clusters

were also located adjacent to population centers. Finally, the Natuna D-alpha field (in East Natuna Basin shown in fig. 6) was

excluded because its development will likely require technology advances in carbon dioxide separation and sequestration. The 

field holds 42 TCF of methane entrained in 100 TCF of carbon dioxide (see Attanasi and Freeman, 2012b, for further details). Of

the total 124 TCF of stranded gas initially identified for Indonesia, 54 TCF was evaluated for commercial LNG export (table 10).

12As discussed in text above (in the section, “Estimates of Stranded Gas outside North America”), the size of the largest field in central Asia, Turkmenistan’s

Yoloten-Osman field, was recently upgraded to between 460 and 750 TCF of gas (Gurt, 2011). This study, along with Attanasi and Freeman (2012a,b), used the

IHS field size of less than 200 TCF.
30 Role of Stranded Gas in Increasing Global Gas Supplies

In Australia, two widely separated onshore clusters (total 1.5 TCF), located near the city of Perth and in the Gippsland 

Basin (not shown in fig. 7), and two offshore clusters of fields (3.4 TCF, in Gippsland and Otway Basins) were not evaluated

because they could not sustain a commercial-scale LNG plant. During this study, several projects have been sanctioned, and 

their gas was removed from consideration in the cost analysis. The Pluto LNG project (Pluto field) and the Gorgon project (Gorgon and Janz/Io fields) in the Northwest Shelf (see fig. 7) removed 41.7 TCF from the stranded gas. In the Browse Basin (see

fig. 7), the Browse project (Calliance, Torosa, and Brecknock1 fields) removed 20.8 TCF from the uncommitted reserves. The

stranded gas fields evaluated for Australia held 105 TCF of recoverable gas offshore and 8 TCF onshore (table 10).

Landed Costs of Stranded Gas for Europe’s Markets

Gas from the Atlantic Basin and North Africa

Costs of gas delivered to Europe from stranded gas fields included field development and extraction costs and the cost of

transportation to an international pipeline or a coastal liquefaction plant. The liquefaction plant transforms the gas into LNG 

to be shipped by seagoing tanker to market. Countries that could supply Europe with stranded gas were categorized by broad 

geographic locations. The Atlantic Basin countries having stranded gas included Nigeria, Venezuela, and Trinidad and Tobago. 

North Africa included Algeria, Libya, and Egypt. Russia and central Asian gas exporters included Russia, Azerbaijan, Turkmenistan, Kazakhstan, and Uzbekistan.

Figure 12 and table 11 show the estimated resource cost of stranded gas delivered to existing LNG complexes or at international gas export pipelines from stranded gas fields located in the Atlantic Basin and north Africa. The functions show how

estimated resource costs progressively increase as more costly tranches of stranded gas are committed to projects. All exports to 

Europe from Venezuela, Trinidad and Tobago, Nigeria, and Egypt were assumed to be in the form of LNG. Algeria was expected 

to export two-thirds by pipeline and the rest as LNG. More than 90 percent of Libya’s gas exports was also expected to be transported by pipeline.

Figure 12. Graph showing estimated costs by region of developing, producing, and transporting stranded gas destined 

for Europe’s markets to coastal transshipment locations. Curves show costs for north Africa and two regions in the 

Atlantic Basin—(1) Nigeria and (2) Venezuela and Trinidad and Tobago. Also shown is the sum of the three areas’ curves, 

or total cost estimates as of early 2008 and in constant 2008 dollars. Table 11 shows costs for onshore and offshore 

stranded gas in each country in these three regions. 
Landed Costs of Stranded Gas for Europe’s Markets 31

Export gas from the stranded gas fields of Venezuela and Trinidad and Tobago was assumed to be transported to the LNG

complex at Point Fortin, Trinidad.13 The stranded gas fields in Trinidad and Tobago are offshore, and about 40 percent of Venezuela’s stranded gas is offshore in the same area. Overall, Venezuela accounts for just over half of the 63 TCF of total stranded

gas (table 10). Figure 12 shows that at a transfer price of $3 per thousand cubic feet (MCF) delivered to the LNG plant at Point 

Fortin, 30 TCF of the identified stranded gas could be commercially developed, and at $5 per MCF at the plant, 47 TCF could

be developed. If one assumes that the volumes could be produced over a 25-year period, the additional daily rate of production 

would represent 3.3 and 5.2 BCF/D of gas into the LNG plant. Alternatively, if one considers only the gas from Trinidad and 

Tobago as readily accessible to Europe, the commercial volume at $3 per MCF would be 9.8 TCF (1.1 BCF/D), and at $5, it 

would be 19.9 TCF (2.2 BCF/D) (table 11). 

Figure 12 also shows the estimated costs of developing and delivering gas from onshore and offshore stranded gas fields

in Nigeria to the LNG complex at Bonny, Nigeria. Produced gas from stranded fields was assumed to be collected at hubs at

Forcados and Bonny (fig. 3). Gas collected at Forcados was assumed to be transported by pipeline about 270 mi overland to

the Bonny liquefaction complex. At inlet gas prices of $3, about 25 TCF (2.7 BCF/D) of gas from onshore stranded fields and

10 TCF (1.1 BCF/D) of gas from offshore fields were estimated to be commercially developable (table 11). Similarly at $5 per

MCF, the estimated commercial volumes were 26.8 TCF (2.9 BCF/D) of onshore gas and 17.1 TCF (1.9 BCF/D) of offshore

gas.

The estimated resource cost function associated with north African stranded gas (fig. 12) included costs of field development, extraction, and transport to the coastal locations of existing LNG plants or trans-Mediterranean pipelines (see fig. 2). The

lowest cost stranded gas fields are located in onshore Algeria and Libya. At $3 per MCF and $5 per MCF, there were estimated

to be about 54 TCF and 76 TCF that could be produced commercially from Algeria, Libya, and Egypt and transported to a

coastal transshipment location (table 11). If this volume of gas were produced over a 25-year period, additional production 

would amount to 5.8 BCF/D and 8.3 BCF/D. 

The cost of delivering pipeline gas from Mellitah, Libya, to Gela, Italy, was computed by applying the technical data and 

cost estimates from the GreenStream pipeline (fig. 9) with the common fiscal assumptions. The estimated tariff is $2.91 per

MCF. The cost for transporting gas along the route of the planned GALSI pipeline from El Kala, Algeria, to Italy (fig. 9) is

estimated to be $2.90 per MCF. Alternatively, the cost of the service tariff to transport the planned limited volume of gas along 

the MEDGAZ route (fig. 9) from Beni Saf, Algeria, to Almeria, Spain, was estimated at $1.60 per MCF. If one assumes that the

cost of pipeline delivery from north Africa to Europe is not more than $3.00 per MCF and each cubic foot of gas has a calorific

value of 1,070 British thermal units (Btu), the cost of delivery is about $2.84 per million British thermal units (MMBtu). If only

volumes of gas from Algeria and Libya are available for pipeline shipment, then at $3.00 per MCF, 45 TCF (table 11) could be 

developed and then delivered by pipeline to southern Europe at a cost of $5.84 per MMBtu. 

13Some of the LNG trains in the Point Fortin LNG complex are merchant trains and will liquefy the gas for a toll.

Table 11. Estimated cost by country in north Africa and the Atlantic Basin for developing, producing, and transporting stranded gas 

destined for Europe’s markets to coastal transshipment locations.

[$/MCF, dollars per thousand cubic feet in constant 2008 dollars; TCF, trillions of cubic feet]

Delivered 

cost at transshipment location 

($/MCF)

Onshore Offshore

Algeria

(TCF)

Libya

(TCF)

Nigeria

(TCF)

Venezuela

(TCF)

Libya

(TCF)

Egypt

(TCF)

Nigeria

(TCF)

Trinidad & 

Tobago

(TCF)

Venezuela

(TCF)

1.00 14.9 10.0 17.1 0.0 0.0 0.0 4.4 0.0 6.9

2.00 23.3 14.3 24.1 13.3 0.0 0.0 7.9 0.0 6.9

3.00 30.5 14.8 25.0 13.8 0.0 8.8 10.2 9.8 6.9

4.00 40.4 16.3 26.0 14.2 0.0 12.2 15.9 17.9 9.5

5.00 44.3 16.7 26.8 14.2 3.2 12.2 17.1 19.9 13.4

6.00 45.5 17.0 26.9 14.2 3.2 14.1 17.1 21.9 15.2

7.00 46.7 17.2 27.1 14.4 8.6 14.5 20.1 26.6 15.2

8.00 48.9 17.3 27.4 14.4 10.6 15.7 20.1 28.6 16.1

9.00 49.1 17.5 27.7 14.5 10.6 20.0 20.1 30.4 16.1

10.00 49.2 17.6 27.7 14.5 10.6 21.3 20.8 30.4 16.1
32 Role of Stranded Gas in Increasing Global Gas Supplies

Table 12. Estimated cost of liquefying and transporting natural gas as LNG from the source country to the destination regasification 

facility if the process gas cost were $3.00 per thousand cubic feet.

[$/MMBtu, dollars per million British thermal units in constant 2008 dollars]

Source country Destination Sailing distance

(nautical miles)

Landed cost ($/MMBtu)

12%

rate of return

9%

rate of return

Trinidad and Tobago South Hook, UK 3,603 8.82 7.76

Gibraltar, Spain 3,403 8.74 7.69

Nigeria South Hook, UK 3,797 8.89 7.82

Belgium 4,187 9.04 7.94

Egypt South Hook, UK 2,791 8.51 7.50

La Spezia, Italy 1,434 7.99 7.08

Algeria South Hook, UK 1,244 7.92 7.02

La Spezia, Italy 682 7.71 6.85

Libya South Hook, UK 2,377 8.35 7.37

La Spezia, Italy 1,188 7.90 7.01

Across Europe, various destinations accept LNG shipments. The liquefaction complex includes processes for gas conditioning, cooling, and storage and has facilities to load the LNG on specially designed seagoing tankers. A discussion of the cost 

analysis is presented in appendix 3. Nigeria, Trinidad and Tobago, and Egypt have modern LNG complexes that are already considered to be of the size needed to take advantage of scale economies. It was therefore assumed that increments to LNG capacity 

would be accomplished by adding a train that could produce 5 million metric tons per year (MTY). These trains are sufficiently

large that additional storage and improved loading facilities are likely to be required. Table 11 shows that each of the three countries had at least the minimum volume of 7.1 TCF in stranded gas to supply an additional 5-MTY train for 25 years.

All the gas marketed to Europe from Egypt and the Atlantic Basin countries described above is in the form of LNG. The 

LNG from Trinidad and Tobago and Nigeria was assumed to be marketed at South Hook, United Kingdom (UK). LNG from 

Egypt, Algeria, and Libya was assumed to be marketed in South Hook, UK, or La Spezia, Italy. Table 12 shows the cost of the 

landed gas based on an inlet gas price of $3.00 per MCF to the plant. The table shows the originating country in the first column, the destination in the second, the sailing distance (nautical miles, nmi) in the next column, and then the landed cost of gas 

depending on whether the required return was 12 percent or 9 percent for liquefaction and shipping components of the LNG 

chain. Calculations were based on the fiscal assumptions and capital costs described in appendix 3. For the LNG base case of

a 12-percent required return, landed costs range from $7.71 to $9.04 per MMBtu. For north African suppliers, it was much

less costly to deliver gas to southern Europe than to South Hook, UK. However, the costs for Algerian and Libyan LNG are 

greater than costs of pipeline gas because the costs of liquefaction and tanker transport exceed the pipeline transport cost. If one 

assumed an LNG plant inlet gas price of $3.00 per MCF, the actual unit costs of liquefying gas and transporting the LNG across 

the Mediterranean would be about $4.28 per MMTBU. If the regasification cost averaged about $0.50 per MMBtu, then LNG

landed costs would exceed pipeline transport costs by about $1.94 per MMBtu. 

For a representative LNG plant at the same scale, same fiscal assumptions, and having gas cost of $3.00 per MCF at the

LNG plant, with the LNG shipped 2,000 nmi to market, the supply chain costs are the following: gas inlet cost, 36 percent;

liquefaction cost, 52 percent; and transportation from plant to market, 12 percent. Reducing the capacity of the liquefaction

trains progressively increases the share of liquefaction costs because scale economies are lost. Additional computations showed 

sensitivity of delivered cost to the assumed required after-tax rate of return, inlet gas cost, and shipping distance. The last 

column in table 12 shows that if the required after-tax return were reduced from 12 to 9 percent, then landed prices would 

decline by about 12 percent. A sensitivity study shows that for an increase in the LNG plant’s process gas costs of $1 per MCF,

the landed cost would increase by about $1.15 per MMBtu assuming the 5-MTY train and a 2,000-nmi trip to market. 
Landed Costs of Stranded Gas for Europe’s Markets 33

Table 13. Estimated cost of developing, producing, and transporting gas from stranded gas fields in Russia by petroleum 

province or producing area to the border of the European Union at Uzhhorod, Ukraine.

[$/MCF, dollars per thousand cubic feet in constant 2008 dollars; TCF, trillions of cubic feet. Numbers may not add up due to rounding]

Delivered 

cost

($/MCF)

Onshore Offshore

Total

West Siberia (TCF)

(TCF)

TimanPechora

(TCF)

Volga-Ural

(TCF)

Caspian 

(TCF)

West Siberia 

(TCF)

Caspian 

(TCF)

4.00 0.0 0.0 0.0 0.0 0.0 0.0 0.0

5.00 0.0 0.0 0.8 0.5 0.0 0.0 1.3

6.00 0.0 8.0 1.9 0.5 0.0 0.0 10.4

7.00 226.6 13.6 2.0 0.7 0.0 5.9 248.9

8.00 439.3 15.0 2.0 0.7 0.0 5.9 463.0

9.00 492.6 15.0 2.5 0.7 0.0 5.9 516.7

10.00 509.5 15.0 2.5 0.7 0.0 7.8 535.6

Gas from Russia and Central Asia 

Figure 10 shows the major gas pipeline delivery routes to markets in Europe from Russia and central Asia. Central Asian

gas producers have limited options to transport gas to western markets. Central Asian producers are required to sell gas to Gazprom where it enters the Russian pipeline system. Gazprom will resell the gas to domestic or European customers. Azerbaijan is

the only central Asian producer that currently has the ability to move gas through Turkey and to sell directly to Europe. The estimates of the cost of transporting the additional supplies from stranded gas are based on “the cost of service” procedures. Tariffs

are for new pipelines that would be located along the Gazprom right-of-way. Table 10 and figure 4 show that the largest volumes

of Russia’s stranded gas inventory that was evaluated for Europe’s markets are located in the arctic areas of the West Siberian

Basin. Table 10 shows that only 42 TCF of the 293 TCF of central Asian gas evaluated for Europe is in Azerbaijan.

Figure 13 is reproduced from Attanasi and Freeman (2012a), and table 13 shows corresponding gas volumes available at 

landed costs up to $10 per MCF. Figures 13A and 13B show that for Russia, the primary major gas tranche of 227 TCF from

West Siberia’s Yamal Peninsula has a threshold delivered cost of $7.00 per MCF. There are small volumes of gas up to that entry

cost, but their sum is less than 22 TCF.14 This analysis assumed an overland route where Yamal gas would flow in pipelines

adjacent to the existing Yamal–Europe, Northern Lights pipeline systems (fig. 10). The cost would be about $0.69 per MCF

greater for a route across the Baltic Sea along the Nord Stream pipeline to Germany assuming the “cost of service” procedure for

computing tariffs. Table 13 shows the estimated costs that must be incurred in developing, producing, and transporting various 

quantities of gas from stranded gas fields in Russia by producing area.

Figures 13C and 13D show the estimated cost of delivered stranded gas to Europe from central Asia. The figures show that

the principal tranches of gas from Azerbaijan and Turkmenistan have threshold delivered costs of $4.50 per MCF and $5.00 per 

MCF, respectively. Although the western areas of Kazakhstan and Uzbekistan can deliver gas at a somewhat lower cost, the gas 

volumes are less than 10 TCF. Table 14 shows the estimated cost that must be incurred in developing, producing, and transporting various quantities of gas from stranded gas fields in central Asia by country. The extra costs associated with gas development, production, and pipeline transportation under severe arctic conditions are the reasons why the estimated delivered cost for 

the Yamal gas from Russia is greater than costs for the two principal tranches from central Asia.15

Transportation accounts for a large component of the delivered costs. The estimated delivered cost is $7.00 per MCF at

Uzhhorod, Ukraine, from Yamal stranded gas fields. About 82 percent of the delivered cost is attributable to transportation.

About 75 percent of the $5.00 per MCF threshold delivered costs at Uzhhorod, Ukraine, from the large tranche of Turkmeni gas

in the Amu Darya Basin is ascribed to transportation. 

14In particular, there are 14 TCF from the Timan-Pechora Basin petroleum province, 6 TCF from Caspian fields, and 2 TCF from the Volga-Ural Region (fig. 4).

15Pipeline distances from the Yamal field to Uzhhorod, Ukraine, are between 2,300 and 2,600 miles (mi). Uzhhorod is 2,100 mi from the principal field in

Azerbaijan and 2,300 mi from the Turkmenistan field.
34 Role of Stranded Gas in Increasing Global Gas Supplies

Figure 13. Graphs showing estimated costs by region of developing, producing, and transporting stranded gas destined for Europe’s 

markets to the market point at the European Union border at Uzhhorod, Ukraine. A, Resource cost curves for Volga-Ural, Caspian, and 

Timan-Pechora provinces. B, Resource cost curves for western Siberia and the total stranded Russian gas resource from the above 

provinces. C, Resource cost curves for Kazakhstan, Uzbekistan, and Azerbaijan. D, Resource cost curves for Turkmenistan and the total 

stranded gas resource in central Asia from the four countries. Cost estimates as of early 2008 and in constant 2008 dollars. Horizontal 

scales vary. Figure modified from Attanasi and Freeman (2012a). 
Landed Costs of Stranded Gas for Europe’s Markets 35

Figure 13. Continued.
36 Role of Stranded Gas in Increasing Global Gas Supplies

Table 14. Estimated cost of developing, producing, and transporting gas from stranded gas fields 

in central Asia by country to the border of the European Union at Uzhhorod, Ukraine.

[$/MCF, dollars per thousand cubic feet in constant 2008 dollars; TCF, trillions of cubic feet. Numbers may not add up

due to rounding]

Delivered cost

($/MCF)

Azerbaijan

(TCF)

Turkmenistan 

(TCF)

Uzbekistan 

(TCF)

Kazakhstan 

(TCF)

Total

(TCF)

3.10 0.0 0.0 4.7 0.0 4.7

4.00 0.0 0.0 4.7 4.4 9.1

5.00 41.9 181.3 12.9 7.6 243.7

6.00 41.9 196.0 17.8 8.3 263.9

7.00 41.9 197.2 19.9 8.8 267.7

8.00 41.9 200.3 23.4 8.8 274.2

9.00 41.9 204.4 25.7 8.9 280.9

10.00 41.9 206.5 28.1 8.9 285.3

Implications for Meeting Europe’s Future Demand for Imported Gas

There are sufficient gas resources in the stranded gas fields in Russia, central Asia, north Africa, and the Atlantic Basin

to sustain the higher gas import demand estimated for Europe during the next several decades. If markets are competitive, 

these supplies could be available at costs that are well within the historical experience of Europe’s gas users. During the period

from 2008 to 2010, average pipeline gas prices to Hungary ranged from $9.02 to $11.97 per MMBtu, and LNG prices to Spain

averaged from $7.14 to $9.22 per MMBtu (International Energy Agency (IEA), 2011). In addition, LNG costs shown in table

12 (which assumes an LNG plant input gas price of $3 per MCF) are competitive with Russian threshold pipeline prices. The

resource cost functions of figure 12 are important in terms of comparing the cost of north African gas supplies by pipeline with

costs of supplies from Russia and central Asia. North African countries of Algeria and Libya have 37 TCF of stranded gas that

can be commercially produced and delivered to southern Europe at a cost of $5.00 per MCF assuming a $3 per MCF trans-Mediterranean pipeline tariff. The discussion above noted that for each $1 change in the inlet gas cost per MCF to the LNG plant, the 

landed costs of the LNG in Europe would change by $1.15 per MMBtu. If one drops the LNG plant inlet gas cost to $2.00 per 

MCF, calculated delivered costs would all be less than $8 per MCF and would be competitive with Russia’s costs. The European Union is quite concerned with security of supply as a policy and the consequences of a single supplier having a significant

market share. Relative comparability of costs suggests that it is not necessary to accept wide price differences among suppliers

to obtain diversity of supply.

From a security viewpoint, other risks are not trivial. In all cases, the supply chain from the gas field to the European market is long. In the case of Russia and central Asia, supply can be disrupted by disputes with transit countries. The additional step

of liquefaction and the special transport of LNG require large investments from the suppliers unless prospective purchasers take 

significant equity positions in the projects. However, such equity investments carry their own risks, which depend on the stability and reliability of their partners. With the exception of Trinidad and Tobago, the role of the host government as represented by

its national oil and gas company is important in terms of any risk calculation. Risk mitigation measures may reduce the required

after-tax return on investment. For example, table 12 shows the effect of reducing the required return from 12 to 9 percent on the 

threshold price necessary for the LNG project to be commercial.

Landed Costs of Stranded Gas for Asia’s Markets

Gas from Russia and Central Asia

The cost of delivered gas to Shanghai, China, was calculated for two clusters in the West Siberian Basin (fig. 5). The northern cluster, holding 92 TCF in stranded gas fields, was also evaluated for delivery to Europe in a section above. However, its

removal from consideration for delivery to Europe does not materially affect the conclusions of the previous section. Its initial 

entry cost to Europe is $7.70 per MCF with a tranche of 39 TCF. For the analysis of these two clusters in markets of Asia, it is

assumed that the produced gas from these fields would be transported south to the West-East China pipeline and then southeast

to Shanghai. Stranded gas in the gas field clusters from eastern Siberia (fig. 5) was also evaluated for the Shanghai market.
Landed Costs of Stranded Gas for Asia’s Markets 37

Figure 14. Graph showing estimated costs of developing, producing, and transporting stranded gas 

to Shanghai, China, from the West Siberian Basin, eastern Siberia, and central Asia (Turkmenistan, 

Uzbekistan, and Kazakhstan). Cost estimates as of early 2008 and in constant 2008 dollars. Figure 

modified from Attanasi and Freeman (2012b).

The gas from these clusters would be collected along the pipeline that originates near Irkutsk. The hypothetical pipeline would 

collect gas within Russia, moving gas northeast and then south to enter China near Blagoveshchensk, Russia (fig. 11). The gas

would then flow directly south to Beijing and southeast to Shanghai. Estimates were also made of the cost of delivered gas to

Shanghai from central Asian producers located east of the Caspian Sea. The Turkmenistan-China pipeline currently delivers gas 

from the Amu Darya Basin in Turkmenistan to China’s West-East pipeline at the Kazakhstan-China border, traversing Uzbekistan and Kazakhstan. Additional pipelines are expected to be located along the same right-of-way of the Turkmenistan-China 

pipeline to increase exports from Turkmenistan and allow gas exports from Kazakhstan and Uzbekistan. 

The results of these delivered cost computations reproduced from Attanasi and Freeman (2012b) are expressed as resource 

cost functions in figure 14. If one considers only clusters with at least 10 TCF of gas, the delivered costs for the West Siberian

Basin stranded gas clusters are 20 to almost 35 percent greater than the cost of gas from eastern Siberia. Though the northern 

West Siberian Basin stranded field cluster has larger fields, their location near the Arctic Circle results in much higher extraction and pipeline transportation costs than costs for the Amu Darya Basin of central Asia, for example (fig. 5). Furthermore, the

distance to Shanghai is almost 4,200 mi compared to 3,500 mi from the Amu Darya Basin and about 2,500 mi from Russia’s

stranded gas in eastern Siberia (fig. 11).

Liquefied Natural Gas from Southeast Asia, Australia, and Russia 

Indonesia, Malaysia, and Australia export gas as LNG because their primary markets are overseas. Although Indonesia 

has exported LNG since the 1970s, new LNG projects have evoked civil unrest because the general population wants the gas

directed to domestic markets. The government now places controls on such projects. Except for the stranded gas fields located

near the Donggi-Senora project, the cost analysis for all the evaluated stranded gas field clusters shown for Indonesia, Malaysia,

and Australia (figs. 6 and 7) assumed that process trains would be added to existing LNG facilities or facilities under construction. The locations of these plants and distances to the Asian target markets are shown in table A3–1. Liquefaction plants located

outside of North America with corresponding capacity ratings are listed in table A3–2. Table A3–3 shows location and capacity

of liquefaction plants under construction in Southeast Asia and Oceania that could serve gas markets in Asia. New trains were 

assumed to be at a scale that was consistent with the plant. 
38 Role of Stranded Gas in Increasing Global Gas Supplies

Figure 15. Graph showing estimated costs by region of developing, producing, and transporting 

stranded gas to coastal LNG plant locations. Curves show costs for Indonesia, Malaysia, Australia, 

and Russia. Cost estimates as of early 2008 and in constant 2008 dollars. Figure modified from 

Attanasi and Freeman (2012b).

Resource cost functions were developed for the stranded gas fields assigned to each LNG plant location. These functions

were similar to those developed for the gas producers in the Atlantic Basin and north Africa. The Malaysia plant is in Bintulu (fig. 6). A Russian plant using gas from eastern Siberia is planned for Vladivostok (fig. 11). Indonesia and Australia have

multiple plants (figs. 6 and 7). These functions were aggregated to the country level and are presented in figure 15. The shape

and position of the curves reflect the numbers and sizes of the stranded gas fields. The cost functions show that at a cost of $3

per MCF at the LNG plants, the economically recoverable resources are 31 TCF in Australia, 23 TCF in Malaysia, and 21 TCF 

in Indonesia. Given the common fiscal and economic assumptions imposed in this analysis, it will require $5.80 per MCF to

recover the full costs of developing, producing, and transporting gas from stranded fields located in the eastern Siberian basins

to Vladivostok. Transportation from the stranded fields to Vladivostok accounts for about 80 percent of the cost of the initial

tranche of gas. For Australia, Indonesia, and Malaysia, more than 90 percent of the gas in stranded fields evaluated was offshore,

and so the transport costs to the coastal LNG location were small.

In contrast to the European market, the Asian market has fragmented demand centers that are not at all connected by pipelines. Consequently, the costs of delivering LNG to market were computed for specific regasification terminals in China, India,

Japan, and South Korea. In table 15, the column labeled “First tranche LNG inlet cost” has the unit costs of developing, producing, and delivering the lowest cost tranche of gas assigned to each LNG complex to the trains initially added. The size of the 

tranche is the volume of gas required to operate the new train over a 25-year period. 

Additional trains at a given complex are assigned progressively higher cost resources. Table 16 shows the resource costs 

associated with developing, producing, and transporting stranded gas to the operating and planned LNG complexes listed. 

Excluding the gas supplying the planned Vladivostok plant, almost 90 percent of the cumulative gas can be delivered to LNG 

plants for less than $6 per MCF. In table 15, the estimated lowest cost tranche of stranded gas from the basins in eastern Siberia 

delivered to Vladivostok is $5.80 per MCF. 

Tables 15 and 16 can be used to estimate the landed cost at any of the market locations for additional tranches from a 

particular supplier. For example, it is assumed that the expansion of LNG capacity at each supply node occurs by adding trains 

of the same size as listed in table 15, which provides landed costs at market of the initial tranche of gas. Table 16 shows how 

much LNG plant process gas cost will increase as additional resources are committed when additional process trains are added. 

A sensitivity of the analysis shows that for every dollar of increase per MCF of gas at the LNG plant, the delivered cost will 

increase $1.16 per MMBtu (based on a distance of 3,000 nmi to market). At Withnell Bay, the initial tranche of gas is $1.80 and

each additional train requires a commitment of 6.3 TCF. Table 16 shows that it would actually require $3.50 per MCF to bring 

the extra gas needed to supply the additional train. The landed cost at Shanghai for the second tranche of gas using the stranded 

gas at Withnell Bay is about $10.58 MMBtu (that is, 1.16 × $1.70 + $8.61 = $10.58).
Table 15. Delivered threshold prices of the first tranche of gas as liquefied natural gas (LNG) from stranded gas fields in Australia, Malaysia, Indonemarkets.[The first tranche is the volume of stranded gas that must be produced to operate an additional train at the capacity shown for a 25-year period. MTY, millions of metric tons per $/MCF, dollars per thousand cubic feet in constant 2008 dollars; $/MMBtu, dollars per million British thermal units in constant 2008 dollars]

LNG complex

 (figs. 6, 7, 11)

Additional train 

capacity

(MTY)

Volume 

required to 

operate train for 

25 years

(TCF)

First tranche

LNG inlet cost

($/MCF)

Liquefaction 

cost 

($/MMBtu)

 Delivered cost first tranche 

Shanghai, 

China

Yokohama, 

Japan

Inch

South 

Australia (fig. 7)

Withnell Bay 4.4 6.3 1.80 5.27 8.61 8.72 8.Browse (proposed) 4.0 5.7 3.50 5.76 10.67 10.78 10.Darwin 3.6 5.1 2.40 5.83 9.51 9.63 9.Gladstone 4.0 5.7 3.30 5.73 10.79 10.68 10.

Malaysia (fig. 6)

Bintulu 3.4 4.8 1.50 4.83 7.22 7.45 7.

Indonesia (fig. 6)

Blang Lancang 1.6 2.3 5.30 5.23 11.73 12.01 11.Tangguh 3.8 5.4 2.60 4.79 8.40 8.51 8.Donggi-Senoro 2.1 3.0 3.40 6.09 10.49 10.62 10.Bontang 2.8 4.0 4.10 4.16 9.26 9.40 9.

Russia (fig. 11)

Vladivostok (proposed) 6.0 8.5 5.80 6.23 12.57 12.55 12.
Table 16. Estimated cost of developing, producing, and transporting gas to various operating and planned LNG complexes. [$/MCF, dollars per thousand cubic feet in constant 2008 dollars; LNG, liquefied natural gas; TCF, trillions of cubic feet] Delivered cost at transshipment location ($/MCF) Australia Malaysia Indonesia 

Withnell Bay (TCF) Browse (TCF) Darwin (TCF) Gladstone (TCF) Bintulu (TCF) Arun at Blang Lancang (TCF) Tangguh (TCF) Donggi- Senoro (TCF) Bon

(T

1.00 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.50 0.0 0.0 0.0 0.0 7.7 0.0 0.0 0.0 2.00 8.3 0.0 0.0 1.8 16.2 0.0 0.0 0.0 2.50 11.6 0.0 8.4 4.1 20.4 0.0 0.8 0.0 3.00 11.6 0.0 15.0 4.1 23.4 1.3 15.2 0.8 3.50 15.6 12.8 22.5 5.8 23.4 1.3 15.2 4.3 4.00 20.2 12.8 22.5 5.8 32.5 1.8 17.7 4.3 4.50 25.8 12.8 22.5 5.8 35.1 1.8 17.7 4.3 5.00 25.8 12.8 25.4 6.6 35.1 1.8 18.7 4.4 5.50 25.8 12.8 28.4 6.6 36.6 3.3 19.6 4.4 6.00 28.7 19.9 28.4 6.6 36.6 3.3 19.6 4.4 6.50 31.9 19.9 29.4 6.6 36.6 3.3 19.6 4.4 7.00 31.9 19.9 33.3 7.6 39.6 3.3 19.6 4.4 7.50 31.9 19.9 33.3 7.6 41.4 3.3 19.6 4.4 8.00 31.9 19.9 33.3 7.6 41.4 3.3 19.6 4.4 8.50 31.9 19.9 33.3 7.6 41.4 3.4 19.6 4.4 9.00 31.9 21.4 33.3 7.6 42.5 3.7 19.6 4.4 9.50 31.9 21.4 33.3 7.6 43.3 3.7 19.6 4.4 

10.00 31.9 21.4 33.3 7.6 44.0 3.7 19.6 4.4 10.50 32.5 21.4 33.3 7.6 44.0 3.7 19.6 4.4 

11.00 33.9 21.4 33.3 7.6 44.0 3.7 19.6 4.4 11.50 36.0 21.4 33.3 7.6 44.0 3.7 19.6 4.4 

12.00 36.3 21.4 33.7 7.8 44.0 3.7 19.6 4.4 12.50 36.3 21.4 33.7 8.0 44.0 3.7 19.6 4.4 13.00 37.0 21.4 33.7 8.0 44.0 3.7 19.6 4.4 13.50 38.0 22.0 33.7 8.0 44.0 3.7 19.6 4.4 14.00 38.0 22.0 33.7 8.0 44.0 3.7 19.6 4.4 14.50 38.0 22.0 33.7 8.0 44.7 3.7 19.6 4.4 15.00 38.0 22.0 34.1 8.0 44.7 3.7 19.6 4.4 15.50 38.0 22.2 34.1 8.0 45.6 3.7 19.6 4.4 16.00 38.0 22.2 34.5 8.0 46.2 3.7 19.6 4.4 
Conclusions and Implications 41

Implications for Meeting Asia’s Future Demand for Imported Gas

The stranded gas resources evaluated in Southeast Asia and Australia amount to 215 TCF. About 170 TCF of this gas can

be delivered to markets in Asia at landed costs that are within the landed price ranges of historical experience. Average annual 

prices for Japan from 2009 to 2011 ranged from $9.06 to $14.73 per MMTBU (BP, 2012). Based on data from figure 14, at a

delivered cost of $14 per MMBTU (almost $15 per MCF) to Shanghai, there is another 101 TCF in stranded fields in basins of

eastern Siberia that could be commercially developed, and about 93 TCF from the West Siberian Basin. The distance from Turkmenistan’s Amu Darya fields to Uzhhorod, Ukraine, is about 2,300 mi, whereas the distance to Shanghai is just over 3,500 mi.

However, the market prospects for commercial development of central Asia’s stranded gas favor Asia, and in particular, China,

because the gas transportation infrastructure is already in operation. Furthermore, the landed costs of Turkmeni gas in Shanghai 

are competitive with costs of LNG and gas from the basins in eastern Siberia. The additional gas could amount to another 240 

TCF even if some of the Turkmeni stranded gas is marketed to Europe. The gas in stranded gas fields that could be commercially

accessible to these four markets in Asia from the West Siberian Basin, the eastern Siberian basins, central Asia, and Southeast

Asia and Australia is just short of 600 TCF, a volume that substantially would meet the estimated alternative demand scenario of 

625 TCF, computed with the data from table 9 and the procedure described in footnote 11. 

Importers of gas in Asia have the same concerns about supply security as importers in Europe and are likely to opt for 

diversity of suppliers rather than to choose the single lowest cost supplier. Japan and South Korea have large industrial bases but 

small domestic gas resources. Conventional gas resources in China and India fall short of domestic consumption. Many of the 

entities purchasing pipeline gas and LNG are state-controlled companies that resell gas to local distribution and power companies. These may be units of national oil and gas companies or semi-governmental utilities. The units frequently purchase equity 

positions in the LNG facilities, and their governments may subsidize the financing of part of the LNG project. The establishment

of equity positions, assistance in financing, and the desire of the purchasers for long-term contracts are efforts to mitigate supply

risks. In many cases, the government-controlled purchasing entities are given exclusive rights to sell the gas by the importing 

country. With a captive domestic market, these entities face virtually no market risk. For the international oil and gas firm operating the LNG project, such an arrangement may assure high utilization of the plant, mitigate risks, and provide below-market 

financing.

 During the last few years, large conventional nonassociated gas discoveries in offshore Mozambique and Tanzania in east 

Africa have been announced. Wood Mackenzie Research and Consulting (2012) estimated that 100 TCF of natural gas has been

found and another 95 TCF is still undiscovered in these offshore areas. The development of these gas resources will be delayed 

because these countries currently lack physical infrastructure. The governments must also develop a legal framework and regulatory institutions for executing such large, high-risk projects. It is expected that Asia would be the primary gas export market 

because of proximity. 

Conclusions and Implications 

 The data and the cost analysis presented here suggest that for the European market and the markets examined in Asia, 

the development of stranded gas provides a way to meet projected demands for gas imports for the period from 2020 to 2040. 

Although this is a reconnaissance-type appraisal, it is based on volumes of gas that are associated with individual identified

fields. Individual field data were carefully examined. Some fields were not evaluated because it appeared that the gas would

likely be held off the export market. Indonesia’s Natuna D-alpha field, having roughly 40 TCF of natural gas and 100 TCF of

carbon dioxide, was not evaluated because of questions about applicability of current carbon sequestration technology. Most 

of the evaluated stranded gas can be produced and delivered to markets at costs comparable to historical prices. Moreover, the 

associated volumes of gas are sufficient to provide an interim supply while additional technologies are developed to unlock gas

diffused in shale and hydrates or while countries transition to making a greater use of renewable energy sources.

Growth in natural gas demand could be accelerated if governments provided economic incentives to reduce carbon dioxide 

emissions or if governments reduced the number of nuclear powerplants. The import demand projections for Europe and the 

Asian markets (U.S. Energy Information Administration, 2011b) predict that only relatively small volumes of gas from shale 

will be produced during the period from 2020 to 2040, despite the large resources assigned by Advanced Resources International

Incorporated (U.S. Energy Information Administration, 2011c). In addition to shale resources, there are other sources of gas that 

can significantly augment world supplies. The stranded gas in the Middle East was not included in the analysis. Qatar leads the

world in installed LNG capacity (table A3–2) and has the resources to sustain and expand supplies to Europe and Asia. Iran’s gas

in stranded gas fields amounts to 214 TCF.

The LNG industry was started as an effort by gas producers to monetize stranded gas. The emergence of the global LNG 

market provides the gas purchasers and suppliers a margin of flexibility that the pipeline deliveries of gas cannot offer. LNG
42 Role of Stranded Gas in Increasing Global Gas Supplies

contract provisions that now permit redirection of cargoes have been important to Japanese LNG purchasers in the aftermath of 

the March 11, 2011, earthquake and the related tsunami that caused the failure of the Fukushima Dai-ichi nuclear power station. The flexibility of destinations of LNG shipments has contributed to the breakdown of entry barriers in some markets. The

growth of LNG supplies has also challenged producers attempting to monopolize certain markets. A number of offshore or floating regasification terminals are now in operation where LNG tankers unload cargoes. The use of floating regasification reduces

the port infrastructure required for receiving LNG and gives buyers the opportunity to purchase LNG where port facilities are 

inadequate. 

Floating liquefaction plants are yet another technology extending LNG into new situations. These facilities have been 

designed but are not yet deployed. Commercial floating LNG facilities could expand the number of stranded gas fields that

could be commercially developed by reducing the minimum offshore field sizes considered for LNG development. The floating liquefaction facility could be relocated and reused as gas fields were depleted. Developers argue that floating facilities could

offer significant project cost reductions because the onshore plant, its site, pipeline infrastructure, and tanker loading and storage

facilities would not be needed. 

Acknowledgments 

The authors thank U.S. Geological Survey colleagues Robert Milici, Ricardo Olea, and Susan Tewalt for reviews, 

Elizabeth Good for editing, and Cathy Knutson for layout. 

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Appendix 1. Stranded Gas Resources in the Middle East 47

Appendix 1. Stranded Gas Resources in the Middle East

Distribution of Stranded Gas Resources

Figure	8	shows	the	locations	of	the	clusters	of	stranded	gas	fields	in	the	Middle	East.	Of	the	303	TCF	of	the	Middle	East	

stranded	gas	in	gas	fields	shown	in	table	2,	Iran	accounts	for	214	TCF,	or	71	percent	of	the	total.1	Table	A1–1	shows	stranded	gas	

in	gas	fields	and	stranded	gas	in	oil	fields	by	country	for	the	Middle	East.	In	2011,	Iran,	Israel,	Kuwait,	Oman,	and	the	United	

Arab	Emirates	(UAE)	imported	natural	gas	(BP,	2012).	Countries	having	stranded	gas	fields	that	have	dedicated	their	resources	

to	domestic	use	are	Israel	(3	TCF),	Syria	(4	TCF),	and	Kuwait	(10	TCF).	Table	A1–2	shows	the	field	size	distribution	of	the	

stranded	gas	fields	for	Iran,	Iraq,	Saudi	Arabia,	the	UAE,	Oman,	and	Yemen.	The	tables	show	Iran	accounting	for	the	largest	

stranded	fields	and	the	most	stranded	gas	in	all	the	Middle	East.	Well	over	90	percent	of	Iran’s	stranded	gas	is	in	large	fields.	Gas	

fields	reported	in	the	IHS	International	Petroleum	Exploration	and	Production	database	(IHS	Inc.,	2009)	for	Iraq,	Saudi	Arabia,	

the	UAE,	Oman,	and	Yemen	that	were	classified	as	stranded	were	all	smaller	than	6.14	TCF.	

	The	volume	of	stranded	associated	gas	in	oil	fields	is	greater	than	the	volume	of	gas	in	stranded	gas	fields.	For	the	oilexporting countries with large oil reserves, there is little incentive in terms of generating new revenues to explore and develop 

natural gas. Furthermore, for much of the exploration history, natural gas was not considered an economic commodity. Consequently, in the cases of Iraq and Saudi Arabia, for example, nonassociated gas reserves may increase when those governments 

direct exploration to target conventional gas prospects. Some of the nonassociated gas listed might be in low-permeability 

formations	or	might	have	significant	hydrogen	sulfide	contamination,	which	requires	the	application	of	sophisticated	production	

technology only available at high cost (Flower, 2008).

Prospects for Expanded Gas Exports 

Abu Dhabi of the UAE, Qatar, Oman, and Yemen currently export natural gas as LNG. The export of LNG from Abu Dhabi 

started	in	the	1970s.	The	Japanese	utility	Tokyo	Electric	Power	Company	(TEPCO)	contracted	to	buy	the	liquefaction	plant’s	

entire initial output and its expanded output (1994) when an additional train was added. The plant initially used associated gas, 

which	is	a	byproduct	from	oil	production.	Abu	Dhabi’s	oil	production,	however,	varies	with	the	allotments	assigned	to	it	by	the	

Organization of the Petroleum Exporting Countries (OPEC) because of its member status. Abu Dhabi imports pipeline gas from 

Qatar to assure that the LNG plants are utilized to meet their sales commitments (Flower, 2008). The Yemen liquefaction plant, 

with	a	capacity	of	6.7	MTY,	started	operation	in	2009	with	South	Korea	and	the	United	States	as	its	primary	initial	buyers.	The	

magnitude	of	proven	reserves	and	identified	stranded	gas	will	not	support	further	plant	expansion	(Flower,	2008).	The	Oman	

LNG	plant	complex	started	operation	in	September	2000	and	now	has	three	trains	with	a	total	capacity	of	10.7	MTY	(see	table	

A3–2).

Qatar	is	the	world’s	leading	LNG	exporter.	North	field	accounts	for	nearly	all	of	Qatar’s	nonassociated	gas.	However,	

in	2005,	Qatar	announced	a	moratorium	on	new	proposals	that	would	expand	gas	production	from	North	field	but	permitted	

completion of projects that had already been authorized (Flower, 2008). The purpose of the moratorium was to allow the Qatari 

authorities	to	study	the	performance	of	the	field	in	order	to	determine	whether	the	field	is	suffering	damage	from	overproduction.	

These studies will not be completed until after 2012, and then this additional information will be used to evaluate new development proposals. 

Although	Iran	has	significant	volumes	of	gas	in	stranded	gas	fields,	it	imports	pipeline	gas	from	Azerbaijan	and	Turkmenistan	to	supply	users	near	the	Caspian	instead	of	transporting	gas	from	its	Zagros	Fold	Belt	over	the	mountains.	Iran’s	domestic	

use	is	growing	rapidly	as	it	uses	gas	as	a	fuel	and	to	maintain	reservoir	pressures	in	depleting	oil	fields.	Nonetheless,	Iran	also	

seeks	export	markets	for	gas	in	its	stranded	gas	fields.	These	efforts	have	been	hindered	by	the	economic	sanctions	imposed	in	

response	to	Iran’s	nuclear	program	(U.S.	Energy	Information	Administration,	2012).	

In summary, while the long-term prospects for additional conventional gas supplies from the Middle East are promising, 

there are a number of barriers to expansion in the next 20 years. Much of the gas listed as reserve is associated gas and is used 

1

The	Middle	East	stranded	gas	total	excludes	Iran’s	South	Pars	field	(~360	TCF)	and	Qatar’s	North	field	(~900	TCF),	which	are	parts	of	the	same	field.	This	

single	gas	field	is	also	thought	to	hold	9	billion	barrels	of	recoverable	condensate	in	the	Iranian	portion	and	10	billion	barrels	of	recoverable	condensate	in	the	

Qatari	portion.	The	values	of	the	condensate	produced	exceed	the	netback	cash	flows	from	gas	sales.
48 Role of Stranded Gas in Increasing Global Gas Supplies

to either prolong the life of oil fields or serve domestic fuel demands such as for electricity generation and water desalinization.

The available nonassociated gas in some countries is used for feedstock in export-oriented petrochemical industries. The 

international sanctions imposed on Iran and the political tensions throughout the region have discouraged new investment. 

Table A1–1. Volumes of remaining recoverable stranded natural gas onshore and offshore in Middle East oil 

and gas fields by country.

[Gas volumes are in trillions of cubic feet (TCF). Field data through the end of 2008 are from IHS Inc. (2009). Dash (-), data not 

available. Numbers may not add up due to rounding]

Country1 Gas in gas fields Gas in oil fields

Onshore Offshore Total gas Onshore Offshore Total gas

Israel - 3 3 - - -

Iran 123 92 215 265 30 295

Syria 4 0 4 3 - 3

Iraq 13 0 13 77 - 77

Kuwait 10 - 10 33 5 38

Saudi Arabia 21 - 21 83 37 119

Qatar - - - - 13 13

United Arab Emirates 3 7 10 10 13 24

Oman 20 0 20 9 0 9

Yemen 8 - 8 6 - 6

 Middle East total 202 102 304 486 98 584

1

Turkey is not shown in this table because stranded gas volumes are less than 1 TCF.
Appendix 1. Stranded Gas Resources in the Middle East 49

Table A1–2. Distribution of gas by field size category for stranded gas in gas fields in Iran, Iraq, 

Saudi Arabia, the United Arab Emirates, Oman, and Yemen.—Continued

[Field data current through the end of 2008 are from IHS Inc. (2009). Country totals here differ slightly from those in 

table A1–1 because the minimum field size in this table is 0.048 TCF. Israel, Syria, Kuwait, and Qatar are not included

in this table because the volumes of stranded gas reported are small relative to domestic demand, and so exports are 

unlikely. TCF, trillions of cubic feet; BCF, billions of cubic feet]

Gas field size 

class range

(TCF)

Number of fields

Cumulative 

percentage of 

fields

Volume in size 

class 

(BCF)

Cumulative 

percentage of gas 

volume

Iran

 >49.2 0 0.0 0 0.0

24.6–49.2 3 7.1 108,000 50.4

12.3–24.6 2 11.9 34,301 66.4

6.14–12.3 2 16.7 14,715 73.2

3.07–6.14 8 35.7 33,997 89.1

1.54–3.07 4 45.2 8,592 93.1

0.768–1.54 9 66.7 9,818 97.7

0.384–0.768 5 78.6 2,999 99.1

0.192–0.384 5 90.5 1,436 99.8

0.096–0.192 4 100.0 500 100.0

0.048–0.096 0 100.0 0 100.0

 Total 42 214,358

Iraq

 >49.2 0 0.0 0 0.0

24.6–49.2 0 0.0 0 0.0

12.3–24.6 0 0.0 0 0.0

6.14–12.3 0 0.0 0 0.0

3.07–6.14 1 12.5 3,300 25.5

1.54–3.07 3 50.0 6,400 74.8

0.768–1.54 3 87.5 3,200 99.5

0.384–0.768 0 87.5 0 99.5

0.192–0.384 0 87.5 0 99.5

0.096–0.192 0 87.5 0 99.5

0.048–0.096 1 100.0 65 100.0

 Total 8 12,965

Saudi Arabia

 >49.2 0 0.0 0 0.0

24.6–49.2 0 0.0 0 0.0

12.3–24.6 0 0.0 0 0.0

6.14–12.3 0 0.0 0 0.0

3.07–6.14 0 0.0 0 0.0

1.54–3.07 3 14.3 8,400 39.5

0.768–1.54 6 42.9 8,000 77.2

0.384–0.768 6 71.4 3,050 91.5

0.192–0.384 6 100.0 1,800 100.0

0.096–0.192 0 100.0 0 100.0

0.048–0.096 0 100.0 0 100.0

 Total 21 21,250
50 Role of Stranded Gas in Increasing Global Gas Supplies

Table A1–2. Distribution of gas by field size category for stranded gas in gas fields in Iran, Iraq, 

Saudi Arabia, the United Arab Emirates, Oman, and Yemen.—Continued

[Field data current through the end of 2008 are from IHS Inc. (2009). Country totals here differ slightly from those in 

table A1–1 because the minimum field size in this table is 0.048 TCF. Israel, Syria, Kuwait, and Qatar are not included

in this table because the volumes of stranded gas reported are small relative to domestic demand, and so exports are 

unlikely. TCF, trillions of cubic feet; BCF, billions of cubic feet]

Gas field size 

class range

(TCF)

Number of fields

Cumulative 

percentage of 

fields

Volume in size 

class 

(BCF)

Cumulative 

percentage of gas 

volume

United Arab Emirates

 >49.2 0 0.0 0 0.0

24.6–49.2 0 0.0 0 0.0

12.3–24.6 0 0.0 0 0.0

6.14–12.3 0 0.0 0 0.0

3.07–6.14 1 9.1 4,200 41.6

1.54–3.07 1 18.2 2,000 61.5

0.768–1.54 2 36.4 1,994 81.2

0.384–0.768 1 45.5 400 85.2

0.192–0.384 5 90.9 1,389 99.0

0.096–0.192 1 100.0 105 100.0

0.048–0.096 0 100.0 0 100.0

 Total 11 10,088

Oman

 >49.2 0 0.0 0 0.0

24.6–49.2 0 0.0 0 0.0

12.3–24.6 0 0.0 0 0.0

6.14–12.3 0 0.0 0 0.0

3.07–6.14 3 9.4 12,035 59.7

1.54–3.07 0 9.4 0 59.7

0.768–1.54 2 15.6 2,750 73.4

0.384–0.768 5 31.3 2,185 84.2

0.192–0.384 8 56.3 1,816 93.2

0.096–0.192 7 78.1 931 97.9

0.048–0.096 7 100.0 431 100.0

 Total 32 20,148

Yemen

 >49.2 0 0.0 0 0.0

24.6–49.2 0 0.0 0 0.0

12.3–24.6 0 0.0 0 0.0

6.14–12.3 0 0.0 0 0.0

3.07–6.14 1 5.9 3,500 45.8

1.54–3.07 0 5.9 0 45.8

0.768–1.54 0 5.9 0 45.8

0.384–0.768 5 35.3 2,559 79.3

0.192–0.384 4 58.8 968 92.0

0.096–0.192 1 64.7 175 94.3

0.048–0.096 6 100.0 437 100.0

 Total 17 7,639
Appendix 2. Field Development, Production, and Transportation Cost Estimates 51

Appendix 2. Field Development, Production, and Transportation Cost Estimates

The onshore and offshore field development and production cost estimation scheme is from Attanasi and Freeman (2011).

Onshore Field Cost Estimation 

Capital and operating costs for a suite of model fields were computed at each size class and at all depth intervals for countries

having stranded gas by using QUE$TOR software (IHS Inc., 2008). The model field is a regarded as the representative field within

each size class. The QUE$TOR software cost estimates were country and basin specific and also took into account terrain, climate, and

typical capital equipment procurement strategies. Cost estimates included capital and operating costs of wells, processing facilities, and 

required supporting infrastructure. Processing facilities to remove natural gas liquids (NGLs) from the gas stream were also included in 

the model field equipment configurations, so that the separate gas and liquids pipelines may transport these products to their respective markets. Basic onshore field design specifications that represented the model gas fields are presented in table A2–1. In the absence

of detailed field plans, numerous simplifying assumptions were made in the preparation of costs. The QUE$TOR software (IHS Inc.,

2008) selected the equipment sizes and equipment configurations given a design concept based on the number of wells and the assumed

field production profiles. The QUE$TOR software also allowed specification and added costs of ancillary infrastructure required for

field development in areas with little infrastructure.

Offshore Field Cost Estimation 

The cost analysis for offshore fields required several phases. First, the QUE$TOR software (IHS Inc., 2008) was applied to

assemble a cost database for gas field configurations characteristic of the U.S. Gulf of Mexico for each field size class and water depth

category where gas has been found. Cost items included capital and operating costs for wells, platforms, and support facilities. A 

similar cost database was assembled for at least two model fields in different size classes and encompassing the water depth classes

at each study location (country and province) where the stranded gas field costs were to be estimated. Then country and province cost

indices were constructed by comparing cost estimates for the two size classes analyzed for each depth category in the Gulf of Mexico 

to corresponding costs for each study area. The indices were then used to estimate the study area’s costs of the other representative gas

field size classes not examined by using the Gulf of Mexico costs as the benchmark. For offshore fields, it was assumed that produced

gas and liquids were brought onshore to a coastal transshipment location where the gas enters an international pipeline or it is liquefied

as LNG and then shipped by seagoing tanker to market. Field design specifications and development concepts for offshore fields are

summarized in appendix table A2–2.

Transportation of Gas to Market 

Clusters of stranded gas fields were assembled on the basis of the spatial distribution or location of the fields to support the cost of

the hypothetical gas transportation infrastructure. A hub was located to minimize the sum of the costs of transporting the gas from field

feeder lines to the hub and the cost of larger pipe from the hub to a terminus. The unit cost (per MCF) for transportation declines dramatically with increases in the volume of gas transported, and so the hubs were centrally located among the fields served to maximize

the more efficient trunk line distance.

Daily flow rates of the feeder lines (field to hub) were based on the plateau production rate of the representative field for the field

size class. The nominal flow rate of the trunk line was based on the daily flow rate that would deliver the total volume of gas in the fields

serviced by the hub to a transshipment location during a 25-year period. This procedure was used for both onshore and offshore stranded 

gas fields. In cases where onshore pipeline infrastructure to the transshipment location already exists, it was assumed that the original

pipeline right-of-way was sufficiently large to allow a parallel regional structure to service the stranded gas. The development of the

stranded gas fields must bear the full cost of the new parallel line. Pipeline transportation facilities were assumed to be operated as regulated carriers. Tariffs are set to recover operating costs and invested capital, plus a 12-percent after-tax return on capital. A 50-percent net 

income tax rate was assumed. Invested capital is recovered through depreciation. 

Gas collected from fields into the designated hubs was transported to larger regional pipelines that terminate either at an LNG

plant on a coast or at the right-of-way of an international gas pipeline. The transport costs for computing delivery costs by pipelines 

to specific markets also were based on the assumption that newly constructed dedicated pipelines would be constructed along existing

rights-of-way. When pipeline distances of existing lines were not available, distances were estimated by using geographic information

system (GIS) tools. For hypothetical pipelines, pipeline distances were estimated by using the GIS tools applied to the posited routes 

in a piecewise linear fashion. For these routes, the calculated distance was increased by 30 percent to compensate for natural topography and the costs of creating a new right-of-way where bridges or tunnel construction would be required. Hypothetical pipelines were 

posited from Proskokovo, Russia, to China’s Second West-East pipeline and from field clusters in eastern Siberia to Beijing and to

Vladivostok, Russia (fig. 11).
52 Role of Stranded Gas in Increasing Global Gas Supplies

Table A2–1. Prototype model designs for onshore gas field development.

[BCF, billions of cubic feet; MMCF/D, millions of cubic feet per day]

Size class Reserves

(BCF)

Field life

(years)

Number of 

wells

Reserves per 

well 

(BCF)

Plateau

flow rate

(MMCF/D)

9 68 17 10 6.8 13.6

10 136 17 13 10.5 27.2

11 272 17 19 14.3 54.4

12 543 25 28 19.4 101

13 1,086 23 41 26.5 201

14 2,172 22 62 35.0 403

Table A2–2. Prototype model designs for offshore gas field development.

[BCF, billions of cubic feet; MMCF/D, millions of cubic feet per day; ft, feet]

Size class Reserves

(BCF)

Field life

(years)

Number of 

wells

Reserves per 

well 

(BCF)

Plateau

flow rate

(MMCF/D)

Development concept

Shallow water depth, 1–656 ft evaluated at 328 ft

9 68 17 9 7.6 13.6 1 platform

10 136 17 13 10.5 27.2 1 platform

11 272 17 20 13.6 54.4 1 platform

12 543 18 28 19.4 101 2 platforms

13 1,086 18 42 25.9 201 2 platforms

14 2,172 18 62 35.0 403 4 platforms

15 4,344 18 102 42.6 776 6 platforms

16 8,689 19 166 52.3 1,490 8 platforms

Medium water depth, 657–1,640 ft evaluated at 1,150 ft

9 68 17 9 7.6 13.6 Tension leg platform (TLP)

10 136 17 13 10.5 27.2 TLP

11 272 17 20 13.6 54.4 TLP

12 543 18 28 19.4 101 TLP

13 1,086 18 42 25.9 201 2 TLPs

14 2,172 18 62 35.0 403 2 TLPs plus 2 subsea wells

15 4,344 18 102 42.6 776 3 TLPs plus 12 subsea wells

16 8,689 19 166 52.3 1,490 6 TLPs

Deep water depth, >1,640 ft evaluated at 3,280 ft

9 68 17 5 13.6 13.6 TLP

10 136 17 8 17.0 27.2 TLP

11 272 17 11 24.7 54.4 TLP

12 543 18 16 33.9 101 TLP

13 1,086 18 24 45.3 201 TLP

14 2,172 18 36 60.3 403 1 spar buoy with 12 subsea wells tied back

15 4,344 18 54 80.4 776 2 spar buoys with 6 subsea wells tied back

16 8,689 19 82 106.0 1,490 3 spar buoys with 10 subsea wells tied back
Appendix 3. Estimation of Liquefaction Cost and the Transportation Costs of Liquefied Natural Gas 53

Appendix 3. Estimation of Liquefaction Cost and the Transportation Costs of 

Liquefied Natural Gas

Liquefaction Plant Complex

The sizes of plants that liquefy natural gas are commonly expressed in terms of millions of metric tons of liquefied natural

gas that can be produced annually based on 350 days of annual operation. An LNG complex consists of the plant made up of 

process trains that purify and liquefy the gas, storage facilities, and docking facilities for loading seagoing LNG tankers. Process 

components of a plant condition or purify the gas and then liquefy the gas by cooling. New, or greenfield, plants are more costly

to construct and operate than the equivalent capacity expansions of operating plants accomplished by adding process trains. 

Storage and docking facilities costs do not increase proportionately with the addition of another process train.

For new plants or plants where trains are added, gas liquefaction cost computations depend on the estimates of the capital 

or investment cost per metric ton of annual output capacity. According to Durr and others (2005), plants and single-process 

trains exhibit similar economies of scale. The data published by Durr and others (2005) were used to fit a generic scale and cost

relationship that approximated the six-tenths rule.1 A new plant complex with a single train having a capacity of 6 million metric 

tons per year (MTY) constructed in Australia (or North America or Russia, for that matter) was assumed to have a capital cost

of 1,025 U.S. dollars per metric ton (USD/t) of LNG output. The addition of a 6-MTY train with additional storage and dock 

facilities cost 850 USD/t of LNG output. Construction costs for plants and additional trains in Indonesia and Malaysia were 850 

and 700 USD/t of LNG, respectively, and the cost of refurbishing idle facilities was 500 USD/t of LNG output. For smaller scale

facilities, the cost per metric ton increased according to the fitted function from the data in Durr and others (2005).

The cost of liquefaction per MMBtu of plant output was calculated on the basis of a cost-of-service procedure. Annual 

operating cost (excluding feed gas) was assumed to be 4 percent of investment cost (Energy and Environmental Analysis, Inc., 

1988), plant life was 25 years, a 12-percent rate of return was required, and a net income tax rate of 50 percent was assumed 

with capital recovered from depreciation allowance. Transformation of input gas to output gas was also assumed to be 85 percent efficient (Energy and Environmental Analysis, Inc., 1988). It was assumed that all gas liquids would be removed at the field

level and sold by the operators so that the LNG plant would use dry gas, principally methane. 

Shipping Costs for Liquefied Natural Gas

Distances from the LNG plants to market ports were first calculated (see table A3–1). It was assumed that the LNG tanker

would have a sailing speed of 18 knots, a ship life of 20 years, a capacity of 140,000 cubic meters, and an initial cost of $270

million. It was also assumed the ship would be powered by boiloff LNG gas. Daily boiloff was assumed be equivalent to 0.125 

percent of the ship’s cargo capacity. The number of days per trip was calculated as the number of sailing days between ports

assuming a speed of 18 knots and a 3-day allowance per round trip for loading and unloading cargo. Tankers were assumed to 

operate 330 days per year. Insurance and maintenance were 1.3 percent and 1 percent of the ship’s value, respectively. Total

annual operating cost included insurance, maintenance, consumables, labor, and overhead, which was assumed to be 4.1 percent 

of the ship’s value (Energy and Environmental Analysis, Inc., 1988). Tariff rates were set to repay operation costs, pay taxes,

recover investment through depreciation, and provide a 12-percent after-tax rate of return on the investment. A 50-percent net 

income tax rate was assumed.

Existing and Potential Capacity for Liquefied Natural Gas Production

Table A3–2 shows the existing LNG capacity for plants in Southeast Asia and Oceania and Russia, the Middle East, Africa,

and South America. The Southeast Asia and Oceania region accounts for about 32 percent of the total of 279 MTY of LNG

capacity represented in this table. The Middle East and Africa account for 33 percent and 25 percent, respectively, of the total 

LNG capacity shown. Table A3–3 shows the additional capacity of LNG plants under construction in the Southeast Asia and

Oceania region. This includes 69.5 MTY for Australia, 6.6 MTY for Papua New Guinea, and 2.0 MTY for Indonesia.

1

If the scale of the reference plant is Sr with reference cost Cr and if Sp is the scale of a projected plant, the application of the six-tenths rule estimates the 

project cost, Cp, as Cp = Cr(Sr/Sp)0.6.
54 Role of Stranded Gas in Increasing Global Gas Supplies

Table A3–1. Estimated costs of transporting liquefied natural gas (LNG) from LNG complex to destination regasification facility and 

market.

[For comparisons, the distance from Withnell Bay, Australia, to South Hook, UK, is 11,090 nmi. $/MMBtu, dollars per million British thermal units in constant

2008 dollars; nmi, nautical miles]

LNG complex

(figs. 6, 7, 11) Source location

Yokohama, Japan Shanghai, China

Distance 

(nmi)

Transport cost 

($/MMBtu)

Distance 

(nmi)

Transport cost 

($/MMBtu)

Withnell Bay Pilbara, Western Australia 3,850 1.65 3,565 1.54

Browse (proposed) Kimberly, Western Australia 3,470 1.52 3,185 1.41

Darwin Darwin, Australia 3,164 1.40 2,879 1.29

Gladstone Queensland, Australia 3,797 1.65 4,083 1.76

Bintulu Sarawak, Malaysia 2,470 1.11 1,850 0.88

Blang Lancang Arun, Sumatra, Indonesia 3,371 1.48 2,689 1.20

Tangguh Irian Jaya, Indonesia 2,480 1.12 2,200 1.01

Donggi-Senoro Sulawesi, Indonesia 2,460 1.13 2,120 1.00

Bontang Kalimantan, Indonesia 2,570 1.14 2,220 1.00

Vladivostok (proposed) Vladivostok, Russia 952 0.52 998 0.54

LNG complex

(figs. 6, 7, 11) Source location

Incheon, South Korea Hazira, India

Distance 

(nmi)

Transport cost 

($/MMBtu)

Distance 

(nmi)

Transport cost 

($/MMBtu)

Withnell Bay Pilbara, Western Australia 4,001 1.71 3,691 1.59

Browse (proposed) Kimberly, Western Australia 3,621 1.58 3,925 1.70

Darwin Darwin, Australia 3,315 1.46 4,320 1.85

Gladstone Queensland, Australia 4,519 1.94 5,953 2.51

Bintulu Sarawak, Malaysia 2,286 1.05 3,133 1.36

Blang Lancang Arun, Sumatra, Indonesia 3,125 1.38 2,089 0.96

Tangguh Irian Jaya, Indonesia 2,636 1.18 4,498 1.89

Donggi-Senoro Sulawesi, Indonesia 2,556 1.17 4,121 1.79

Bontang Kalimantan, Indonesia 2,656 1.17 3,710 1.58

Vladivostok (proposed) Vladivostok, Russia 911 0.50 5,569 2.42
Appendix 3. Estimation of Liquefaction Cost and the Transportation Costs of Liquefied Natural Gas 55

Table A3–2. Existing LNG capacity outside North America.—Continued

[Data are from True (2012) except that Middle East data are from the International Group of Liquefied Natural Gas Importers (2011). BCF/D, billions of

cubic feet per day; LNG, liquefied natural gas; MTY, millions of metric tons per year; T1, train 1; 350 working days in a year. Numbers may not add up due to

rounding]

Country Liquefaction facility Number of trains Capacity

(BCF/D)

Capacity

(MTY)

Southeast Asia, Oceania, and Russia

Australia Withnell Bay, Northwest Shelf 5 2.2 16.4

Wickham Point, Darwin LNG 1 0.5 3.6

Burrup Peninsula, Pluto LNG 1 0.6 4.3

 Australia total 7 3.3 24.3

Brunei Lumut, Brunei LNG 5 1.0 7.2

Indonesia Blang Lancang, PT Arun1 2 0.5 3.5

Bontang, PT Badak 8 3.1 22.6

Bintuni, Tangguh LNG 2 1.0 7.6

 Indonesia total 13 4.8 33.7

Malaysia Bintulu MLNG 1 (Satu) 3 1.1 8.1

Bintulu MLNG 2 (Dua) 3 1.2 9.1

Bintulu MLNG 3 (Tiga) 2 0.9 6.8

 Malaysia total 8 3.3 24.0

Russia Sakhalin 2 2 1.3 9.6

Middle East

Abu Dhabi Das Island 3 0.8 5.6

Oman Qalhat (T1 & T2) 2 1.0 7.1

Qalhat (T3) 1 0.5 3.6

 Oman total 3 1.5 10.7

Qatar Ras Laffan (Qatargas 1: T1 & T2) 2 0.9 6.3

Ras Laffan (Qatargas 1: T3) 1 0.4 3.1

Ras Laffan (Qatargas 2: T1) 1 1.1 7.8

Ras Laffan (Qatargas 2: T2) 1 1.1 7.8

Ras Laffan (Qatargas 2: T3) 1 1.1 7.8

Ras Laffan (Rasgas 1: T1 & T2) 2 0.9 6.6

Ras Laffan (Rasgas 2: T1) 1 0.6 4.7

Ras Laffan (Rasgas 2: T2) 1 0.6 4.7

Ras Laffan (Rasgas 2: T3) 1 0.6 4.7

Ras Laffan (Rasgas 3: T1) 1 1.1 7.8

Ras Laffan (Rasgas 3: T2) 1 1.1 7.8

 Qatar total 13 9.5 69.1

Yemen Balhaf (T1 &T2) 2 0.9 6.7
56 Role of Stranded Gas in Increasing Global Gas Supplies

Table A3–2. Existing LNG capacity outside North America.—Continued

[Data are from True (2012) except that Middle East data are from the International Group of Liquefied Natural Gas Importers (2011). BCF/D, billions of

cubic feet per day; LNG, liquefied natural gas; MTY, millions of metric tons per year; T1, train 1; 350 working days in a year. Numbers may not add up due to

rounding]

Country Liquefaction facility Number of trains Capacity

(BCF/D)

Capacity

(MTY)

Africa

Algeria Arzew (GL1Z) 6 1.1 8.0

Arzew (GL2Z) 6 1.2 8.4

Arzew (GL3Z) 1 0.6 4.7

Arzew (GL4Z) 3 0.1 0.9

Skida (GL1K, GL2K) 3 0.5 3.5

 Algeria total 19 3.5 25.5

Libya Marsa-el-Braga 3 0.1 0.6

Egypt Damietta 1 0.7 4.8

Idku 2 1.0 7.2

 Egypt total 3 1.6 12.0

Nigeria Bonny Island (T1, T2, T3) 3 1.4 9.9

Bonny Island (T4, T5) 2 1.1 8.2

Bonny Island (T6) 1 0.6 4.1

 Nigeria total 6 3.0 22.2

Equatorial Guinea Bioko Island 1 0.5 3.4

Angola Soyo 1 0.7 5.2

South America

Trinidad & Tobago Point Fortin 4 2.1 15.1

Peru Melchorita 1 0.6 4.4

1

Four additional trains are mothballed.

Table A3–3. LNG capacity under construction accessible to Asian importers from Southeast Asia and Oceania.

[Data are from True (2012) except that Browse data are from Woodside Energy (2012). BCF/D, billions of cubic feet per day; LNG, liquefied natural gas;

MTY, millions of metric tons per year; TBD, to be determined; 350 working days in a year. Numbers may not add up due to rounding]

Country Liquefaction facility 

(start-up year)

Number of 

trains

Capacity

(BCF/D)

Capacity

(MTY)

Australia Burrup Peninsula, Pluto LNG (2013) 1 0.6 4.3

Burrup Peninsula, Pluto LNG (2014) 1 0.6 4.3

Barrow Island, Gorgon LNG (2014) 3 2.1 15.0

Gladstone, Queensland Curtis LNG (2014) 2 1.2 8.5

Gladstone LNG (2015) 2 1.1 7.8

Gladstone, Australia Pacific LNG (2015–16) 2 1.2 9.0

Ashburton North, Wheatstone LNG (2016) 2 1.2 8.6

Kimberly Coast, Browse (year TBD) 3 1.6 12.0

 Australia total 16 9.5 69.5

Indonesia Donggi-Senoro (2014) 1 0.3 2.0

Papua New Guinea Port Moresby (2014) 1 0.9 6.6
Appendix 4. Countries in Each Region 57

Appendix 4. Countries in Each Region

This report refers to regions for which data on stranded gas were provided in figure 1 and tables 1–4. Table A4–1 lists the

countries in each region where some stranded gas has been reported and summarized in figure 1 and tables 1 and 2.

Table A4–1. List of countries reporting stranded gas in gas fields by regions as used in figure 1 and tables 1, 2, 3, and 4. 

[Asterisk indicates presence of offshore fields. Field data through the end of 2008 are from IHS Inc. (2009)]

Region Countries

South America1 Argentina*, Barbados, Bolivia, Brazil*, Chile*, Colombia*, Guatemala, Paraguay, Peru*, Trinidad 

and Tobago*, and Venezuela*.

Europe Albania*, Austria, Bulgaria*, Croatia*, Czech Republic, Denmark*, France, Germany*, Greece,

Hungary, Ireland*, Italy*, Malta, Moldova, Netherlands*, Norway*, Poland*, Portugal, Romania*,

Serbia, Slovakia, Slovenia, Spain*, Svalbard,2 Sweden, Switzerland, Ukraine*, and United 

Kingdom*.

Middle East Iran*, Iraq, Israel*, Kuwait, Oman*, Saudi Arabia, Syria, Turkey*, United Arab Emirates*, and 

Yemen.

Africa Algeria, Angola*, Cameroon*, Chad, Congo*, Cote d’Ivoire*, Egypt*, Equatorial Guinea*, Eritrea*,

Ethiopia, Gabon*, Ghana*, Libya*, Madagascar*, Mauritania*, Morocco, Mozambique*, 

Namibia*, Nigeria*, Senegal, Somalia, South Africa*, Sudan*, Tanzania*, and Tunisia*.

South Asia Afghanistan, Bangladesh*, India*, and Pakistan*.

East Asia China*, Japan*, South Korea*, and Taiwan*.

Central Asia Azerbaijan*, Kazakhstan, Kyrgyzstan, Tajikistan, Turkmenistan*, and Uzbekistan.

Southeast Asia and Oceania Australia*, Brunei*, Burma*, Cambodia*, Indonesia*, Malaysia*, New Caledonia,3 New Zealand*, 

Papua New Guinea*, Philippines*, Thailand*, and Vietnam*.

Russia Russia*.

1

South America includes stranded gas fields in the Caribbean and Central America except Mexico.

2

Svalbard is a territory of Norway.

3

New Caledonia is a special collectivity of France.