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COMMODITY SPECIAL REPORT Shale - the new world

ANZ RESEARCH | August 2013

CONTENTS EXECUTIVE SUMMARY 3 SNAPSHOT 4

US ENERGY MIX 5

WINNERS & LOSERS 6

US ENERGY SELF-SUFFICIENCY 6

US LNG EXPORTS 7

IMPACT FOR AUSTRALIAN LNG EXPORTS 9

CHINA’S ENERGY RESPONSE 11

CHINA’S SHALE AMBITIONS 12

SHALE BACKGROUND 14 CONTRIBUTORS Mark Pervan Global Head of Commodity Strategy +61 3 8655 9243 Mark.Pervan@anz.com Natalie Rampono Commodity Strategist +61 3 8655 9258 Natalie.Rampono@anz.com

Publication date: 8 August 2013 Please email research@anz.com with feedback and enquiries

Shale – the new world / 7 August 2013 / 3 of 18

EXECUTIVE SUMMARY

IMPLICATIONS OF THE SHALE REVOLUTION

In this paper we consider the implications of the shale revolution on the US economy, Australian LNG exports, and China’s unconventional gas ambitions. We conclude the US energy market will change dramatically in the next two decades moving rapidly towards self-sufficiency. Australia will continue to see strong investment in LNG, with strong demand offsetting rising US LNG exports. And China will be keen, but slow to develop shale reserves, with a lack of infrastructure, know-how and challenging geology creating headwinds.

KEY POINTS

• The shale boom will drive the US economy to energy self-sufficiency by 2030, with excess coal and gas offsetting a net-short position in oil.

• The US will be largest oil producer in the world by 2020, producing over 11 million barrels of oil per day, surpassing Saudi Arabia and Russia.

• US oil imports will halve by 2020 to 4.5 million barrels per day. This will reduce the US trade bill by USD200 billion, or 4% in today’s prices.

• Low US gas prices have already triggered USD95 billion worth of new US capital projects – the winners are the petrochemical and fertiliser industries.

• US will be exporting LNG from 2016 and be producing 40 million tonnes per annum by 2020, making it the third largest producer after Australia and Qatar.

• Australia’s current committed LNG projects will propel it to the world’s largest LNG producer by 2020 ahead of Qatar, producing 88 million tonnes per annum.

• Increased US LNG exports could delay or reduce the second wave of Australian gas projects, but stronger forecast global LNG demand will see most approved.

• Freight and gas prices will ultimately determine Australia’s supply response. A Henry Hub gas price above USD5mmbtu will give Australian LNG the edge.

• China will contribute the largest share in global gas demand by 2030, growing an impressive 200% over the next 15 years.

• China’s LNG footprint is growing strongly, increasing from 13 to 23 planned, under construction, or operating LNG regasification plants in the past 3 years.

• Despite China’s strong LNG import growth plans, substantial demand will mean a need for major gas pipelines from Russia and South East Asia.

• China will need to develop its own domestic gas supply and holds the world’s largest potential shale reserves of 1,695tcf, twice that of the US.

• We estimate only half China’s shale could be exploited, because of geology, infrastructure and technology hurdles.

• China will need to secure supplies through overseas acquisitions and will be increasingly dependent on gas imports – about 55% by 2030.

Shale – the new world / 7 August 2013 / 4 of 18

ALGERIA

BRAZIL

FRANCE

NORWAY

CHILE

INDIA

CHINAUNITED STATES

ARGENTINA

MEXICO

STH AFRICAAUSTRALIA

CANADA

LIBYA

POLAND

A SNAPSHOT The rapid growth in US shale gas and oil production over the past few years is set to reshape the global energy market in the coming decades. US natural gas and oil production has jumped over 30% since 2005, after no growth in the previous 40 years. Other countries are lining up to assess the potential of their domestic shale reserves, but we think the well-established US energy market is best positioned to exploit this substantial opportunity.

In this paper we consider the implications of the shale revolution on the US economy, Australian LNG exports, and China’s unconventional gas ambitions. We conclude the US energy market will change dramatically in the next two decades, moving rapidly towards self-sufficiency. Australia will continue to see strong investment in LNG, with strong demand offsetting rising US LNG exports. And China will be keen, but slow to develop shale reserves, with a lack of infrastructure, know-how and challenging geology creating headwinds.

We think the big winner in the shale production boom is the US. The US has the know-how, the infrastructure and the political will to exploit large untapped shale reserves. We forecast by 2030 that the US will be self-sufficient in energy supply, with excess gas and coal offsetting a much smaller net short position in oil. In fact, US oil production will double and US oil imports halve in the next 10 years.

The energy-intensive US market will also benefit substantially from lower power costs, and if officials decide to protect this comparative advantage, it could spur a flood of new investment in domestic enterprises. Even if the cheap energy supply is

FIGURE 1. TOP 15 GLOBAL SHALE GAS RESERVES

exploited through LNG exports, we think the prospect of energy self-sufficiency will be a powerful prop for the domestic economy.

Australia has a big stake in the direction of US energy policy. Huge investment in Australian LNG production over the past two years could hit headwinds from the prospect of large US LNG exports in the coming years. While we accept this as a risk, we think it will be muted by the expectation of even stronger global demand for LNG. US LNG exports would also be more competitive in Europe, leaving the strong emerging Asian LNG markets more suited to closer Middle East and Oceania suppliers.

A re-think of the second wave of Australian LNG investment projects (post 2020) is more possible, although an expected easing in the inhibiting high currency and labour costs should make most of these investments more attractive. A key advantage for Australian LNG participants is the large additional footprints being developed for brownfield expansions (expansion to existing assets) – something US LNG entrants won’t have once conversion of existing regasification plants is completed over the next 4-5 years.

The China shale story is still too early to predict, but we know there is strong interest in developing the opportunity. The outcome will come down to economics and development of associated infrastructure. We think environmental concerns will also be a bigger issue than in the US with a more acute water problem and greater issues with seismic activity. Needless to say, the growth in domestic gas demand suggests China will need to exploit all avenues of supply - domestic conventional and unconventional gas, imported pipelined supply and seaborne LNG imports over the decades ahead.

Note: Map not to scale Sources: EIA, Thomson Reuters, ANZ

Shale – the new world / 7 August 2013 / 5 of 18

UNITED STATES

• Natural gas should surpass oil as the number one energy source for US consumers by 2030

• USD95 billion of new capital projects are due to low gas prices – the biggest winners will be the petrochemical and fertiliser industries

• US LNG exports to emerge in 2016 and lift US exports to number 3 global supplier, behind Australia and Qatar by 2020

US ENERGY MIX

SUPPLY

Shale gas is set to become the fastest growing contributor to the US primary energy supply over the next two decades. Advancements in upstream technology have seen a ten-fold increase in technically recoverable reserves of hydrocarbon-bearing shale over the past five years, creating the opportunity for an even larger reserve base going forward. We predict by 2030 that shale gas production will rise by 35% to 10.4 trillion cubic feet, increasing its market share from 28% to 32% of total US energy supply.

Rising associated shale oil production and increased development of ultra deepwater oil reserves will also give the US a considerable lift in domestic crude oil production. We forecast by 2020, US daily crude oil output to double to over 11 million barrels per day –potentially leap-frogging the US to largest oil producer in the world ahead of Russia and Saudi Arabia. That said, we expect US growth rates to slow in the subsequent decade as easily developed liquid-rich gas supplies diminish and energy producers move towards more productive dry-gas drilling areas.

We expect US coal production to remain steady over the next two decades, averaging around 1 billion tonnes per annum. While we don’t expect production to recover to pre-GFC levels, rising coal exports should offset the prospect of lower domestic demand. We do expect a modest pick-up in domestic coal production from 2025, with the commissioning of large new port capacity accessing the previously captive Powder River Basin coal reserves in the US North East.

FIGURE 2. US ENERGY PRODUCTION

350

400

450

500

550

600

650

700

750

00 05 10 15F 20F 25F 30F

Coal Oil Gas

Mtoe

Sources: IEA, BP Statistics, ANZ Commodity Strategy DEMAND

Consistent with rising supply, we expect US demand to swing increasingly to the lower-priced natural gas market over the coming decades. We forecast natural gas consumption to rise 18% to 655 million tonnes of oil equivalent (mtoe) by 2030 - increasing its market share of the total energy market from 25% to 30%. While this period growth rate may seem reasonably modest, it is in context to zero growth in total energy demand over the same period.

In fact, existing and proposed new regulations to lower carbon emissions will constrict oil and coal’s market share for cleaner fuel sources. Natural gas produces about 30% less greenhouse emissions than oil and 40% less than coal. By 2030, natural gas should surpass oil as the number one energy source for US consumers.

FIGURE 3. US ENERGY CONSUMPTION

Renewables Coal

OilGas

Nuclear13%

17%

29%30%

11%

2030F2012

RenewablesCoal

OilGas

Nuclear 6%22%

37%25%

10%

Source: IEA, US EIA, BP Stats, ANZ Commodity Strategy

The biggest market share decline will occur in oil consumption – from 37% in 2012 to 29% by 2030. Oil demand in transport should decline 23% over the next two decades as a focus on fuel-efficient vehicles and hybrid technologies from 2020 onwards limits

Shale – the new world / 7 August 2013 / 6 of 18

the use of gasoline and diesel in light vehicles. While energy demand should rise for heavy trucks as industrial output improves, we believe competitive gas prices will increase gas fuel use, displacing about 250 million barrels of liquid fuels per annum.

We think the coal industry will lose about five percentage points of total US energy market share by 2030 – replaced by natural gas, renewables and nuclear power sources. The drop in coal power use will coincide with a 19% decline or 65 gigawatt (GW) drop in coal-fired capacity to 270GW over the same period. Despite lower coal power use, we think the coal market will remain the largest source of electrical power in the US, contributing about 39% of total power use by 2030, but down from 48% today.

FIGURE 4. US POWER GENERATION

Renewables

Coal

Oil

Gas

Nuclear

15%

39%

0.5%

21%

24%

2030F2012

Renewables

Coal

Oil

Gas

Nuclear

7%

48%

1%

20%

23%

Sources: IEA, BP Statistics, ANZ Commodity Strategy

WINNERS & LOSERS

Cheap abundant natural gas supply should have a significant impact on the energy-intensive US economy. About 10% of domestic manufacturing has energy expenditure greater than 5% of the value of its output and high exposure to foreign competition (also known as energy-intensive, trade–exposed EITE industries). Industry group Industrial Energy Consumers of America, reports as much as USD95 billion worth of new capital projects have been announced in the past couple of years because of low gas prices. We think the biggest beneficiaries reside in the petrochemical industries (particularly in plastics) and in fertilisers – both big direct consumers of gas.

Energy-intensive users, such as aluminium and steel producers, would benefit two-fold, from lower power costs and increased end-use demand. Energy accounts for about 10-20% of total input costs in these industries, so a prolonged decline in gas prices could prop up marginal plants. In addition, rising power industry requirements for rigs, pipelines and other infrastructure – as well as gas-fired power

plant materials (e.g. turbines) – will likely contribute to an overall increase in metal use.

Cheaper natural gas-fired power generation and lower input costs will positively impact the price of electricity, cutting business and household energy bills. The transport industry should also benefit with a rising switch to gas powered vehicles, especially for heavy-duty freight transportation (trucking) and as a feedstock for producing diesel and other fuels. If oil-gas price differentials remain healthy, the natural gas boom could even trigger a host of new gas-for-transport supply projects. Global gas price differentials should also encourage energy producers to exploit rising seaborne demand for gas with the construction of LNG exporting facilities (more on this in the “US as a LNG Exporter” section).

On the flipside, the losers are likely to be energy exporters to the US (mainly South American and Middle East suppliers) and increasingly less competitive domestic coal producers. Non-US companies could potentially lose market share from US companies that are able to maintain a comparative advantage from lower energy costs, but the impact will be less visible compared to the primary energy sector.

US ENERGY SELF-SUFFICIENCY

The forecast rise in US energy supply will imply a move towards energy self-sufficiency. On a net energy basis (exports minus imports), we think this could occur late next decade. Our modelling suggests the US should be in a mild net energy surplus position by 2030. An expected surplus of coal and gas supply will more than offset a smaller net short position in oil. That said, we think the net long energy position will be capped, with political, environmental and transport issues limiting rising exports under only favourable pricing conditions.

Shale – the new world / 7 August 2013 / 7 of 18

FIGURE 5. US NET ENERGY POSITION

(600)

(500)

(400)

(300)

(200)

(100)

0

100

200

00 05 10 15 20 25 30

Oil Coal Gas Total

Mtoe

net importing

net exporting forecast

Sources: IEA, ANZ Commodity Strategy

One of the big trade impacts will be a sharp drop in US crude oil imports. We forecast domestic oil production will double in the next 10 years to over 11 million barrels per day, which could halve US oil imports to 4.5 million barrels per day by 2020. A drop of this level would represent an import saving of nearly USD200 billion, equivalent to 4% of the 2012 US trade bill.

In terms of contribution, crude oil is the single largest US import product at a cost of USD330 billion or 14% of total imports in 2012. By 2020, we forecast oil imports will drop to a cost of USD136 billion representing a much more modest 4% of total imports. Additional savings are also likely – if displaced oil imports, supplemented by domestic supply, are acquired at a significant price discount, as is the case today.

FIGURE 6. US OIL AND OTHER IMPORTS

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

96 98 00 02 04 06 08 10 12 14 16 18 200

5

10

15

20

25

Other Imports Oil Imports % Oil (RHS)

USD trillion %

forecast

Sources: Bloomberg, ANZ Commodity Strategy

On the flipside, the shale boom will trigger the opportunity to export competitively priced LNG and unwanted domestic thermal coal supply. We think the opportunity is more a medium term, rather than near-term strategy, with large new exporting facilities (ports and liquefaction plants) not likely to be commissioned until well into the next decade. That said, the conversion of existing regas importing LNG plants to liquefaction exporting facilities, over the next 5-10 years, could see the US move into a net exporting position of natural gas by 2020 (more in the next section).

In thermal coal, the US is already a net exporter in the order of 17 million tonnes in 2012. While we expect this trend to grow over the next 10 years, the gains will be capped by the exploitation of incremental (brownfield) port expansions on the US east coast (and mainly destined for Europe). The bigger coal export opportunity to Asia will arise from 2025 onwards as the huge Powder River Basin reserves become accessible from new (greenfield) port commissioning on the US north west coast. We forecast US thermal coal exports could rise four-fold by 2030 to 205 million tonnes leapfrogging the US from number six to number three in terms of global thermal coal exports behind Indonesia and Australia.

US LNG EXPORTS

Excess US gas supply will prompt the emergence of LNG exports. We think this will be achieved firstly by the conversion of LNG regasification plants (to liquefaction) and later next decade, standalone greenfield plants for exports. The biggest hurdles will be import feed costs (gas prices) and cheap access to freight. This is likely to be more of an issue longer term (2020 onwards). Economic, regulatory and environmental hurdles also exist, potentially limiting volumes or delaying timing. Ultimately, we think US LNG exports will be contingent on favourable pricing dynamics.

We forecast US LNG exports to grow from nothing currently, to 40 million tonnes by 2020. This would lift US exports quickly to number 3 global supplier, behind Australia and Qatar, with a market share of 10% by 2020. We expect exports to begin in 2016, with the start-up of the 16 million tonne per annum Sabine Pass LNG facility (a converted regas project). Sabine Pass is the only project that has cleared most regulatory and permits hurdles and has already started construction of liquefaction capabilities.

Shale – the new world / 7 August 2013 / 8 of 18

FIGURE 7. US LNG EXPORTS

0

10

20

30

40

50

60

70

80

10 15F 20F 25F 30F0

2

4

6

8

10

12

14

16

US LNG exports US global share (RHS)

m tonnes %

Sources: Wood Mackenzie, ANZ Commodity Strategy

A series of other US projects are under feasibility study for LNG exports – some are regas conversion options and others are entire new plants. However, high capital expenditures and infrastructure constraints could delay timing or lower capacity potential. In our modelling, we assume a realisation rate of about 50% for probable future projects, to generate our 73 million tonne per annum capacity forecast by 2030.

We think feedstock and cost advantages will be maintained until 2020, with gas prices averaging less than USD5.00 per million metric British thermal units (mmbtu), about half the price of gas in Asia. However, any rise in low Henry Hub gas prices (input costs) and dip in Asian LNG prices (revenue) will quickly diminish the economics to export LNG. Another consideration will be the political pressure of arbitraging cheaper domestic gas prices into a more expensive global LNG priced market. We think the government is likely to restrict the number of licenses or export volumes, to manage potentially higher domestic gas prices.

Increased environmental regulations and potential penalties could raise gas input costs. The main worries centre on the large scale use of water in hydraulic fracturing, potentially inhibiting domestic availability, damaging aquatic habitats and increased risk for leaking hazardous chemicals. The US Geological Survey (USGS) has also confirmed that hydraulic fracturing can cause small earthquakes and seismic activity, adding to growing worries over shale output.

Cheap access to freight is another dynamic likely to impact US exports to Asia. We think US gas exports are more likely to be shipped through an expanded Panama Canal to reach Asian markets (46 days), rather than the longer and more expensive route via the Cape of Good Hope (72 days). However, potential delays to deepen the Panama Canal and higher shipping tariffs to fund the cost of the expansion may prevent this route from being the least cost option.

Tough government approvals for contracts to export to countries with no free trade agreements (non-FTA) will slow any LNG export ambitions to top consumers in Asia (China and India). Expansions to existing projects will also have to submit applications for non-FTA approvals. As a result, we think most of the exports will flow to Europe and potentially Japan and South Korea if the economics stack up. Currently, around 236 million tonnes have been approved for FTA country applications, while about 233 million tonnes are being requested for non-FTA countries. We believe LNG exports realised from these projects will be substantially lower than approved export quantities.

FIGURE 8. US LNG EXPORT APPLICATIONS

Sabine Pass 20.8 Approved Partial ApprovalFreeport LNG 21.5 Approved Partial ApprovalMain Pass & Freeport 24.7 Approved DOE ReviewGulf Coast LNG 21.5 Approved DOE ReviewGolden Pass Products 19.9 Approved DOE ReviewCheniere Marketing 16.1 Approved DOE ReviewLake Charles & Trunkline 15.3 Approved DOE ReviewJordan Cove Energy 15.3 Approved DOE ReviewCameron LNG 13.0 Approved DOE ReviewGulf LNG Liquefaction 11.5 Approved DOE ReviewExcelerate Liquefaction 10.6 Approved DOE ReviewLNG Development 9.6 Approved DOE ReviewPangea LNG 8.4 Approved DOE ReviewCE FLNG 8.2 Approved DOE ReviewDominion Cove Point LNG 7.7 Approved DOE ReviewSouthern LNG 3.8 Approved DOE ReviewCarib Energy 0.3 Approved DOE ReviewVenture Global LNG 5.1 Pending DOE ReviewMagnolia LNG 4.1 Approved n/aGasfin Development USA 1.5 Approved n/aWaller LNG Services 1.2 Approved n/aSB Power Solutions 0.5 Approved n/aAdvanced Energy Sol'n 0.2 Pending n/a

Total 241

COMPANY QUANTITY (MT) FTA NON-FTA

Sources: US Federal Energy Regulatory Commission

Shale – the new world / 7 August 2013 / 9 of 18

AUSTRALIA

• Australia and the US will both be winners with a five-fold increase in global gas demand to 530 million tonnes by 2030

• Australia’s location and existing gas supplies will offset rising capital costs, but impact could be on second generation plans

IMPACT FOR AUSTRALIAN LNG EXPORTS

While we expect the rise in US LNG exports could take market share from existing suppliers, such as Australia, a rapid growth in demand will create opportunities for all suppliers. We forecast global gas demand to grow to 530 million tonnes by 2030 (a five-fold increase), in line with an average 5% trend growth in power use. Under this scenario, we think Australia and the US will both be winners and in some cases, take market share away from other mature players. We believe Australia will maintain a favourable exporting position despite rising capital costs, with nearby locality to key Asian demand and excess gas supplies creating a competitive edge.

We project Australian LNG exports to grow rapidly by an average 18% per annum in the first decade (2010-2020) to 88 million tonnes, doubling the growth rates experienced from 2000-2010. On these estimates, Australia’s market share will rise towards 25%, surpassing top producer Qatar by 2019, due to a moratorium in place to manage Qatari gas fields. We think the US could reach about 14% market share over the next two decades, almost half of Australia’s market position in the same period.

FIGURE 9. GLOBAL SUPPLY & MARKET SHARE

0

100

200

300

400

500

600

10 15F 20F 25F 30F0

5

10

15

20

25

30

35m tonnes share %

Australia (RHS)

US (RHS)

Qatar (RHS)

Sources: Bloomberg, ANZ Commodity Strategy

Existing operating costs between Australia and the US look similar. However, Australian processing costs over the past few years have come under increasing pressure from a rising domestic currency and a skilled labour shortage. We believe existing assets will continue to produce as required, but higher costs could have an impact on second generation plans. But even with lower realisation rates, we think Australian exports could expand to 124 million tonnes by 2030, supplying a quarter of the total seaborne market and maintaining Australia’s number one position as the largest LNG exporter.

FIGURE 10. US VERSUS AUSTRALIA PROJECT COSTS

0.01.02.03.04.05.0

6.07.08.09.0

10.0

US Australia

Shipping

Liquefaction

Gas Losses

Gas price

USD/mmbtu

Sources: Wood Mackenzie, ANZ Commodity Strategy

To compare Australian and US cost economics, we used an export cost break-even model. We assume Henry Hub (HH) gas prices and freight to Japan (proxy for Asia) are variable costs, and processing costs of USD3.9mmbtu are fixed (which includes liquefaction costs and gas losses). We compare US export costs against Australian break-even costs of USD9.4mmbtu – incorporating a 25% rise on original capital cost estimates to take cost pressures into account. The shaded region in Figure 11 (next page) shows the pricing points at which US exports become less competitive relative to Australia and figures in bold within the box are what we consider to be realistic price ranges over the next decade.

Shale – the new world / 7 August 2013 / 10 of 18

FIGURE 11. LNG EXPORT COST SENSITIVITY MATRIX

2.5 3.0 3.5 4.0 4.5 5.01.0 7.4 7.9 8.4 8.9 9.4 9.91.5 7.9 8.4 8.9 9.4 9.9 10.42.0 8.4 8.9 9.4 9.9 10.4 10.92.5 8.9 9.4 9.9 10.4 10.9 11.43.0 9.4 9.9 10.4 10.9 11.4 11.93.5 9.9 10.4 10.9 11.4 11.9 12.4S

hip

pin

g (

mm

btu

) Henry Hub Price (mmbtu)

Sources: Wood Mackenzie, ANZ Commodity Strategy

According to our US export cost matrix, HH gas prices above USD5.0mmbtu (shaded region) will be uncompetitive compared to Australian exports to Asia. With US HH gas prices at USD2.3mmbtu, risks are on the upside over the next decade, which could inflate US exporting costs. On the flipside, Australian gas feed costs should be less volatile for existing projects due to long-term contracts in place for gas inputs and a smaller domestic demand profile. We think Australian gas prices will remain comparatively low, averaging USD4.5mmbtu compared to HH prices of around USD5.0mmbtu over the same timeframe.

Australia will maintain shipping cost advantages over the US for the foreseeable future, notwithstanding a dramatic shift in US freight technology. Assuming typical LNG carrier speeds of 19 knots, it takes at least 45 days (<10,700 nautical miles) for US LNG supplies to reach China via the shortest route (the Panama canal), while Australian shipments only take about 15 days (<4,300 nautical miles). Since Australia is about a third of the distance to Asia, freight costs should remain below USD1.00mmbtu, while US shipping costs are likely to be more than USD1.50mmbtu.

Beyond 2020, the window for US LNG exports will likely diminish with second generation investments limited to more expensive greenfield opportunities – including the development of higher costing storage and port capacity. In contrast, Australia has already accounted for brownfield footprint expansions for current projects, which should make increased supplies and exports post 2020 comparatively more efficient.

A possible key sensitivity will be Australia’s access to future cheap feedstock. Rapid expansion of coal seam gas reserves in the Queensland Darling Basin is coming under increasing pressure from agricultural-based activists - the area is known for Australian cotton/beef production. On the flipside, potentially vast new areas of untapped unconventional gas, including shale and coal seam methane, appear to be opening up in the less environmentally sensitive, but existing gas producing Cooper/Eromanga Basin.

FIGURE 12: AUSTRALIA’S MAJOR GAS BASINS

Canning Basin

Surat Basin

Clarence Moreton Basin

SydneyBasin

GunnedahBasin

NSW

QLD

SA

VIC

WA

TAS

NT

ACT

Perth Basin

Shale gas basinsProspective shale gas basinsCBM basinsConventional gas basins

Browse Basin

Bonaparte Basin

McArthur Basin

Southern Carnarvon Basin

Otway BasinOtway Basin Bass/Gippsland

Basin

Carnarvon Basin

Georgina Basin Galillee

Basin

Amadeus Basin

Bowen Basin

Amadeus Basin

Cooper/Eromanga Basin

Note: Map not to scale

Sources: Wood Mackenzie, ANZ Commodity Strategy

Shale – the new world / 7 August 2013 / 11 of 18

CHINA • China will contribute the largest growth in

global gas demand by 2030, up an impressive 150% over the next 10 years

• China holds the largest potential shale reserves of 1,695tcf, but any development of domestic production will likely be slow

• China will secure supplies via overseas acquisitions and will increasingly depend on LNG imports – about 55% by 2030

CHINA’S ENERGY RESPONSE

China’s energy policy is of great importance given a rapid domestic demand growth outlook. China’s total energy requirements will rise over 200% by 2030, with plenty of upside – demand currently represents about a third of energy per-capita consumption in developed countries. We think the scale of the rise in China’s energy consumption means there will be only marginal impacts to China’s energy mix in the medium-term. Beyond 2020, changes to China’s demand mix should be more apparent, as substantial policies geared towards environmentally friendly supplies and renewable energies favour natural gas, nuclear and hydroelectric power generation over thermal coal.

We believe China will contribute the largest growth in gas demand (conventional and unconventional) globally, increasing by an impressive 150% to 250 million tonnes of oil equivalent (mtoe) over the next 10 years – as China continues to urbanise and industrialise its huge population base during this timeframe. Longer-term we anticipate gas to account for almost 10% of total demand by 2030 – from just 4% currently. Downstream gas-power generation will grow about 8% from 2%, with the rest of the growth expected in commercial and residential buildings.

We think capacity constraints in hydroelectricity power generation by the end of this decade will leave room for growth in other clean energies including natural gas and nuclear. Hydroelectricity demand caps out at around 6% of China’s power mix, but only represents 3% in overall energy use. We think nuclear will be a longer-term development story, accounting for about 5% of China’s total energy mix, from 1% currently. We anticipate as much as 30,000 tonnes of uranium will be consumed by 2030, with the majority of the uranium sourced locally.

The scale of China’s power demand growth projections means the country will continue to consume substantially larger amounts of coal, despite a 15% decline in coal’s contribution to 55% in China’s total energy mix by 2030. The scale of China’s rising energy needs, projected to increase by some 240%, still implies an increase of current coal consumption to over 5 billion tonnes per annum, from 3.3 billion tonnes currently. Like the US, we think coal combined with oil in China will still account for the largest proportion of the energy mix, around 70%.

China’s oil market share will remain sticky around 18% or 712mtoe of China’s total energy mix over the next two decades and will also contribute the most to rising Asian oil refinery capacity. Focus will be on improving technologies for higher quality products to meet environmental obligations and switches from gasoline to diesel. We think increasing consumption of oil will mostly be met by greater imports given the constraints on China’s mature domestic production, with China’s oil import dependency to be about 75% compared with 54% today.

FIGURE 13: CHINA’S ENERGY CONSUMPTION MIX

Coal70%

Oil18%

Renewables6%

Gas4%

Hydro1%

Nuclear1%

2012

Coal55%

Oil18%

Renewables9%

Gas10%

Hydro3%

Nuclear5%

2030F

Sources: NDRC, ANZ Commodity Strategy

Similar to the initial energy growth stages in the US, China is likely to outstrip domestic production supplies and will need to be met by imported LNG. We expect China to be about 55% dependent on gas imports by 2030, from around 20% currently. China has more than doubled its LNG footprint in the past 3 years, having gone from 13 planned, under construction or operating LNG regasification plants to 33. Total import capacity will equate to around 105 million tonnes per annum (mtpa) by 2020 if all the projects go ahead. Although China has strong ambitions to grow LNG import capacity in the East, we think the significant growth in gas consumption also means China will continue to develop gas pipelines from Russia and nearby southwest Asian regions.

Shale – the new world / 7 August 2013 / 12 of 18

FIGURE 14: OPERATING & APPROVED IMPORT TERMINALS

PROVINCE PROJECT CAPACITY (MT)

Dapeng Phase 1 6.8

Fujian Phase 1,2 7.8

Shanghai Phase 1,2 12.0

Jiangsu Phase 1,2 6.5

Dalian Phase 1,2 6.0

Ningbo Phase 1 3.0

Zhuhai Phase 1 3.5

Tangshan Phase 1 6.5

Shenzhen Phase 1 3.0

Hainan Phase 1 2.0

Jieyang Phase 1 2.0

Tianjin 2 projects 5.2

Shandong Phase 1,2 8.0

Beihai Phase 1 3.0

Total 75

Sources: Thomson Reuters, ANZ Commodity Strategy

CHINA’S SHALE AMBITIONS

China holds the largest potential shale reserves of around 1,695tcf, but there are many issues surrounding the development of domestic supplies, particularly in relation to geology, infrastructure and technological know-how. We think China will therefore secure supplies through overseas acquisitions and importing in the near-term, while the development of shale prospects will be a longer-term ambition.

Despite China being only in the exploratory phase of developing domestic shale supplies, the National Development and Reform Commission (NDRC) is anticipating gas from shale sources to account for about 13% of total supplies by 2020. The government is targeting 229bcf (4.8mt) by 2015 and anywhere between 2,100-3,550bcf (45-75mt) of gas to be extracted by 2020. We believe this is overly optimistic, with many hurdles likely to hinder domestic shale production.

Geology

Although China has substantial shale reserves, not all of these reserves can be developed with current technologies. China has seven major shale gas basins, but five of them are of non-marine based

reserves with large clay density, which means that fracking technologies are currently unable to extract shale gas or oil from these reserves. However, the remaining two basins, Tarim in the North West and Sichuan in Central China, do have potentially recoverable reserves, estimated to be in the order of 1,275tcf. This is almost 1.5 times the amount of the US’s total shale reserves of about 860tcf recoverable shale reserves.

Geological data still needs to be clarified, especially the extent of folding and faults. From the geological data that is available, the Sichuan and Tarim basins have considerable potentially viable reserves. The majority of these have been reported to be substantially deeper than those in US, but are within range for viable extraction. The problem is the Sichuan area has considerable geological folding and faults, which would greatly reduce the potential for horizontal fracking. This may be less of an issue for the Tarim basin, but with deeper reserves within a mountainous and more remote region, the accessibility and depth of the reserves will likely be problematic for extraction.

FIGURE 15: CHINA’S MAJOR SHALE BASINS

GUANGZHOU

Tarim Basin

Rudong

Wuhaogou

Shanghai

FujianDapeng

West-East II

West-East

BEIJING

SHANGHAISichuan Basin

Junggar Basin

Ordos Basin

Songliao Basin

Bohai Basin

Nth China Basin

\LNG receiving terminal]

LNG constructed/proposedHigh consuming region

Prospective shale gas basinsCoal depositsPipelines

Note: Map not to scale

Sources: US EIA, ANZ Commodity Strategy

Infrastructure

Both the Tarim and Sichuan basins already provide conventional oil and gas. However, the level of overall infrastructure remains relatively low compared to the US. For instance, China only has 50,000km of existing gas pipelines, and the US has over 480,000km. China only expects to increase its

Shale – the new world / 7 August 2013 / 13 of 18

pipeline capacity to about 100,000km by 2015, which is still only a fifth of the US’s existing infrastructure. Shale gas reserves also tend to be higher in corrosive sulphites than conventional gases, which could add to the costs of refining before distribution. Alternatively, additional pipelines that are less corrodible would have to be built.

As already suggested, the mountainous and remote nature of the Tarim basin will likely impede both drilling and the required infrastructure. The Sichuan basin also has land-use problems, as it is also a principle region for agriculture in China. This means there could be potential conflict in the use of land for multiple well drilling and pipelines against agricultural requirements. In addition, the potential contamination of already stretched water supplies from fracking could be an even bigger concern for Chinese residents, compared to the US. Especially since these environmental concerns are already starting to gain legislative traction in the US.

Another, and potentially major, concern is the risk of seismic activity in the Sichuan basin. Several years ago, earthquakes in Sichuan caused the death of some 60,000 people. The concern that multiple subterranean explosions needed to shatter shale formations and allow for gas extraction could inadvertently trigger earth tremors or even earthquakes, will likely impede shale gas development. The massive Three Gorges Dam, with its huge hydroelectric generation, also lies within this region and any increase in seismic activity will obviously raise concerns over its security as well.

Stage of development

With very few exploratory wells being drilled, potential reserves are still some way from being verified, let alone extracted. Despite the Chinese authorities stating the development of shale gas is a priority, less than 100 exploratory drills are currently in place across China, suggesting extraction is some way off. In the US, there are currently some 40,000 wells. Given that key technologies for extraction are concentrated within US corporations, the development of China’s resources will be highly dependent upon joint ventures with international resource companies.

Conoco-Phillips, Shell, Chevron, EOG and Newfield are already involved with China’s state-owned oil company PetroChina. However, there continue to be questions surrounding the effectiveness and security of transferring intellectual property and technologies for drilling to Chinese counterparts. Despite joint venture activity to bid for exploratory blocks, we think extraction will likely be more of a 10-20 year event, but we will be following this market closely for any new breakthroughs.

Shale – the new world / 7 August 2013 / 14 of 18

SHALE BACKGROUND

GLOBAL GAS RESERVES & PRODUCTION

Globally there are over 14,124 trillion cubic feet (tcf) of remaining recoverable resources of conventional gas, according to the IEA. This is equivalent to around 120 years of production at current rates. Russia, Iran, and Qatar together account for more than half of the world’s proven conventional gas reserves. While uncertain, unconventional recoverable resources are estimated to be similar in size to conventional resources, bringing total gas reserves to around 250 years of production. China is estimated to have the highest amount of unconventional resources followed by the US – while Australia is in 5th spot.

World gas production in 2011 was estimated at around 116tcf, of which the largest producers were Russia and the US. Unconventional gas production accounted for about 15% of total gas production in 2011. Australia is the world’s fifteenth largest gas producer, accounting for about 1.8% of global gas production with a lot of upside potential. Although China has vast gas resources, they are only 6th in world production rankings as of 2011.

FIGURE 16. GLOBAL GAS RESERVES

0 2,000 4,000 6,000

NigeriaNorway Algeria

IndonesiaVenezuela

CanadaMexico

ArgentinaAustralia

QatarSaudi Arabia

IranChina

USRussia

Conventional

Shale

Tight

Coal-bed methane

tcf Sources: IEA, ANZ Commodity Strategy

GAS CONSUMPTION

Gas is the third largest global energy source, accounting for around 20% of global primary energy consumption. The four largest gas consumers are the US (21%), Russia (14%), Iran (4%), and China

(3%). Global gas consumption increased at an average annual rate of about 3% since 2000 and totalled 120tcf in 2011. The largest share of gas trade is carried by pipelines, with inter-regional flows accounting for about 58% of the total in 2011. The largest share of growth has been taken by LNG exports, with LNG trade accounting for around 9% of global gas consumption. Global LNG trade has expanded rapidly – by 7.8% per year since 2000 – to reach 243 million tonnes in 2012, led by a wave of capacity additions from current top exporter Qatar. The recent growth in shale gas production will no doubt have major implications for future LNG flows.

SHALE GAS RESERVES & PRODUCTION

Technically recoverable shale resources account for more than a quarter of total global gas reserves or about 6,622tcf based on estimates of fourteen regions from the US EIA. The IEA suggests global shale resources could be closer to 7,200tcf. The vast majority of shale resources are located in China, followed by the US, Argentina, and Mexico, which is consistent according to both IEA and EIA sources.

Although China holds the vast majority of shale resources, the country is still in the exploration stage, so shale gas production has not started. Australia’s shale gas exploration is also in its infancy, but has significantly increased in the last few years. The US is the market leader in terms of shale production, with many countries trying to mimic.

FIGURE 17. SHALE GAS RESERVES

0200400600800

1,0001,2001,400

Chi

na US

Arg

entin

aM

exic

oS

Afr

ica

Aus

tral

iaC

anad

a

Liby

aA

lger

iaB

razi

lPo

land

Fran

ce

Nor

way

Chi

leIn

dia

tcf

Sources: EIA, ANZ Commodity Strategy

Shale – the new world / 7 August 2013 / 15 of 18

SHALE OIL RESERVES & PRODUCTION

The US Energy Information Agency (EIA) estimates that shale oil makes up 10 per cent (345 billion barrels) of global technically recoverable oil resources. While shale oil is found in over 30 countries worldwide, the largest technically recoverable shale oil resources are thought to be in Russia (75 billion barrels) followed by the US (58 billion barrels) and China (32 billion barrels). Australia is thought to rank number six with as much as 18 billion barrels.

It is important when considering resource estimates to distinguish between technically recoverable and economically recoverable resources. Technically recoverable resources are volumes that could be produced with current technology, regardless of prices and production costs. While economically recoverable resources are resources that can be profitably produced under current market conditions. Economically recoverable resource can significantly influences by local above ground factors like ownership rights, access to infrastructure and critical expertise and availability of water. Given the wide variability in above ground factors the extent to which technically recoverable resources will be converted to production is not yet clear.

FIGURE 18. SHALE OIL RESERVES

US 17%

China 9%

Venezuela 4%

Australia 5%

Mexico 4%

Russia 22%

Argentina 8%

Libya 8%

Other 19%

Pakistan 3%Canada 3%

Sources: EIA, ANZ Commodity Strategy

SHALE SUPPLY CHAIN

There are different stages of development to extract shale gas (or shale oil) and deliver to domestic and export markets. These include exploration, development, production, processing and transport. While different technologies can be used to extract different unconventional gases, once extracted, the

successive activities across the supply chain are similar to conventional natural gas. FIGURE 19. GAS SUPPLY CHAIN

Project

Exploration

Export market

Domestic market

Development

LNG Plant

LNG Tanker

World Market

Processing Plant

Power Generation

Pipeline

Pipeline

Residential

Commercial

Industry

End-useProcessing, Transport, Storage

Source: BREE, ANZ Commodity Strategy

Once a decision to proceed has been made and financial and regulatory requirements addressed, infrastructure and production facilities are developed. Reports suggest that up to 80% of natural gas wells drilled in the next decade will require hydraulic fracturing (“fracking”) combined with horizontal drilling techniques to produce shale products. Fracking makes it possible for shale oil extraction to produce oil and natural gas in places where conventional technologies are ineffective.

Fracking is a type of drilling process. Water and sand is pumped into the ground to create cracks (also known as fissures or fractures) to release the gas or oil from rocks into wells built for collection. While 99.5% of the fluids used consist of a sand-water mixture, sometimes chemicals are added to improve the flow. The process of bringing a well to completion is generally short-lived, taking a few months for a single well, after which the well can be in production for 20 to 40 years.

FIGURE 20. HYDRAULIC FRACKING

HydrofrackZone

Shale Deposit

Wellhead

Well is turned horizontal

Aquifer

Sources: BREE, ANZ Commodity Strategy

Shale – the new world / 7 August 2013 / 16 of 18

Current shale playsProspective shale playssdfdsdf

Coal depositsMountainous rangesLNG liquefaction plantsLNG existing regas plants

APPALACHIAN MTS

ROCKY MTS

Barnett

CANADA

Bakken

Haynesville - Bossier

Fayetteville

Woodford

Eagle Ford

Maltrata

New Albany

MEXICO

UNITED STATES

FREEPORT SABINE PASS

COVE POINT

LAKE CHARLES

Marcellus

THE US SHALE EXPERIENCE

US shale gas production is not a recent phenomenon. Shale gas was first extracted in 1825 – although production on an industrial scale did not begin until the 1970s. The combination of favourable government policies, unique US land ownership laws and technological advances has made natural gas from shale the fastest growing contributor to the total primary energy mix in the US over the last decade – increasing 26 times and currently comprising about 30% of US total gas output.

FIGURE 21. US NATURAL GAS SUPPLY

0

5

10

15

20

25

90 95 00 05 10Other Oil linked CBM Tight gas Shale gas

tcf2012

32%

26%

8%8%

2000

2%

21%8%

55%25%

15%

Sources: US EIA

To improve energy self-sufficiency and reverse the decline in natural gas reserves in the 1970s, the US Federal government invested in shale R&D, implemented encouraging policies (tax credits and deregulated wellhead prices) and granted exploration permits. Land ownership laws unique to the US – private owners have the commercial rights to mine resources found on their land – and profit-sharing with private owners, have also been instrumental in the quick development of local shale gas resources.

Technological advances in horizontal drilling and hydraulic fracturing, cost efficiencies from new technologies and availability of capital have contributed to the more recent gains in shale production. An estimated 35,000 wells are hydraulically fractured annually and it is estimated that over one million wells have been hydraulically fractured since the first well in the late 1940s.

A spike in natural gas prices to record highs of USD13.5mmbtu in 2005 – after Hurricane Katrina shut down all refinery capacity in the Gulf of Mexico – was another catalyst for higher shale production.

US natural gas production has jumped sharply since then, up 27% from 49.5bcf/day in 2005 to 63.0bcf/day in 2011, as producers profited from higher gas prices.

Outside of the more developed Barnett shale play in Texas, the US EIA estimates that four major shale plays (Haynesville, Fayetteville, Marcellus, and Woodford) may account for 55 trillion cubic feet (tcf) of gas, or ~3% of the ~1,750tcf of technically recoverable reserves. Unproved resources in the US are generally more than double proved reserves. As equipment and drills are installed, unproven resources should switch to marketable gas supplies, prompting even greater production of shale gas.

Rising horizontal rigs also imply more shale energy in future, with active horizontal rigs as a share of total rigs rising from 10% in 2005 to around 60% currently. However, higher relative oil prices compared to natural gas means greater returns for producers and increased substitution from shale gas rigs (down to a 13-year low) to shale oil rigs. The reverse will likely occur if gas prices strengthen like they did in 2005, improving the economics to supply gas.

FIGURE 22. US SHALE PRODUCTION LOCATIONS

Note: Map not to scale

Sources: US EIA, ANZ Commodity Strategy

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