Natural Resources Research

, Volume 23, Issue 1, pp 175–193

Commercial Possibilities for Stranded Conventional Gas from Alaska’s North Slope

Authors

    • US Geological Survey
  • Philip A. Freeman
    • US Geological Survey
Article

DOI: 10.1007/s11053-013-9213-9

Cite this article as:
Attanasi, E.D. & Freeman, P.A. Nat Resour Res (2014) 23: 175. doi:10.1007/s11053-013-9213-9
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Abstract

Stranded gas resources are defined for this study as gas resources in discrete accumulations that are not currently commercially producible, or producible at full potential, for either physical or economic reasons. Approximately 35 trillion cubic feet (TCF) of stranded gas was identified on Alaska’s North Slope. The commercialization of this resource requires facilities to transport gas to markets where sales revenue will be sufficient to offset the cost of constructing and operating a gas delivery system. With the advent of the shale gas revolution, plans for a gas pipeline to the conterminous US have been shelved (at least temporarily) and the State and resource owners are considering a liquefied natural gas (LNG) export project that targets Asian markets. This paper focuses on competitive conditions for Asian gas import markets by estimating delivered costs of competing supplies from central Asia, Russia, Indonesia, Malaysia, and Australia in the context of a range of import gas demand projections for the period from 2020 to 2040. These suppliers’ costs are based on the cost of developing, producing, and delivering to markets tranches of the nearly 600 TCF of recoverable gas from their own conventional stranded gas fields. The results of these analyses imply that Alaska’s gas exports to Asia will likely encounter substantial competitive challenges. The sustainability of Asia’s oil-indexed LNG pricing is also discussed in light of a potentially intense level of competition.

Keywords

Stranded gasgas marketsresource costs

Introduction

This study defines stranded conventional gas resources as gas in identified (discovered and appraised) conventional oil and gas accumulations which are not currently commercially producible for either physical or economic reasons. The discovered conventional North Slope gas is stranded because there is currently no transportation system to take the gas to a market. In the past, proposals for North Slope gas export projects have been developed only to be withdrawn when the projected product prices at the intended market were insufficient to repay the cost of production and transportation to the market. Although the magnitude of this discovered and recoverable conventional stranded gas is approximately 35 trillion cubic feet (TCF)1 (Nehring Associates, Inc. 2010), the costs of extracting, conditioning, and transporting the gas to markets have exceeded expected market prices. Currently, the natural gas resource lease owners and the State of Alaska are considering a liquefied natural gas (LNG) project that targets Asian markets.

This study focuses on the likely competitive conditions of Asian markets during the period from 2020 through 2040 by projecting the cost of supplying these markets with gas from known stranded gas fields currently located in central Asia, Russia, Indonesia, Malaysia, and Australia. Gas import demand projections provide a framework to examine sufficiency of this stranded gas for meeting the Asian import demand. Examination of only the basic costs of delivering the North Slope’s stranded gas to Asian markets as LNG shows the potential challenges that such a LNG project will encounter. The potential level of competition to supply Asia’s markets casts some doubt about the sustainability of the current system of oil-indexed LNG pricing.

Alaska’s Identified North Slope Natural Gas

In addition to the approximately 35 TCF of gas in discovered fields, the mean estimates of gas in undiscovered conventional fields in northern Alaska and the adjacent Federal and State offshore areas are approximately 200 TCF (US Geological Survey 2012; Bureau of Ocean Energy Management 2011). The conventional accumulations with the largest identified volumes of recoverable gas are the Prudhoe Bay oil field (discovered 1968) and the Point Thomson natural gas and condensate field (discovered in 1977). As of the end of 2010, the remaining gas reserves at the Prudhoe Bay oil field are estimated at about 24.4 TCF of gas (Nehring Associates, Inc. 2010, and ASOGCC 2012).2 The operators of the Prudhoe Bay oil field use the gas for lease fuel and also sell it to other North Slope field operators. In 2010, about 6.9 billion cubic feet per day3 (BCF/D) was produced and 6.3 BCF/D was reinjected; the difference in the produced and injected gas amounted to 0.56 BCF/D (ASOGCC 2012). The reinjected gas enhances oil production by assisting in the maintenance of reservoir pressures and for tertiary oil recovery practices.

The largest known conventional onshore North Slope gas accumulation is the Point Thomson gas–condensate field located about 60 miles (96 km) east of Prudhoe Bay. This field is estimated to hold 8 TCF of recoverable natural gas along with 300 million barrels4 (MMbbl) of condensate and crude oil and is currently under development to first produce the condensate and crude oil. Initial production will be about 10,000 barrels per day (B/D) liquids to be transported by pipeline to the Trans-Alaska Pipeline System (TAPS) pump station at Prudhoe Bay. Produced natural gas will be reinjected into the over-pressured reservoir, and natural gas will fuel the field’s operations until gas production can occur at a later time. The start-up of gas–condensate production is scheduled for the 2015–2016 winter (Loy 2012). There are several other conventional gas accumulations and gas–condensate accumulations that have been identified, but none come close to the volume of gas in the Prudhoe Bay oil field or the Point Thomson gas–condensate field. Commercial development of North Slope stranded gas would require participation of the Prudhoe Bay field owners and perhaps the Point Thomson field owners.

Markets for Alaska’s North Slope Gas

The Alaska Natural Gas Inducement Act (AGIA) provides State subsidies to encourage commercialization of natural gas from Alaska’s North Slope. In 2007, the TransCanada pipeline project was awarded AGIA endorsement from the State of Alaska. The initial project design consisted of constructing a 48-in. (122 cm) diameter high pressure gas pipeline from the Prudhoe Bay field to AECO™, the Alberta gas hub, a total distance of 1,715 miles (2,759 km) (TransCanada 2007). The proposed pipeline from Prudhoe Bay to Alberta was sized to carry 4.5 BCF/D of gas. Over a 30-year period, if the pipeline had 90% utilization, it would transport 44.3 TCF of gas, which is substantially greater than currently discovered gas volumes. The industry, however, will not search for additional gas reserves unless expected prices will be sufficient to repay all costs.

The 2007 estimated cost of conditioning and delivering gas to the conterminous 48 states using the published cost from the AGIA application was about $3.94 per million British thermal units (MMBtu) or $4.46 per MMBtu when gas shrinkage is taken into account for fuel consumption (Attanasi and Freeman 2009).5 An update to the design of the project in 2010 resulted in increased capital cost of at least 25% above the 2007 submission (TransCanada 2007, 2010), thus raising minimum transport costs to about $4.93 per MMBtu or $5.57 per MMBtu after shrinkage. Figure 1 shows the monthly prices from 2001 through 2012 at Henry Hub Louisiana, USA, the AECO Hub in Alberta, Canada, and the average landed prices for imported LNG in Japan. For 2012, the average Henry Hub price was $2.75 per MMBtu and the average AECO Hub price was $2.41 per MMBtu. The Energy Information Administration (EIA) (2013a) shows in their base case projection of Henry Hub prices that forecast prices will not exceed the cost of transporting the gas from the North Slope to US Midwestern markets until 2035. Development costs for stranded gas and the finding and development cost of new gas, in addition to taxes and return on investments, would make the minimum required gas price to the US markets substantially higher than EIA forecasts for US markets.
https://static-content.springer.com/image/art%3A10.1007%2Fs11053-013-9213-9/MediaObjects/11053_2013_9213_Fig1_HTML.gif
Figure 1

Natural gas price for AECO hub (Alberta, Canada), Henry Hub (Louisiana, USA), and Japan LNG in nominal US dollars per million Btu from 2001 through 2012. AECO data from Natural Resources Canada (2013), Henry Hub data from EIA (2013b), and Japan data from World Bank (2013)

During the 2011 open season, which is a formal time period when the pipeline sponsors gauge the market, TransCanada received insufficient producer and purchaser commitments for the pipeline project to move forward. The risk to wholesale gas purchasers, who will generally be required to sign take-or-pay contracts, is that they may not be able to resell their purchased gas without incurring heavy losses. TransCanada, with the approval of the Alaska state government, has announced that it will delay filing an application with the Federal Energy Regulatory Commission for an Alberta gas pipeline until October 2014 (Nelson 2012). The AGIA had a secondary option which is to transport North Slope gas to southern Alaska for in-state use and for liquefaction and export as LNG. TransCanada and the North Slope producers are evaluating an alternative strategy to market the gas as LNG to Asian purchasers. The feasibility study for an in-state pipeline and LNG export operation is to be completed in 2014 (Nelson 2012). Geographically, the closest natural market for Alaska LNG exports outside of North America is Asia. Perhaps, more importantly, the historical prices for LNG delivered to Asian markets have been substantially higher than the historical transmission (pipeline) gas prices in North American markets (see Fig. 1).

Asia’s Markets for Imported Natural Gas

Projected Demand and Natural Gas Imports

Asia’s market for imported natural gas is fragmented as a result of geographic and political barriers. The markets examined consist of the major importing countries of Japan, South Korea, China, and India (BP 2012). Since 2001, gas consumption grew 8.7% per year in this group. Japan and South Korea have little indigenous gas. Although China and India have some conventional gas, they are gas importers.

Table 1 shows three sets of intermediate-term gas import demand projections for the four markets. The top set of projections or scenario 1 is the EIA forecast published in the International Energy Outlook (EIA 2011a) as their reference projection. The historical data are from BP (2012). The alternative projections (scenario 2 and 3) represent variations of the EIA country demand projections. Scenarios 2 and 3 assume the same domestic gas production levels of the EIA projection, but differ from the EIA base case in three respects. They recognize closure of nuclear-fueled electrical generating plants in Japan (Inajima and Okada 2011), include an assumption about extending electrical service to some of the more than 400 million people (Wolfram et al. 2012) in India without electrical service,6 and they assume that growth in electricity generated by coal will be constrained in both China and India.
Table 1

Three Demand Scenarios for Net Natural Gas Imports, in Trillions of Cubic Feet per Year, by Country Showing Historical Imports and Projections into Future

Country

Historical Demand

Projected Demand

2008

2011

2015

2020

2025

2030

2035

Scenario 1: EIA reference case

 Japan

3.5

3.8

3.4

3.5

3.7

3.8

3.8

 South Korea

1.2

1.7

1.5

1.6

1.8

1.8

1.9

 China

0.0

1.1

2.4

3.3

4.1

4.5

4.6

 India

0.4

0.6

0.8

1.1

1.3

1.4

1.4

 Total

5.1

7.2

8.1

9.5

10.9

11.5

11.7

Scenario 2

     

 Japan

3.5

3.8

5.8

6.1

6.4

6.8

7.0

 South Korea

1.2

1.7

1.5

1.6

1.8

1.8

1.9

 China

0.0

1.1

6.0

8.2

12.5

16.3

18.9

 India

0.4

0.6

1.9

3.4

5.3

7.5

10.1

 Total

5.1

7.2

15.2

19.3

26.1

32.4

37.9

Scenario 3

     

 Japan

3.5

3.8

5.8

6.1

6.4

6.8

7.0

 South Korea

1.2

1.7

1.5

1.6

1.8

1.8

1.9

 China

0.0

1.1

4.2

5.8

8.3

10.4

11.8

 India

0.4

0.6

1.7

3.1

4.8

6.8

9.0

 Total

5.1

7.2

13.2

16.6

21.4

25.7

29.6

Scenario 1 is the EIA reference case. Scenarios 2 and 3 assume natural gas is substituted for nuclear power in Japan, and India extends electrical service to 90% of its population by 2040 by adding gas-fired power generation. Additionally, in scenario 2, gas-generated electricity is substituted for 50% of the EIA reference case projected growth in coal-fired electricity for China and India. In scenario 3, gas-generated electricity is substituted for 25% of growth in coal-fired electricity for China and India.

1 cubic meter = 35.3 cubic feet.

EIA reference case projections from EIA (2011a) except 2008 and 2011 demand from BP (2012).

The EIA projected very robust growth in electricity generated by coal-fired generating plants for China and India. For scenario 2, it is assumed that half of the projected growth of China and India’s electricity from coal under the EIA reference case projection would be shifted to electricity generated by natural gas. In scenario 3, only 25% of the growth of China’s and India’s electricity from coal under the EIA reference projection is assumed to be shifted to gas. Beyond 2020, the gas import demand projections based on scenarios 2 and 3 for China and India show increasing divergence from the EIA’s reference import demand projections. Comparison of scenarios 2 and 3 shows the dramatic effect of relaxing the assumption of continued heavy reliance on coal to fuel electricity generation in China and India. For India, about 75% of the difference between the EIA reference projection and scenario 2 is attributed to the expansion of electrical service to 90% of the population by 2035.

Reconnaissance estimates of technically recoverable shale gas in China and India are 1,285 and 63 TCF, respectively (EIA 2011b). China was estimated to have a coal bed gas resource base of 1,000 TCF of in-place gas (Rice et al. 1993), but testing for commercial production started only recently. Standard commercial-scale shale gas production requires a lengthy experimental period to design effective fracture treatments, as well as the use of large volumes of water, which could present a problem for shale gas in the Tarim Basin where water is scarce. According to the EIA (2011b), about 46% of China’s recoverable shale gas is located in the Tarim Basin. The EIA reference scenario (EIA 2011a) included projections for unconventional gas production for China and India.7

The aggregate net gas import demand projections for 2020 range from 9.5 to 19.3 TCF, and for 2035, the projections range from 11.7 to 37.9 TCF. To put these gas import demand levels in perspective, Europe imported nearly 11 TCF of gas from outside countries in 2011 (BP 2012) and its population was less than one-fifth of the Asia market countries studied here. Over the 20-year period from 2020 to 2040, total gas imports that correspond to the EIA reference case projection are 224 TCF; under scenario 2, the cumulative imports are 625 TCF; and under scenario 3, cumulative imports are 499 TCF.8 Scenarios 2 and 3 in Table 1 show the dominance of China.

Delivered Cost of Competing Pipeline and LNG Suppliers to Asian Markets

The lowest cost gas supplied to Asian importers is generally supplied from proved reserves in operating fields and from gas in stranded gas fields in gas-exporting countries near their markets. Because the gas volumes in operating fields and fields under development are already likely committed to purchasers, the gas in conventional stranded gas fields represents the lowest cost volumes or tranches of gas for future gas sales to Asia. The analysis of costs of competing supplies to Asian markets from central Asia (Turkmenistan, Kazakhstan, and Uzbekistan), Russia, Indonesia, Malaysia, and Australia focuses on costs of gas from their conventional stranded gas fields.

The source of gas recovery data by field is the IHS International Field File (IHS Inc. 2008a).9 Attanasi and Freeman (2013b) describe the process for identifying the stranded gas fields. The fields were then grouped into clusters and hypothetical hubs and terminal locations were located to minimize transport costs to an export pipeline to market or to a coastal LNG plant that would transform the gas to LNG and then transport the LNG to market in seagoing tankers. The following discussion summarizes the additional criteria that determined whether the identified stranded gas could be competitively offered for export to China, India, Japan, and South Korea. For this analysis, we have largely ignored potential political barriers or legal delays associated with major new gas development and export projects.

Gas Available in Stranded Fields in Central Asia, Russia, Indonesia, Malaysia, and Australia

The Chinese markets are currently supplied with pipeline gas from central Asia. China now imports pipeline gas from Turkmenistan and future gas imports are planned from Kazakhstan and Uzbekistan. Gazprom, the Russian government controlled gas producer and owner of the gas pipelines in Russia, is expected to eventually supply pipeline gas to China when both countries agree on a system for pricing the gas. The China National Petroleum Corporation (CNPC) is also constructing a gas pipeline to import about 1.2 BCF/D of gas from Myanmar (Smith 2011). Japan and South Korea are expected to remain dependent on LNG for gas imports during the projection period. India’s petroleum companies appear poised to significantly expand LNG imports as they aggressively contract for gas from LNG projects in Australia, Indonesia, and North America (White 2012). In 2011, 78% of the gas imported by Japan, China, South Korea, and India originated in central Asia, Russia, Southeast Asia, and Australia (BP 2012). Nearly all of the rest of the supply came from the Middle East (mainly Qatar). Although Iran holds large gas reserves, there are no formal plans to expand pipeline gas or LNG export capacity from this politically volatile region.

Attanasi and Freeman (2013a) prepared estimates of the costs of developing and delivering stranded gas for each of the four markets from conventional stranded gas fields located in central Asia, Russia, Indonesia, Malaysia, and Australia. They determined that the inventory of stranded gas that could be exported to Asian markets is substantial. In the case of Russian sourced pipeline gas for export to Asia, about 98 TCF was evaluated in the eastern part of Russia’s West Siberian Basin and 103 TCF was evaluated in basins in eastern Siberia (Attanasi and Freeman 2013a, see also Fig. 2). There is more than 250 TCF of stranded gas in central Asia evaluated for export by pipeline to Asia (Attanasi and Freeman 2013a, see also Fig. 2).
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Figure 2

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 (modified from Attanasi and Freeman 2013a)

China imports natural gas by pipeline and as LNG. India, Japan, and South Korea currently only import natural gas as LNG. Malaysia and Indonesia are estimated to have 48 and 54 TCF, respectively, of conventional gas resources in stranded fields, which is likely to be assigned to LNG export markets (Attanasi and Freeman 2013a, also see Fig. 3).10 In Australia, 105 TCF of stranded gas was estimated to be available for LNG export after current (sanctioned) projects and small stranded gas accumulations were removed from the list of stranded fields (Attanasi and Freeman 2013a, see also Fig. 4). More than 650 TCF of stranded gas is potentially available in the stranded gas accumulations evaluated for pipeline gas and LNG. Although new discoveries will add to the inventory, the cost of developing and delivering these already identified gas resources provides a basis for assessing the competitive environment that will be encountered by Alaska’s future LNG projects.
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Figure 3

Map showing LNG liquefaction plants, clusters of stranded gas fields, and US Geological Survey (USGS) petroleum provinces (US Geological Survey World Energy Assessment Team 2000) in Indonesia, Malaysia, and Brunei (modified from Attanasi and Freeman 2013a)

https://static-content.springer.com/image/art%3A10.1007%2Fs11053-013-9213-9/MediaObjects/11053_2013_9213_Fig4_HTML.gif
Figure 4

Map showing LNG liquefaction plants, clusters of stranded gas fields, and USGS petroleum provinces (US Geological Survey World Energy Assessment Team 2000) in Australia (modified from Attanasi and Freeman 2013a)

Computation of Delivered Costs of Gas from Stranded Gas Fields

In this report, delivered cost estimates are tied to volumes of stranded gas as calculated in Attanasi and Freeman (2013a). The cost estimates include the cost of individual field development, production operations, and construction of a pipeline from clusters of stranded gas fields to a market where pipeline transport to the market is feasible. Otherwise, the stranded gas was assumed to be transported to a coastal liquefaction plant, processed into LNG, and delivered to one of the four Asian markets. In particular, each field was assumed to be developed with the expectation that revenues from production will repay operating costs, taxes, and investment expenditures and will provide an after-tax return of at least 12% on the investment. The common set of fiscal assumptions included a 20% royalty rate, 50% tax rate on annual net income, and 12% required rate of return. Gas field development and operating cost data were derived from the QUE$TOR (IHS Inc. 2008b) cost database. The cost analysis and comparisons are presented in constant 2008 US dollars.11

Transportation tariffs and liquefaction tolls were based on the “cost of service” concept where level fees are set to recover operating costs, taxes, and capital investment over the economic life of the facility (typically 25 years), along with a 12% after-tax return on investment. For pipelines, the “cost of service” tariffs assume that new pipelines are built and located along the right of way of existing pipelines. With the exception of the proposed liquefaction plants at Vladivostok, Russia (Gazprom 2012), and Donggi-Senoro, Indonesia (Ledesma 2008), gas in stranded fields was transported to an operating LNG plant or a plant under construction. It was assumed that the LNG plant would be expanded by adding trains of the same size as the largest currently operating or planned train. Consequently, for each LNG plant considered, there was a cost function starting from the least expensive tranches of gas at the plant inlet and moving up the cost function as higher cost supplies from smaller and more distant gas fields were committed to that plant. The delivered LNG costs to various markets from the plant include the cost of liquefaction and the cost of LNG delivery by a seagoing vessel. Each LNG importer must regasify the imported LNG by allowing it to vaporize by passive means or by adding energy to speed vaporization from the liquid state. Regasification is required for all imports and this does not enter into the competitive analysis among LNG suppliers.

Estimated Delivered Costs of Competing Supplies

Table 2, reproduced from Attanasi and Freeman (2013a), shows estimates of the delivered cost of gas in pipelines from stranded conventional gas fields in central Asia and Russia at Shanghai, China. Delivered costs for the initial large-volume tranches of gas are between $7.00 and $8.30 per thousand cubic feet (MCF) for gas from eastern Siberia, $7.60 per MCF for central Asian gas, and $10.90 per MCF for Western Siberian Basin gas. The total of the tranches with delivered cost less than or equal to $8.30 per MCF amounts to more than 260 TCF of gas. Table 1 shows that China’s projected import demands are expected to dominate the Asian gas import markets by the end of the projection period. Table 2 shows that China has access to significant volumes of gas delivered by pipeline (total volume is 444.3 TCF). The pipeline distances from central Asia and the Western Siberian Basin stranded fields that were evaluated to the Shanghai market are as much as 3,600–4,200 miles (5,792–6,758 km). Pipeline distances from the eastern Siberian basins to Shanghai range from 2,500 to 2,900 miles (4,023–4,666 km). For the threshold prices shown in Table 2, pipeline transport costs account for 76–86% of the delivered costs.
Table 2

Threshold Cost and Corresponding Initial Volume of Gas that can be Developed, Produced, and Delivered to Shanghai, China, at the Threshold Cost by Country, Basin, or Region Shown Along with the Total Available Volume of Stranded Recoverable Gas

Area

Cost ($/MCF)

Initial Volume (TCF)

Total Volume (TCF)

Republic in Central Asia

 Turkmenistan

7.60

190

211

 Uzbekistan

7.80

8.2

31

 Kazakhstan

11.70

1.1

4.2

Basin in eastern Siberia

 Angarra-Lena

8.30

49

55

 Baykit Arch

9.30

4.8

5.4

 South Nepa-Botuoba

8.00

3.8

4.8

 North Nepa-Botuoba

7.00

13

29

 Lena-Vilyuy

9.90

5.4

9.3

Region in Western Siberian Basin

 Urengoy

10.90

28

92

 Proskokova

10.20

0.9

2.6

Cost in constant 2008 US dollars.

1 cubic meter = 35.3 cubic feet.

From Attanasi and Freeman (2013a).

$/MCF dollars per thousand cubic feet, TCF trillion cubic feet.

Table 3 shows the delivered cost of the initial (lowest cost) tranche of stranded gas assigned to each of the identified LNG plants and delivered costs to the four market areas. For computational purposes, the destination port for China is Shanghai, for Japan it is Yokohama, for South Korea it is Incheon, and for India it is Hazira. Each tranche of gas is the volume of available stranded gas that can be committed to each new train where the scale of the train is consistent with the largest train currently in operation or under construction. The table shows how the delivered cost to various destinations increases as the plants add trains and operators use progressively more costly input gas to the LNG plants. Most of the plants have sufficient stranded gas assigned to add four trains, but Gladstone, Blang Lancang, and Donggi-Senoro currently have only enough identified stranded gas for an initial tranche or train.
Table 3

Delivered Threshold Costs for Each Additional Train of Gas as LNG from Stranded Gas Fields in Australia, Malaysia, Indonesia, and Russia to Four East Asia markets

Liquefaction Facility

Committed Recoverable Resources per Train (TCF)

LNG Inlet Cost ($/MCF)

Delivered Cost per Train ($/MMBtu)

Shanghai, China

Yokohama, Japan

Incheon, S. Korea

Hazira, India

First train

 Withnell Bay, Australia

7.1

1.80

8.61

8.72

8.78

8.66

 Browse, Australia

4.8

3.50

10.67

10.78

10.84

10.96

 Darwin, Australia

4.6

2.40

9.51

9.63

9.68

10.08

 Gladstone, Australia

5.6

3.30

10.79

10.68

10.97

11.55

 Bintulu, Malaysia

4.8

1.50

7.22

7.45

7.38

7.70

 Blang Lancang, Indonesia

2.5

5.30

11.73

12.01

11.91

11.49

 Tangguh, Indonesia

5.4

2.60

8.40

8.51

8.57

9.28

 Donggi-Senoro, Indonesia

2.8

3.40

10.49

10.62

10.66

11.28

 Bontang, Indonesia

4.0

4.10

9.26

9.40

9.43

9.84

 Vladivostok, Russia (planned)

8.5

5.80

12.57

12.55

12.54

14.45

Second train

 Withnell Bay, Australia

7.1

3.20

10.22

10.33

10.39

10.27

 Browse, Australia

4.8

3.50

10.67

10.78

10.84

10.96

 Darwin, Australia

4.6

2.80

9.97

10.09

10.14

10.54

 Gladstone, Australia

0.0

a

a

a

a

a

 Bintulu, Malaysia

4.8

1.60

7.33

7.56

7.49

7.81

 Blang Lancang, Indonesia

0.0

a

a

a

a

a

 Tangguh, Indonesia

5.4

3.00

8.86

8.97

9.03

9.74

 Donggi-Senoro, Indonesia

0.0

a

a

a

a

a

 Bontang, Indonesia

4.0

4.10

9.26

9.40

9.43

9.84

 Vladivostok, Russia (planned)

8.5

6.30

13.15

13.13

13.11

15.03

Third train

 Withnell Bay, Australia

7.1

4.20

11.37

11.48

11.54

11.42

 Browse, Australia

4.8

6.00

13.55

13.66

13.72

13.84

 Darwin, Australia

4.6

3.40

10.66

10.78

10.83

11.23

 Gladstone, Australia

0.0

a

a

a

a

a

 Bintulu, Malaysia

4.8

1.60

7.33

7.56

7.49

7.81

 Blang Lancang, Indonesia

0.0

a

a

a

a

a

 Tangguh, Indonesia

5.4

3.80

9.78

9.89

9.95

10.66

 Donggi-Senoro, Indonesia

0.0

a

a

a

a

a

 Bontang, Indonesia

4.0

7.20

12.83

12.96

13.00

13.40

 Vladivostok, Russia (planned)

8.5

6.90

13.84

13.82

13.80

15.72

Fourth train

 Withnell Bay, Australia

7.1

6.20

13.67

13.78

13.84

13.72

 Browse, Australia

4.8

6.00

13.55

13.66

13.72

13.84

 Darwin, Australia

4.6

5.00

12.50

12.62

12.67

13.07

 Gladstone, Australia

0.0

a

a

a

a

a

 Bintulu, Malaysia

4.8

2.40

8.25

8.48

8.41

8.73

 Blang Lancang, Indonesia

0.0

a

a

a

a

a

 Tangguh, Indonesia

0.0

a

a

a

a

a

 Donggi-Senoro, Indonesia

0.0

a

a

a

a

a

 Bontang, Indonesia

4.0

15.40

22.26

22.39

22.43

22.83

 Vladivostok, Russia (planned)

8.5

7.20

14.18

14.16

14.15

16.06

Costs in constant 2008 US dollars.

1 cubic meter = 35.3 cubic feet.

Volumes and costs from Attanasi and Freeman (2013a).

$/MCF dollars per million cubic feet, $/MMBtu dollars per million British thermal units, TCF trillion cubic feet.

aInsufficient recoverable resources for additional train.

In general, the suppliers with the lowest delivered costs are those with the lowest LNG plant inlet gas cost. For these suppliers, costs of production and delivery of gas to the LNG plant usually account for less than 30% of the overall delivered cost at the market. For the lower cost suppliers, the liquefaction process accounts for 50–67% of the total delivered costs. The cost of marine transport of LNG to the market from the plant is relatively small, rarely exceeding 15% of the delivered cost, so the ranking of the suppliers by delivered costs will be roughly the same across the Shanghai, Yokohama, and Incheon locations. The discussion now focuses on the Yokohama, Japan market.

If the computations in Table 3 were extended so that all the remaining tranches of stranded gas allotted to each LNG plant are assigned a delivered cost to market, and if all this gas is aggregated across the plants and ordered by delivered cost at Yokohama, then Figure 5 is the result. It shows the potential resource-cost supply function that a new entrant to that market may have to match to be competitive. The curve is instructive because it shows there are substantial volumes of stranded gas that could be developed and delivered at costs that are below the historical market prices shown for Japan in Figure 1. Approximately 250 TCF would be available at delivered costs of less than $16.00 per MMBtu. Similar functions were developed for Shanghai, Incheon, and Hazira using the set of stranded gas fields that were evaluated and the costs associated with liquefaction and transport.
https://static-content.springer.com/image/art%3A10.1007%2Fs11053-013-9213-9/MediaObjects/11053_2013_9213_Fig5_HTML.gif
Figure 5

Graph summarizing various volumes of gas as LNG at corresponding delivered costs from stranded gas fields in Russia, Indonesia, Malaysia, and Australia evaluated for LNG export. Delivered cost includes the cost of developing, producing, and transporting gas to Yokohama, Japan, in constant 2008 US dollars (1 cubic meter = 35.3 cubic feet)

The historical tie between Asian LNG prices and oil prices is an artifact of the development of the LNG industry (International Gas Union 2009). The successful emergence of shale gas as an important new source of North American gas supply has idled most LNG-receiving terminals in the United States. US regasification terminal operators, particularly in the Gulf Coast, have proposed building merchant liquefaction plants that would offer to liquefy natural gas purchased at Henry Hub prices for long-term LNG purchasers, with the LNG purchasers bearing the hub price risk. The strategy is intended to profit from the differences in the prices of gas sold at Henry Hub prices (plus liquefaction tolls and cost of oceangoing LNG transport) and the oil-indexed prices of pipeline gas sold in Western Europe and LNG sold in the Asian markets (Jensen 2012). With these emerging alternatives, Asian LNG purchasers are now resisting signing new long-term contracts for future LNG supplies that are based exclusively on oil equivalence and oil indexation (White 2012). However, for an LNG export project to progress beyond the planning stage, several factors must align. Authorization from the government in the exporting country must be obtained and a substantial portion of the LNG output must be committed by long-term purchase contracts to secure financing. Governments are carefully reviewing (Australia and US) or restricting (Indonesia) the volumes of LNG allowed for export. LNG purchasers have critical leverage in setting initial prices in new projects by withholding commitments to long-term contracts.

The delivered costs of LNG presented in Table 3 for Shanghai, China, can be compared to the estimates of delivered cost of pipeline gas to Shanghai. If it is assumed that a cubic foot of pipeline natural gas has 1,070 Btus, Table 2 shows that the estimated delivered costs to Shanghai from central Asia are $7.10 through $7.30 per MMBtu, gas from Russia’s eastern Siberian basins costs $6.54 to $9.25 per MMBtu, and gas from the West Siberian Basin costs $10.19 per MMBtu. The evaluations in Tables 2 and 3 show that the delivered costs of pipeline gas to Shanghai are below most of the delivered costs of LNG. Because security of supply is also an important consideration, it is unlikely that China will totally rely on imports of pipeline gas, but will seek to assemble a portfolio of alternate sources for its gas imports, namely, as LNG from different countries.

Cost of Delivering Alaska Gas

The North Slope gas owners and the State are considering an LNG project aimed at Asian markets that consists of (1) a gas conditioning plant located on the North Slope, (2) an 800-mile, 42- to 48-in. (107- to 122-cm) diameter pipeline to carry between 3 and 3.5 BCF/D to Southern Alaska, and (3) initially planning a three-train liquefaction facility (Nelson 2012). The plan permits up to 5 in-state gas off take points amounting to 0.300–0.350 BCF/D. For the purposes of this analysis, it is assumed the natural gas treatment plant on the North Slope is sized for 3.3 BCF per day output and 3.0 BCF/D is received at the LNG plant in southern Alaska with 0.3 BCF/D taken by in-state users. The fiscal assumptions related to this project are as follows: (1) a combined US Federal and State income tax rate of 41.1%, (2) an ad valorem property tax of 2% of plants, pipeline, and equipment valuations, and (3) a 12% after-tax required return on invested capital. The following very rudimentary analysis is presented merely to illustrate how costs for such a project compare to the competition (Fig. 5).

According to the plan, for natural gas sourced from the Prudhoe Bay oil field, the producer will seek wellhead gas price levels that will also compensate for the “opportunity costs” associated with reducing the maximum oil recovered had the gas continued to be recycled. Little information is available in the public domain regarding the quantity of oil potentially not recovered if the recycled gas, now used to maintain oil reservoir pressure, is diverted to major gas sales. Thomas et al. (2009) speculated that the range would be 150 million barrels oil (MMBO) to 300 MMBO and they used 230 MMBO for their analysis. For example, if the recoverable gas is 23 TCF and the net value of the 230 MMBO is $50 per barrel at the time production starts, then the opportunity cost of early production of the associated gas is about $0.50 per MCF. There are no estimates in the public domain relating to the investment costs required for converting the Prudhoe Bay and Point Thomson infrastructure from primarily liquids production to natural gas production (see Statoil 2012, for a discussion of a similar conversion of the Statfjord Field). In addition to the opportunity cost of lost liquids and investment costs for gas conversion, gas extraction costs include continued operating cost, property taxes, royalty, and severance taxes. For illustrative purposes, the cost of gas at the North Slope conditioning plant is assumed to be $2.00 per MCF, and the product gas, after conditioning, is assumed to be dry gas having a calorific value of 1,020 Btu per cubic foot.

In the application under the AGIA, TransCanada (2007) estimated the capital and operating costs for (1) the North Slope gas conditioning plant, (2) the segment of the 4.5 BCF/D pipeline that would transport natural gas to the Alaska/Yukon border, and (3) the pipeline segment from the Alaska/Yukon border to the AECO hub in Alberta. The gas conditioning plant had a design output of 4.5 BCF/D of pipeline quality gas and an estimated capital cost of $7.1 billion. If it is assumed that the gas conditioning plant-scale cost factors follow the six-tenths rule as do many chemical plants, the estimate of the total capital cost for a gas conditioning plant having an output capacity of 3.3 BCF/D is about $5.9 billion in 2007 dollars.12 The cost estimates were adjusted to constant 2008 dollars, and estimates of the cost of service for conditioning the natural gas were calculated. The TransCanada application specified that 4.4% of the gas input would be used to fuel the plant. Details of the gas conditioning plant toll calculations are presented in Appendix 2. The estimated gas plant conditioning toll is about $1.43 per MMBtu exclusive of the nominal $2.00 per MCF cost of the input gas.

An overland pipeline would transport gas from the North Slope gas conditioning plant to a LNG plant at or near Valdez, Alaska, following most of the route of the existing TAPS oil pipeline (see Fig. 6). The $10.9 billion estimate of the capital costs for an 800-mile (1,287 km) pipeline to Valdez was based on scaled cost factors derived from the TransCanada application. In addition, it was assumed the 800-mile (1,287 km) trip would result in a loss of 1.2% of the pipeline inlet gas volume in order to fuel compressors and other equipment. Further details of the assumptions and tariff calculations are also provided in Appendix 2. The estimated tariff for transporting natural gas from the North Slope gas conditioning plant to Valdez is $2.59 per MMBtu.

With a LNG plant inlet capacity of 3.0 BCF/D and assuming 85% efficiency for transforming inlet gas to LNG, one feasible configuration uses three trains of 6.5 million metric tons per year (MTY/Y) (312 BCF/Y) each. The procedures for estimating liquefaction and transportation costs to markets are presented in Appendix 1 and the supply chain costs are summarized in Table 4. The delivered cost at Yokohama, Japan, is $13.50 per MMBtu when the gas cost at the inlet of the gas conditioning plant is the nominal $2.00 per MCF ($1.96 per MMBtu). Table 4 shows how, as the North Slope conditioning plant inlet gas cost increases, the delivered cost (in $/MMBtu) of the LNG increases based on different rates of return.
Table 4

Estimated Cost of Treating, Liquefying, and Transporting Gas as LNG Delivered from Alaska’s North Slope to Yokohama, Japan

Inlet Cost at Gas Treatment Plant ($/MCF)

Gas Treatment Plant Cost ($/MMBtu)

Transport Cost to Valdez, Alaska ($/MMBtu)

Liquefaction and LNG Transport Cost ($/MMBtu)

Delivered Cost at Yokohama, Japan ($/MMBtu)

Volume Competitor’s Gas Below Alaska Cost (TCF)

12% after-tax rate of return

 2.00

1.43

2.59

7.52

13.50

149

 2.50

1.48

2.60

7.62

14.14

172

 3.00

1.53

2.60

7.72

14.79

223

 3.50

1.58

2.61

7.82

15.44

227

 4.00

1.63

2.62

7.92

16.08

244

 4.50

1.68

2.62

8.02

16.73

249

 5.00

1.73

2.63

8.12

17.37

249

9% after-tax rate of return

 2.00

1.20

2.14

6.26

11.56

114

 2.50

1.25

2.15

6.36

12.20

123

 3.00

1.29

2.15

6.46

12.85

136

 3.50

1.34

2.16

6.56

13.50

149

 4.00

1.39

2.17

6.66

14.14

172

 4.50

1.44

2.17

6.76

14.79

223

 5.00

1.49

2.18

6.86

15.44

227

15% after-tax rate of return

 2.00

1.68

3.06

10.13

16.83

249

 2.50

1.73

3.07

10.23

17.48

249

 3.00

1.78

3.08

10.33

18.13

249

 3.50

1.83

3.08

10.43

18.77

249

 4.00

1.88

3.09

10.53

19.42

256

 4.50

1.93

3.10

10.63

20.07

256

 5.00

1.98

3.10

10.73

20.71

256

A 12% after-tax rate of return is the standard used for Alaska and the international projects evaluated. Other rates pertain only to Alaska and are provided for sensitivity analysis. Costs in constant 2008 US dollars.

1 cubic meter = 35.3 cubic feet.

$/MCF dollars per thousand cubic feet, $/MMBtu dollars per million British thermal units, TCF trillion of cubic feet.

Figure 5 shows the potential resource-cost supply function for the Yokohama, Japan, LNG market that a new entrant would encounter. The total recoverable gas resource assessed for the Asian LNG import market is 275 TCF, with approximately 250 TCF potentially available at delivered costs of $16.00 per MMBtu, which assumes that all the stranded gas in Russia’s east Siberian basins is assigned to LNG instead of pipeline export. By using Figure 5, a new entrant from outside the region could compare his cost with the delivered costs of other potential suppliers to Japan’s LNG market. Using the data from Figure 5, the entrant could determine the volume of gas that could be supplied by competitors at lower costs. This same information is in the rightmost column of Table 4.

If the gas treatment plant inlet gas cost is the nominal $2.00 per MCF, more than 148 TCF of gas could be supplied at delivered costs to Yokohama below the listed North Slope delivered cost of $13.50 per MMBtu. Table 4 also shows results for two alternative rates of return. If the required after-tax return for the entire Alaska project was reduced to 9%, delivered cost is $11.56 per MMBtu and 114 TCF of the competitors’ gas would have lower delivered cost. Table 4 also shows that raising the required after-tax rate of the return to 15% assures that the Alaska project’s landed gas costs will be greater than 250 TCF of the competitors’ stranded gas. Normally, higher rates of return are required for projects involving more uncertainty and financial risk, so the 9% case is the least likely of the three analyses unless financing of the project is heavily subsidized. Table 4 also provides a summary of the process costs along the Alaska LNG supply chain. For the range of prices considered, the transportation costs from Valdez, Alaska, to Yokohama, Japan, are generally less than 15% of delivered LNG.13

Based on data in Figure 1, the average price over the 12-month period during 2012 for LNG delivered to Japan was at an all-time high of $16.55 per MMBtu or $15.12 per MMBtu in 2008 US dollars. According to Table 4, assuming a 12% after-tax return, this price would allow a netback inlet gas treatment plant cost (price) of between $3.00 and $3.50 per MCF ($2.94 and $3.43 per MMBtu). However, the realization of the 2012 price into the future is far from certain, as Asian LNG purchasers are being offered alternative pricing options such as purchasing gas at Henry hub-indexed prices and having it liquefied by merchant LNG plants (White 2012). Moreover, China, representing the largest potential future importer of gas, has several alternatives to LNG, namely, from pipeline gas and development of its domestic unconventional gas resources.

Implications

The forecast by the EIA and alternative projections show a wide range in potential gas import demand during the 2020–2040 period, but China drives much of the incremental growth in gas import demand in Asia. China’s policies with respect to pipeline gas imports from central Asia and Russia and its success in efforts to produce its domestic unconventional gas profoundly affect the future Asian LNG market demand. The Asian LNG market analysis, based on cost of supply of currently identified stranded gas in central Asia, Russia, Indonesia, Malaysia, and Australia, implies that new market entrants will face formidable competition both from pipeline gas suppliers and LNG suppliers.

The analysis evaluated 275 TCF of gas in conventional stranded fields in Australia, Indonesia, Malaysia, and Russia that could be exported to the Asia-focus markets as LNG. This analysis also presented the integrated cost function of these suppliers for landed LNG at the Japan market, assuming Yokohama, Japan, as a central location. Landed cost of LNG from Alaska was compared to the competitors’ delivery cost functions in order to determine Alaska’s competitive position. Even if Alaska’s stranded gas could be delivered to the assumed gas treatment plant at Prudhoe Bay for a minimum cost of $2.00 per MCF, the delivered cost at Yokohama would exceed the cost of 149 TCF of gas that might be offered by competitors. The development of new fields in remote locations in northern Alaska that would incur higher costs also faces serious commercial challenges by alternative LNG suppliers.

In the alternatives to the EIA reference gas import demand projections (scenarios 2 and 3), India emerges as a significant market. The government of India controls prices of natural gas sold within the country. Imported gas prices are typically above the controlled prices so the government must subsidize consumers to maintain domestic prices. As in most developing economies, India’s gas demand is very price sensitive. During the last few years, large offshore gas discoveries have been announced in Mozambique and Tanzania. Wood Mackenzie Research and Consulting (2012) estimates that 100 TCF has already been found and another 95 TCF remains as undiscovered in these east African offshore areas. The natural export market for this gas is India. In the effort to monetize these discoveries, it is likely that producers, with the concurrence of the host countries, will offer the gas at competitive prices.

China’s net import demand for LNG is also price sensitive because it has access to alternative lower cost pipeline gas from central Asia and potentially from Russia, or it can choose to incur the cost of developing its significant unconventional gas resource as coal bed gas and shale gas. In an effort to reduce gas import prices, Japanese utilities are studying the feasibility of building a gas pipeline to the Sakhalin I project in eastern Russia along with a parallel effort to study the feasibility of constructing a LNG plant at Vladivostok, Russia (Narusawa and Yamawaki 2012).

In the EIA reference scenario, China and India account for about half the gas import demand in 2030, whereas for scenarios 2 and 3, these two markets account for 76 and 67% of the respective imported gas demand. Perhaps these projections provide the answer as to the likelihood that crude oil-based gas prices will be sustained into the future. Because of their expected role of dominance in the future LNG market, China and India can be expected to demand changes in gas pricing. Based on the delivered cost function shown in Figure 5, more than 90% of the gas in stranded gas fields within the region can be extracted, liquefied, and transported to Yokohama at a cost below the price of $15.12 per MMBtu, which was the average price in 2012 of Japan’s oil-indexed LNG in 2008 dollars. With sufficient supplies from alternative sources, LNG buyers from major Asian markets are likely to seek the end of high oil-indexed prices. A downward pressure on gas prices, whether from exports of North American low-cost gas sources or from the stranded gas resources in Asia and Australia, poses a significant hurdle to successful near and intermediate-term development of Alaska’s stranded gas.

Footnotes
1

1 cubic meter = 35.3 cubic feet. A complete set of conversion factors is listed in Table 6.

 
2

This estimate of reserves is based on cumulative net withdrawals through 2010 of 5.4 TCF (ASOGCC 2012) and an estimate of 29.8 TCF of original recoverable gas (Nehring Associates, Inc 2010). The Prudhoe Bay oil field has both gas dissolved in the oil and a gas cap.

 
3

1 cubic meter per day = 35.3 cubic feet per day.

 
4

1 cubic meter = 6.3 barrels.

 
5

This estimated tariff to Alberta used the TransCanada estimate of $2.50 per MMBtu (TransCanada 2007).

 
6

More than one-third of India’s population is currently without electrical service. In the alternative projections, it is assumed that by 2035, 90% of India’s population will be served by electricity.

 
7

In particular, the 2030 and 2035 supplies from unconventional gas resources from China are 1.6 and 5.2 TCF, respectively, and the projections for India for 2030 and 2035 are 0.2 TCF for each year.

 
8

This volume calculation is 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.

 
9

Any use of trade, firm, or product names is for descriptive purposes only and does not imply the endorsement of the US Government.

 
10

Public opposition to expansion of Indonesia’s gas exports has resulted in civil unrest. More than 100 million Indonesians do not have electricity (Wolfram et al. 2012). Stranded gas fields near Indonesian population centers were excluded from LNG export consideration. Similarly, stranded offshore gas fields adjacent to the Malay Peninsula, where most of the population resides, were excluded from LNG export consideration. The 40 TCF in the Natuna D field of Indonesia was also excluded because of the high carbon dioxide content of the field and a need to develop a means of disposing the carbon dioxide.

 
11

The QUE$TOR (IHS Inc. 2008b) cost represents 2008 technological configurations and costs for project development in each location. As of 2012, Australia project costs have sky rocketed, in large part because of the more than 20% appreciation of Australia’s currency. Because this is likely to be a transitory phenomenon, the 2008 cost structure was retained. The US consumer price index at the end of 2012 was only 4.4% higher than at the end of 2008 because of the severe recession in the intervening years.

 
12

If the scale of the reference plant is Sr with reference cost Cr and the Sp is the scale of project plant, the application of the six-tenths rule estimates the project cost, Cp as Cp = Cr(Sr/Sp)0.6.

 
13

At the required after-tax return of 12%, for the range of gas costs considered, LNG transportation costs from Valdez, Alaska, to Yokohama, Japan, have a range of $1.51 to $1.60 per MMBtu. Similarly, when the required return is 9%, the LNG transport costs are $1.26 to $1.36, and when the required return is 15%, the costs range from $1.76 to $1.87 per MMBtu.

 
14

The property valuation is assumed to decline at 4% per year of the initial construction costs until the valuation reaches 20% of the capital costs and then remains at that level for the economic life of the project.

 
15

1 cm = 0.394 in., 1 km = 0.6214 miles.

 

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© International Association for Mathematical Geosciences 2013