The Increasing Importance of Australia’s Onshore Petroleum ......the offshore Browse, Carnarvon and Bonaparte basins.＊10 Additional resources of petroleum liquids can be found

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The Increasing Importance of Australia’s Onshore Petroleum Resources

（1）Gas Resources

　Austra l ia’s tota l ident i f ied convent iona l and unconventional gas resources are estimated at 392 trillion cubic feet（tcf）, according to Geoscience Australia（Table 1）＊1. Around 97％ of the conventional gas resources are located off the north-west coast in the Carnarvon, Browse and Bonaparte basins and off the south-east coast in the Gippsland Basin（Figure 1）＊2. The main region for conventional onshore gas resources is central Australia’s Cooper Basin. Total identified conventional gas resources are estimated at 166 tcf＊3.　All of Australia’s unconventional gas resources（CSG, shale and tight gas）are located onshore and account for over half of the country’s identified gas resources. The development of Australia’s significant CSG resources in Queensland’s Bowen and Surat basins as well as the

Sydney, Gunnedah, Gloucester and Clarence-Moreton basins in New South Wales has shifted attention back to onshore exploration and development. Total identified CSG resources are estimated at 203 tcf＊4.　Smaller unconventional tight gas accumulations are located in South Australia, Western Australia and Victoria. Total identified tight gas resources are estimated at 20 tcf＊5.　There are only 2 tcf of identified shale gas resources, which are located in the Cooper Basin＊ 6. However, there are potentially large shale gas resources in Western Australia, South Australia, Queensland and the Northern Territory. The US Energy Information Administration（EIA）released a report in June 2013 that assessed the risked, technically recoverable shale gas resources from six of Australia’s basins（Beetaloo,

JOGMEC Sydney Office Lainie Kelly

　現在、オーストラリアでは海域における在来型ガスのほか、陸域での石炭層メタンガス（Coal Seam Gas：CSG。オーストラリア以外の国ではCoalbed Methane：CBMと呼称）の開発が進められており、両者を原材料とするLNGプロジェクトが複数進んでいることは周知のとおりである。　石油・ガス探査は当初、すべて陸域で行われていたが、1960年代から1970年代にかけての大型発見により海域に重点が移った。これまでのほとんどの石油・ガス生産は海域におけるものであるが、近年ではCSG産業の発展により陸上ガス資源はより大きな役割を果たすようになっている。2014年にクイーンズランド州カーティス島で世界初のCSG LNGプロジェクトが生産を開始したほか、さらに二つのCSG LNGプロジェクトが2015年に稼働開始の予定である。また、中央オーストラリアのCooper Basinをはじめとした国内各地において、非在来型のシェールガスおよびタイトガスの初期陸上探査も開始されている。　本稿では、ますます注目度が高まるオーストラリア陸域における石油・ガスの探鉱開発に関して、これまでの経緯を振り返るとともに、連邦政府および各州・準州における関連法規制、税制などについて概説を試みた。

はじめに

1. Location of Petroleum Resources

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Canning, Cooper, Georgina, Maryborough and Perth）are 437 tcf（Figure 3）＊7.

（2）Oil Resources

　Austra l ia’s tota l demonstrated convent iona l resources of petroleum liquids（crude oil, condensate and LPG）are estimated at 3779 million barrels of oil

（Table 2）＊ 8. Just like Australia’s conventional gas resources, the majority of conventional resources of petroleum liquids（around 95 ％）are located off the north-west coast in the Carnarvon, Browse and Bonaparte basins and off the south-east coast in the

Resource Category Conventional Gas Coal Seam Gas Tight Gas Shale Gas Total Gas

EDR※¹ 99 tcf 33 tcf ～3 PJ 132 tcf

SDR※² 57 tcf 60 tcf 2 tcf 119 tcf

Inferred※³ ～10 tcf 111 tcf 20 tcf 141 tcf

All identified resources 166 tcf 203 tcf 20 tcf 2 tcf 392 tcf

Estimates of potential resources-undiscovered, in ground and preliminary

227 tcf 235 tcf Unknown 437 tcf※⁴

Total Gas Resources in AustraliaTable1

Note： 1 trillion cubic feet（tcf）Source： Geoscience Australia and Bureau of Resources and Energy Economics Australian Energy Resource Assessment 2014※1. Economic Demonstrated Resources（EDR）are resources with the highest levels of geological and economic certainty and include

remaining proved plus probable commercial reserves of petroleum.※2. Sub-economic Demonstrated Resources（SDR）are resources for which profitable extraction has not yet been established.※3. Inferred Resources are those with a lower level of confidence that have been inferred from more limited geological evidence and are

assumed, but not verified.※4. Shale gas estimates are from US Energy Information Administration 2013

AdavaleAdavaleAmadeusAmadeusCanningCanning

CooperCooper

BonaparteBonaparte

BrowseBrowse

CarnarvonCarnarvon

PerthPerth

OtwayOtwayBassBass

GippslandGippsland

SydneySydneyGloucesterGloucesterGunnedahGunnedah

SuratSurat

BowenBowen

Clarence-MoretonClarence-Moreton

Conventional Gas ResourcesCoal Seam Gas ResourcesConventional Gas ResourcesCoal Seam Gas Resources

Location of Australia’s Conventional Gas & CSG ResourcesFig1

Source： Geoscience Australia and Bureau of Resources and Energy Economics

McKelvey Basin Crude oil Condensate LPG

EDR Bonaparte 121 308 244

EDR Browse 0 665 0

EDR Carnarvon 552 800 497

EDR Gippsland 177 94 145

EDR Other 80 51 47

EDR Total 930 1,917 932

SDR Bonaparte 68 117 0

SDR Browse 2 423 348

SDR Carnarvon 182 132 13

SDR Gippsland 61 69 0

SDR Other 14 58 53

SDR Total 326 799 414

EDR+SDR Total 1255 2,716 1,345

Crude Oil, Condensate & LPG McKelvey Classification Estimates, January 2012Table2

Source： Geoscience Australia and Bureau of Resources and Energy Economics Australian Energy Resource Assessment 2014

mmbbls

AmadeusAmadeusCanningCanning

CooperCooper

BonaparteBonaparte

BrowseBrowse

CarnarvonCarnarvon

PerthPerth

OtwayOtwayBassBass

GippslandGippsland

Bowen/SuratBowen/Surat

Crude Oil ResourcesCondensate ResourcesLPG Resources

Crude Oil ResourcesCondensate ResourcesLPG Resources

Location of Australia’s Crude Oil, Condensate & LPG ResourcesFig2

Source： Geoscience Australia and Bureau of Resources and Energy Economics


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Gippsland Basin（Figure 2）＊ 9. The first petroleum liquid discoveries onshore were overshadowed by the successful discoveries offshore in the Bass Strait’s Gippsland Basin in the 1960s. Today most of the conventional resources of petroleum liquids are condensate and LPG associated with large gas fields in the offshore Browse, Carnarvon and Bonaparte basins.＊10

Additional resources of petroleum liquids can be found offshore in the Bass, Otway and Perth basins as well as onshore in the Canning, Amadeus, Cooper-Eromanga and Bowen-Surat basins.　The r e a r e n o d emon s t r a t e d r e s o u r c e s f o r unconventional shale liquids and light tight oil, but preliminary exploration in several onshore basins is ongoing. The 2013 EIA report assessed that the risked, technically recoverable shale oil resources from five of

Australia’s basins（Beetaloo, Canning, Cooper, Georgina and Perth）are 17.5 billion barrels of oil（Figure 3）＊11.

2. Petroleum Exploration & Production

（1） Early Onshore Petroleum Exploration &

Production

　In 1900 Australia’s first gas discovery was made by accident when a water bore found gas in the Surat Basin in Queensland. In 1953 the first significant oil flow was at Rough Range in the onshore section of the Carnarvon Basin, Western Australia. There were other onshore oi l f inds , but it was not unti l 1962 that Australia’s first commercial oil production began at the onshore Moonie oil field in the Surat Basin.　During the 1960s and 1970s onshore oil and gas discoveries were made in the Cooper Basin and it has become Australia’s largest conventional onshore oil and gas province. The Cooper Basin is located in north-east South Australia and south-west Queensland in central Australia. The region’s main producing fields are part of the South Australian Cooper Basin（SACB）and South-West Queensland（SWQ）joint ventures, which are operated by Santos with partners Beach Energy and Origin Energy. In 1963 Santos made the first significant gas discovery in the Cooper Basin with the Gidgealpa-2 well＊ 12. The Moomba-1 discovery in 1966 confirmed the region as a major petroleum

province and gas suppl ies to Adelaide in South Australia commenced in 1969＊13. The first commercial oil discovery was the Tirrawarra field in 1970, but oil production did not commence until 1982. It was also in the Cooper Basin that Australia’s largest onshore oil discovery, Jackson-1 was made in 1981.　The Cooper Bas in jo int ventures proved and probable recoverable reserves were 480 million barrels

（mmbbls）of oil（crude oil, condensate and LPG）and 8,313 billion cubic feet（bcf）of gas＊14 The remaining proved and probable reserves are 69 mmbbls of oil and 1,484 bcf of gas as of January 2015＊ 15. The Cooper Basin joint ventures contain approximately 190 gasfields and 115 oilf ields currently on production＊ 16. Gas production from the Cooper Basin joint ventures peaked at over 700 million cubic feet per day（mmcfd）between 1999 and 2002 and oil production peaked at 28,500 barrels per day（bpd）in 1989＊17. Even though production at the Cooper Basin joint ventures has been i n dec l i ne f o r more than a decade , pe t ro l eum production was over 63kboe/d in 2014＊18.　Smaller onshore oi l and gas f ields in Western Australia’s Perth Basin and the Northern Territory’s

GeorginaGeorgina

BeetalooBeetaloo

CooperCooperMaryboroughMaryborough

Perth

Technically Recoverable Shale Oil ResourcesTechnically Recoverable Shale Gas ResourcesTechnically Recoverable Shale Oil ResourcesTechnically Recoverable Shale Gas Resources

CanningCanning

Shale Gas93tcfShale Gas93tcf






Shale Oil0.5billion bblShale Oil0.5billion bbl





Australia’s Assessed Prospective Shale Gas & Shale Oil BasinsFig3

Source： US Energy Information Administration 2013

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Amadeus Basin have been supplying the domestic market for decades. In 1965 the Dongara field was discovered in the Perth Basin and resulted in the state’s first gas pipeline. The Dongara field had original gas in place of 540 bcf and potential oi l r e s e r v e s o f 9 - 1 0 mmbb l s＊ 19 . G a s p r odu c t i o n commenced from Dongara in 1971 followed by oil production in 1975. Gas production peaked in the early 1980s at 90 mmcfd＊20 and has declined to 1.5 mmcfd in 2014 ＊ 21. Oil production peaked in 2004 at 6,150 bpd and ceased production in 2014＊ 22. The Waitsia gas discovery made in 2014 in the Perth Basin could represent the largest onshore conventional gas discovery in Western Australia since the Dongara gasfield, according to operator AWE＊ 23. AWE is targeting production from the Waitsia field by mid-2016. Other important discoveries in the Perth Basin include the Woodada gasfield in 1980 and the Beharra Springs gasfield in 1990. The Woodada field has ceased production, but Beharra Springs is still producing gas for the domestic market.　In the Northern Territory’s Amadeus Basin there has been production from the remote Mereenie oil and gas field since the 1980s. Discovered in 1964, the Mereenie field proved and probable recoverable reserves were 23 mmbbls of oil and 236 bcf of gas＊24. Santos reports remaining reserves of 8 mmbbls of oil and 116 bcf of gas. Oil production commenced in 1984 and peaked a t 3 , 400 bpd in 1986 ＊ 25 . The f i e ld produced about 500 bpd of o i l in 2014 , which is transported by road to Port Bonython in South Australia＊26. Gas production commenced in 1987 and peaked at 44 mmcfd in 2007 ＊ 27. The field stopped producing gas in 2010 when the Northern Territory’s Power and Water Corporation ceased its contracts with the Mereenie field and now all produced gas is reinjected. Other significant discoveries in the Amadeus Basin include Central Petroleum’s Palm Valley gasfield, wh ich has been produc ing s ince 1984 . Centra l Petroleum’s nearby Dingo gasfield also started producing gas for the domestic market in 2015. More recently Central Petroleum discovered the Surprise oilfield in 2011,which commenced production in 2014. Surprise in the Amadeus Basin was the Northern Territory Government’s first approval of an onshore

petroleum production licence in more than 30 years.　Since oil production commenced from Barrow Island offshore Western Australia and the Gippsland Basin o f f shore V ic tor i a in the 1960s the ma jor i ty o f production has come from offshore fields（Figure 4）. 　Whereas, gas production from onshore fields was initially greater than offshore fields in the 1960s and 1970s as a result of production from the Cooper Basin and smaller onshore fields in Queensland and Western Australia. However, this changed in 1984 with the start-up of gas production from the North West Shelf Domestic Gas Project and increased production from the offshore Gippsland Basin Joint Venture（Figure 5）.

（2）Offshore Exploration & Production

　In 1965 the ExxonMobil/BHP Billiton Gippsland Joint Venture discovered the Barracouta gasfield in the Bass Strait. Two years later Kingfish was discovered and is still the largest oilfield ever discovered in

250

200

150

100

50

01979 1989 1999 2009 2014

mmbbls

y

Onshore

Offshore

Australia’s Onshore & Offshore Crude Oil, Condensate & LPG ProductionFig4

Source： APPEA Production Statistics

2,000

1,800

1,600

1,400

1,200

1,000

800

600

400

200

01979 1989 1999 2009 2014

bcf

y

Onshore

Offshore

Australia’s Onshore & Offshore Conventional Gas & CSG ProductionFig5

Source： APPEA Production Statistics


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Australia. These and other subsequent offshore oil and gas discoveries were made by the Gippsland Joint Venture, and today there are 23 offshore platforms and installations in the Bass Strait＊28. Despite the decline of the Bass Strait oilfields since 1985 and the gasfields since 2008 the Gippsland Joint Venture remains an important source of energy for the domestic market, producing around 183,562 barrels of oil equivalent per day（boe/d）in 2014＊29.　The Woodside-operated North West Shelf Project commercialised huge gas, oil and condensate fields discovered off the coast of Western Australia and is a symbol of offshore resources dominating force in Australia’s oil and gas industry. The North West Shelf exploration drilling began in 1967 and major gas and

condensate discoveries were made in 1971 at Scott Reef, North Rankin and Angel. In 1972, the Goodwyn gas and condensate field was discovered to the west of North Rankin. Domestic gas deliveries commenced in 1984 and in 1989 Australia shipped its first cargo of LNG from the North West Shelf Project to Japan. In 2014 the North West Shelf Project was Australia’s largest resource project and accounted for 624,658 boe/d of petroleum production（Figure 6）＊30. In 2014, Australia’s total petroleum production was 1.5 mmboe/d, of which only 17％ came from onshore basins（Table 3）＊31.

（3）Australia’s Coal Seam Gas Industry

　In the early 1990s unconventional onshore CSG was initially produced as a by-product of coal mining in New South Wales, and the first commercial CSG production did not occur until 1996 in the Dawson Valley area of the Bowen Basin in Queensland.Since 1996 Australia’s CSG production has grown rapidly to reach 390 bcf（413.7 PJ）in 2014-15＊32. Queensland is the main producer of CSG with about 98 ％ coming from the Surat and Bowen basins（Figure 7）. The remaining production comes from the Sydney and Gunnedah basins in New South Wales.　Historically conventional gas from the onshore Cooper Basin and the offshore Gippsland Basin has supplied most of eastern Australia’s gas demand. In the 2000s Cooper Basin gas production peaked and then began to

decline. Meanwhile, CSG production has steadily increased becoming an important gas supply source for eastern Australia, particularly in Queensland where CSG supplies over 90％ of the state domestic market＊33. T h e m a i n r e a s o n f o r t h e C S G industry’s continued growth is the Queensland LNG export projects the first of which commenced production in 2014.　In 2007-08 the first proposals to develop Queensland’s CSG resources f o r LNG expo r t p r o j e c t s we r e a n n o u n c e d a n d i n t e r n a t i o n a l c ompan i e s b eg a n i n v e s t i n g i n Australia’s CSG industry. The three

Australia’s Onshore & Offshore Petroleum Production by basinTable3

Note： barrels of oil equivalent per day（boe/d）, million barrels of oil equivalent per day（mmboe/d）. Petroleum production includes petroleum liquids（crude oil, condensate and LPG）and gas（conventional gas and CSG）.

※ 1.The Perth Basin has both onshore and offshore production.Source： EnergyQuest

624,658

183,562128,767

63,01463,014

462,353 North West Shelf

Gippsland Basin Joint Venture

Pluto LNG

Cooper Basin Joint Ventures

Other

boe/d

Australia’s Petroleum Production by Major Producing Project 2014Fig6

Source： EnergyQuest

Onshore Petroleum Production by Basin

2014boe/d

Offshore Petroleum Production by Basin

2014boe/d

Amadeus 1,307 Bonaparte 43,485

Canning 1,080 Gippsland 187,595

Cooper 93,427 Carnarvon 948,463

Surat-Bowen 148,997 Bass 8,819

Gunnedah 79 Otway 50,852

Sydney 2,192

Perth ※ 1 4,167 Perth 1,890

Total 251,249（17%） Total 1,241,104（83%）

Total Australia 1.5 mmboe/d

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approved CSG to LNG projects on Curtis Island in the port of Gladstone in Queensland are Queensland Curtis LNG（QCLNG）, Gladstone LNG（GLNG） and Australia Pacific LNG（APLNG）（Table 4）. The CSG LNG projects are underpinned by several key CSG fields located in the Surat and Bowen basins, which also supply the domestic market. This includes the Santos-operated Fairview CSG field discovered in 1994 in the Bowen Basin, which began first gas sales to the domestic market in 1997. Another key CSG field is Spring Gully, which was discovered in 1998 in the Bowen Basin and commenced commercial production in 2005.Spring Gully is now operated by the APLNG project participants. The Argyle-Kenya CSG field located in the Undulla Nose development area of the Surat Basin comprises the Argyle, Kenya, Lauren and Codie accumulations. In 2000 QGC（formerly known as Queensland Gas Company）drilled the first Argyle exploration wells and domestic gas production commenced in 2007. The Berwyndale and Berwyndale South CSG fields are also located in the Undulla Nose development area. In 2001 QGC drilled the first exploration wells and commercial production commenced in 2006 from Berwyndale South.　In 2014-15 Australia's total CSG production was 1,070 mmcfd of which 1,057 mmcfd came from Queensland's CSG fields in the Surat and Bowen basins. By 2019-20 Australia's CSG production is forecast to increase to 3,879 mmcfd mainly due to the demand from the three CSG LNG projects located in Queensland.　In February 2008, QGC and BG Group announced a proposal to develop an LNG plant on Curtis Island

u s i n g QGC’s CSG f i e l d s i n t h e Undu l l a No s e development area in the Surat Basin. In October 2008, BG Group launched a takeover bid for QGC, and in March 2009 BG Group finalised the takeover of QGC and its CSG acreage in the Surat Basin. In 2009-10 BG Group announced the signing of agreements with China National Offshore Oil Corporation（CNOOC）and Tokyo Gas for LNG supply and equity in the QCLNG project. In October 2010 BG Group’s 8.5 million tonne per annum（mtpa）QCLNG project was the first of the CSG to LNG projects to make a final investment decision＊34.　In July 2007 , Santos announced a proposal to construct an LNG facility on Curtis Island, which would use CSG from several Santos-operated fields including Fairview, Roma, Scotia and Arcadia in the Surat and Bowen basins. In May 2008, Santos announced it had selected Petronas to be its partner in the development

CSG LNG Project Participants＊Operator Capacity Gas Supply

Required Status

Queensland Curtis LNGBG Group 73.75％＊CNOOC 25％Tokyo Gas 1.25％

8.5mtpa（2 trains）

1,320 mmcfd （2 trains） FID October 2010, start-up 2014.US$20.4 billion

Gladstone LNG（GLNG）

Santos＊ 30％Petronas 27.5％TOTAL 27.5％KOGAS 15％

7.8mtpa（2 trains）

1,179 mmcfd （2 trains） FID January 2011, start-up 2015.US$18.5 billion

Australia Pacific LNGOrigin Energy 37.5％ ConocoPhillips 37.5％ Sinopec 25％

9mtpa（2 trains）

1,641 mmcfd（2 trains） FID July 2011, start-up 2015. $24.7 billion

Total 25.3mtpa（6 trains）

4,390 mmcfd （6 trains）

QCLNG and GLNG exporting LNG cargoes. APLNG start-up in 2015.

Australia’s Producing & Approved CSG LNG ProjectsTable4

Source： Company Websites/Announcements

1,200

1,000

800

600

400

200

0

1997

-1998

1998

-1999

1999

-2000

2000

-2001

2001

-2002

2002

-2003

2003

-2004

2004

-2005

2005

-2006

2006

-2007

2007

-2008

2008

-2009

2009

-2010

2010

-2011

2011

-2012

2012

-2013

2013

-2014

2014

-2015

mmcfd

y

QLD

NSW

Australia’s CSG Production by StateFig7

Note： million cubic feet per day（mmcfd）. NSW CSG Production 2001-05 unavailable.

Source： Queensland Government, EnergyQues


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of the company’s 7.8 mtpa GLNG project. In 2010 TOTAL and Korea Gas Corporation（KOGAS）also bought stakes in the GLNG project. Following the completion of LNG supply agreements with Petronas, TOTAL and KOGAS the project was approved in January 2011＊35.　In September 2008, Origin Energy announced that it had selected ConocoPhillips to invest in the joint development of a CSG to LNG project using Origin E n e r g y’s C S G r e s e r v e s i n Q u e e n s l a n d a n d ConocoPhillips LNG technology. The key APLNG CSG fields located in the Surat and Bowen basins include Spring Gully, Talinga and Combabula.In 2011, Origin Energy and ConocoPhillips signed agreements with China PetroChemical Corporation（Sinopec）for LNG supply and equity in the 9 mtpa APLNG project. A final investment decision was made in July 2011 for the first train and common facilities for the APLNG project followed by approval of the second train in July 2012＊36.　Towards the end o f 2014 the QCLNG pro ject commenced production and in January 2015 shipped the world’s first LNG cargo supplied by unconventional onshore CSG resources. There will be a total of six LNG trains supplied by CSG when GLNG and APLNG bring their LNG trains online through 2015-16.Australia’s gas production is expected to more than double from 2.4 tcf

（67.1 Bcm）in 2014-15 to 5.4 tcf（145.6 Bcm）by 2019-20＊37. C SG p r odu c t i o n i s a l s o expected to increase from about 15 ％ of Australia’s total gas production in 2014-15 to over 27％ by 2019-20

（Figure 8）＊38.

（4） Potential Shale and

Tight Gas Resources

　So far, only Australia’s u n c o n v e n t i o n a l C S G resources are producing substantial quantities of gas, while production from other unconventional resources is

limited.The release of the EIA shale gas reports in 2011 ＊ 39 and 2013 ＊ 40 highlighted the potential of Aus t r a l i a’s s h a l e g a s r e s ou r c e s a nd s eve r a l international companies invested in unconventional resources from 2010 to 2014（Figure 9）.　The majority of shale and tight gas wells have been drilled in the Cooper Basin, but exploration has also been conducted in several other basins. Mostly vertical wells have been drilled with fewer horizontal wells. This section provides a brief summary of some of the key basins, although it should be noted that there are other basins actively being explored.

120

100

80

60

40

20

02011-2012 2013-2014 2015-2016 2017-2018 2019-2020

Bcm

FY

Conventional

CSG

Outlook for Australia’s Conventional Gas & CSG ProductionFig8

Note： 1 billion cubic metres（Bcm）= 0.035 trillion cubic feet（tcf） Source： Office of the Chief Economist, Resources and Energy

Quarterly March 2015

GeorginaGeorgina

BeetalooBeetaloo

CooperCooper

AmadeusAmadeus

Perth

CanningCanning

Ongoing investment in unconventional resourcesWithdrawal from investment in unconventional resourcesOngoing investment in unconventional resourcesWithdrawal from investment in unconventional resources

Feb 2013Chevron/Beach Energy$349m

Feb 2013Chevron/Beach Energy$349m

Jul 2011BG Group/Drillsearch$130m

Jul 2011BG Group/Drillsearch$130m

Oct 2012Santos/Central Petroleum$150m

Oct 2012Santos/Central Petroleum$150m Nov 2012

Total/Central Petroleum$190m

Nov 2012Total/Central Petroleum$190m

Feb 2014Origin/Senex$252m

Feb 2014Origin/Senex$252m

May 2014Origin & Sasol/Falcon$200m

May 2014Origin & Sasol/Falcon$200mJun 2010

Mitsubishi/Buru$152.4m

Jun 2010Mitsubishi/Buru$152.4m

Nov 2013Apache(Quadrant)/Mitsubishi & Buru$32.2m

Nov 2013Apache(Quadrant)/Mitsubishi & Buru$32.2m

Sep 2010Bharat/Norwest$15m

Sep 2010Bharat/Norwest$15m

Mar 2014 Chevron withdrawsMar 2014 Chevron withdraws

Feb 2011Hess/FalconUS $160m

Feb 2011Hess/FalconUS $160mJun 2013 Hess withdrawsJun 2013 Hess withdraws

Sep 2011ConocoPhillips/New StandardUS $109.5m

Sep 2011ConocoPhillips/New StandardUS $109.5mOct 2014 Conoco Phillips withdrawsOct 2014 Conoco Phillips withdraws

Feb 2013PetroChina/ConocoPhillipsUndisclosed

Feb 2013PetroChina/ConocoPhillipsUndisclosedOct 2014 PetroChina withdrawsOct 2014 PetroChina withdraws

Jun 2012Statoil/PetrofrontierUS $210m

Jun 2012Statoil/PetrofrontierUS $210mNov 2014 Statoil withdraws from two permitsNov 2014 Statoil withdraws from two permits

Key Investment in Unconventional Resources 2010-2014Fig9

Note： Unconventional covers shale oil and gas, tight gas and oil as well as deep coals, but CSG is not included.Source： Company Websites/Announcements

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　The Cooper Basin in central Australia has the advantage of established conventional oil and gas infrastructure and access to the east coast domestic markets. The Encounter-1 and Holdfast-1 vertical wells targeting shale gas were drilled in the basin by Beach Energy in 2010 and 2011 respectively. In 2013 Beach Energy’s first horizontal well Holdfast-2, drilled with joint venture partner Chevron was fracture stimulated and flowed gas at 0.25 mmcfd＊41. The results from the joint venture’s f irst few wells did not convince Chevron to progress to the next exploration stage and Chevron withdrew in March 2015.　In October 2012, Australia’s first commercial shale gas well commenced production in the Cooper Basin. The Santos-operated Moomba-191 vertical well flowed gas at commercial rates of 3.0 mmcfd and was only 350 metres from existing pipeline infrastructure. Santos’s follow-up Moomba-194 vertical well was fracture stimulated and flowed gas at peak rates of 3.5 mmcfd. Santos’s f irst horizontal shale gas wel l Roswell-2 was also fracture stimulated and flowed gas at a stable rate of 0.8 mmcfd＊ 42. Moomba-194 and Roswell-2 were connected to Santos’s nearby Cooper Basin infrastructure in 2014.　In the 2015 financial year BG Group and Drillsearch Energy’s Cooper Basin Shale and Tight Gas Joint Venture drilled four vertical exploration wells. Two wells, Charal-1 and Anakin-1 were hydraulically fractured and tested. Charal-1 flowed gas at a peak rate of 0.95 mmcfd, while Anakin-1 recorded a peak rate of 1.05 mmcfd＊43.　The onshore portion of the Canning Basin in Western Australia has the largest technically recoverable shale gas and shale oil resources in the country, according to the EIA＊ 44. Even though the basin is located in a remote area and lacks infrastructure it has attracted investment from international companies such as Mitsubishi, ConocoPhillips, PetroChina and Apache Energy（interests now held by Quadrant Energy）. Since 2010 the Buru Energy and Mitsubishi Joint Venture has been exploring for unconventional resources in the Canning Basin and is targeting the potentially large tight wet gas resources in the Laurel Formation＊45. The joint venture discovered gas in the Laurel Formation at their Valhalla prospect in 2011

and conducted appraisal drilling at the Yulleroo gasfield in 2012 and 2013 . Work cont inues on the j o in t v en tu r e’s Lau r e l Fo rma t i o n T i gh t Ga s P i l o t Exploration Program, which commenced in 2014.　The onshore portion of the Perth Basin in Western Australia is close to existing pipeline infrastructure and there is potential for domestic gas supply within the state. In 2010 AWE’s Woodada Deep-1 vertical well was drilled to test shale gas targets. AWE was also involved in a joint venture with Norwest Energy and Bharat Resources that fractured stimulated the Arrowsmith-2 shale gas well and produced promising gas flows as well as oil in 2013＊46.　The New Standard Energy, ConocoPhillips and PetroChina Joint Venture drilled two wells into the Goldwyer Shale in the Canning Basin. However, the results did not induce ConocoPhillips and PetroChina to continue and they withdrew from the joint venture in October 2014.　The Georgina Basin, which is largely unexplored, is spread over parts of the Northern Territory and Queensland. The ongoing Central Petroleum and TOTAL Jo i n t Ven ture i n t he Georg ina Bas i n commenced the first phase of a four year exploration program in the second half of 2013 and drilled two wells targeting the shale and tight gas reservoirs in the Lower Arthur Creek Formation in 2014＊47.　Statoil is part of a drilling campaign testing the unconventional oil potential of the Lower Arthur Creek and Thorntonia formations in the Georgina Basin with joint venture partner Petrofrontier. Statoil decided to exit two permits in November 2014 after reportedly disappointing drilling results, but continues to hold interests in two nearby permits＊48.　In February 2015 INPEX made its first investment in Austral ian shale explorat ion by winning the Northern Territory Government’s first competitive tender for exploration acreage. INPEX Director Australian Ventures, Tony Pytte, said the onshore acreage was located in the highly prospective Beetaloo Basin, about 500 kilometres southeast of Darwin＊49.　In September 2015, the Falcon Oil & Gas, Origin Energy and Sasol Joint Venture announced the completion of the Kalala S-1 vertical exploration well, which is the first well in the 2015 three well drilling


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campaign targeting shale resources in the Beetaloo Basin＊50.　In the Amadeus Basin the Central Petroleum and Santos Joint Venture is exploring for unconventional oil and gas resources in the Northern Territory. In 2014 Santos decided to proceed to the second exploration phase of its farm-in agreement with Central Petroleum.　The success of the CSG industry has not been repeated with other unconventional resources such as shale and tight gas. The initial assessment of shale gas resources by the EIA and increased investment from international companies was encouraging. However, some international companies were not persuaded by early exploration results and have withdrawn from unconventional gas exploration programs in Australia. Additionally the low oil price environment has led to company’s reducing exploration expenditure, which has had an impact on unconventional exploration programs. The Cooper Basin has benefited from established oil and gas infrastructure aiding in the start-up of Australia’s first commercial shale gas well in the basin. Whereas other basins in remote areas of Western Australia and the Northern Territory will require substantial capital expenditure to develop infrastructure to deliver the gas to market.

（5）Growth of Gas & Decline of Oil

　In 2014 Australia produced a record 24.7 million tonnes of LNG from three LNG projects（North West Shelf , Darwin LNG and Pluto LNG）supplied by conventional offshore gas fields＊51. However, QCLNG’s

Train 1 shipped the world’s f irst cargo of LNG supplied by unconventional onshore CSG fields in January 2015. This will be followed by the GLNG and APLNG projects expected to start-up in 2015. By 2018 Australia will have 10 operational LNG projects with a total capacity of over 85 million tonnes of LNG and is forecast to become the world’s largest LNG exporter

（Figure 10）. In Western Australia Chevron’s Gorgon and Wheatstone LNG projects are scheduled to start-up in 2016. INPEX’s Ichthys LNG project in the Northern Territory and Shell’s Prelude floating LNG project offshore Western Australia are both expected to start-up in 2017.This unprecedented growth in LNG capacity includes 25.3 million tonnes supplied by onshore CSG fields. The prominence of conventional offshore gas production continues , but onshore production has become increasingly important with the development of unconventional CSG resources to supply eastern Australia’s LNG export projects.　Unlike gas production, Australia’s production of oil has been steadily declining since it peaked in 2000-01. Australia’s production of crude oil and condensate was 687,000 bpd in 2000-01, and has declined to about 356,000 bpd in 2014-15（Figure 11）＊52. Production is expected to increase slightly to 430,000 bpd in 2017-18 due to condensate production associated with the Prelude and Ichthys LNG projects, but is forecast to decline again to 377,000 bpd in 2019-20＊ 53. If there are no new major petroleum liquid discoveries the decline in production is expected to continue.

100

90

80

70

60

50

40

30

20

10

02012 2013 2014 2015 2016 2017 2018

mtpa

y

Prelude

Wheatstone

Ichthys

APLNG(CSG)

GLNG(CSG)

QCLNG(CSG)

Gorgon

Pluto

Darwin LNG

NWS

Australia’s Existing & Approved LNG CapacityFig10

Source： Company Websites/Announcements

800

700

600

500

400

300

200

100

01999-2000 2003-2004 2007-2008 2011-2012 2015-2016 2019-2020

kbd

Crude oilCondensateLPG

FY

Australia’s Crude Oil, Condensate & LPG ProductionFig11

Source： Office of the Chief Economist, Resources and Energy Quarterly March 2015

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（1） Commonwealth, State and Territory

Legislation and Regulation

　In Australia petroleum（any naturally occurring hydrocarbon, whether in a gaseous, liquid or solid state）is the property of the Crown（i.e. Commonwealth, State or Terr i tory governments）. Legis lat ion regulating petroleum exploration and production is divided into Commonwealth offshore（waters beyond the three nautical mile limit to the edge of Australia’s continental shelf and incline）.　State or Territory onshore and State or Territory offshore（adjacent waters from the territorial sea baseline extending seaward three nautical miles）.　T h e m a i n l e g i s l a t i o n t h a t a p p l i e s t o t h e Commonwealth offshore area is the Offshore Petroleum and Greenhouse Gas Storage Act 2006. Each State and Territory also has its own legislation covering the exploration and production of onshore and offshore petroleum resources（Table 5）. In Western Australia the Petroleum（Submerged Lands）Act 1982 applies to the State offshore areas and the Petroleum and Geothermal Energy Resources Act 1967 applies to the State onshore areas.　The regulatory regime for offshore petroleum exploration in Commonwealth waters is jo int ly administered by the Commonwealth , State and

Territory governments through a Joint Authority arrangement. The Joint Authority for each State

（except Tasmania）and the Northern Territory comprises the responsible Commonwealth Minister and the relevant State or Northern Territory Minister＊54.　T h e N a t i o n a l O f f s h o r e P e t r o l e u m T i t l e s Administrator（NOPTA）is responsible for the a dm in i s t r a t i o n o f p e t r o l e um t i t l e s a nd d a t a management in all offshore areas. In Commonwealth waters, NOPTA administers titles, undertakes data and resource management, and provides technical advice to the Joint Authority＊ 55 . However , the State and Territory maintain a titles administrator role in State and Territory waters.　The Nat ional Offshore Petro leum Safety and Environmental Management Authority（NOPSEMA）was established on 1 January 2012, and is Australia's first national regulator for health and safety, well integrity and environmental management for offshore petroleum operations in Commonwealth waters, and in coastal waters where State and Territory powers have been conferred＊56. To date only Victoria has conferred its functions for health and safety, well integrity and environmental management for petroleum activities in coastal waters on NOPSEMA, but other States and Territories are considering the conferral of functions.

3. Petroleum Legislation & Regulation

Onshore and Offshore State/Territory Government Petroleum LegislationTable5

Primary Legislation（Licensing）

State and Territory Onshore within borders Offshore up to 3 nautical miles seaward of the baseline.

New South Wales Petroleum（Onshore）Act 1991（NSW） Petroleum（Submerged Lands）Act 1982

Northern Territory Petroleum Act（NT） Petroleum（Submerged Lands）Act 1981

Queensland Petroleum and Gas（Production and Safety）Act 2004（Qld）Petroleum Act 1923（Qld） Petroleum（Submerged）Lands）Act 1982

South Australia Petroleum and Geothermal Act 2000（SA） Petroleum（Submerged）Lands）Act 1982

Tasmania Mineral Resources Development Act 1995（Tas） Petroleum（Submerged Lands）Act 1982

VictoriaPetroleum Act 1998（Vic）Mineral Resources（Sustainable Development）Act 1990（Vic）

Petroleum（Submerged）Lands Act 1982

Western Australia Petroleum and Geothermal Energy Resources Act 1967（WA） Petroleum（Submerged Lands）Act 1982

Source： State and Territory Government Websites/Announcements


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（2） Strong State and Territory Onshore

Petroleum Exploration & Production

Activity

　Onshore petroleum exploration and production is well established in Queensland, Western Australia, South Australia and the Northern Territory with supportive governments and relatively stable policies. Under the relevant State or Territory legislation both conventional and unconventional petroleum exploration has been conducted for decades.　In Queensland onshore petroleum exploration including CSG is carried out under the Petroleum and Gas（Product ion and Safety）Act 2004 and the Petroleum Act 1923. In 2010 the Queensland Land Access Framework was introduced to provide the statutory and policy framework for accessing private land to undertake resource activities and compensating for associated impacts＊57. The GasFields Commission Queens land was a lso estab l i shed in 2013 as an independent statutory body to manage the coexistence of landholders, regional communities and the onshore gas industry in Queensland. The regulatory regime in the state has facilitated the establishment of a thriving CSG industry while providing protection for the environment, water resources, landholders and communities. Queensland will also benefit from more than $63 billion in direct investment in LNG, almost 30,000 construction jobs, and then up to 17,000 jobs during full production of the three LNG projects＊58. 　In South Australia onshore petroleum exploration and development is regulated under the Petroleum and Geothermal Energy Act 2000. South Australia was the f irst Austral ian state to f inal ise an approach to developing its unconventional gas resources. The Roadmap for Unconventional Gas Projects in South Australia was released in December 2012 and covers the life-cycle of shale and tight gas projects including logistics, supply chains and infrastructure＊ 59. The Roadmap emphasised that community confidence in the ability of the regulators and industry was essential to ensuring continued gas development.　In Western Australia the Petroleum and Geothermal Energy Resources Act 1967 covers all onshore areas for petroleum exploration and development. Onshore exploration has continued during the implementation of

various regulatory reforms that will oversee the development of the state’s shale and tight gas industry. The new resource management and administration regulations came into effect in July 2015. The new assessment guidelines for hydraulic fracturing were also released by the Environmental Protect ion Authority in December 2014. These changes have been implemented to provide the community with confidence that shale and tight gas projects can be developed safely.　In the Northern Territory the Petroleum Act is the main legislation associated with onshore petroleum exploration and production activities.The Report of the Independent Inquiry into Hydraulic Fracturing in the Northern Territory was released in November 2014 and concluded that the environmental risks associated with hydraulic fracturing can be managed effectively with a robust regulatory regime＊ 60 . In Western Australia and South Australia the inquiries into hydraulic fracturing are ongoing.　Historically petroleum exploration and production has been in remote areas away from densely populated areas such as onshore in central Australia or offshore Western Australia and Victoria. However, CSG resources are located in areas where a large portion of the land is used for agricultural purposes. The rapid growth in Australia’s unconventional gas industry has led to increased public interest in the impacts of exploration on water resources essential to the agricultural industry. CSG extraction involves the production of associated water, which has a high saline content and requires treatment before it can be reinjected or reused for activities such as irrigation and livestock watering. Communities are concerned about the potential contamination of groundwater and surface water from CSG associated water. A major challenge for the CSG industry has been the treatment and reuse of the CSG associated water. Currently CSG is only produced in the states of Queensland and New South Wales where the governments have in place strict conditions around the treatment and reuse of CSG associated water.　Furthermore, hydraulic fracturing, a technique used to extract some unconventional onshore resources has attracted a large amount of community scrutiny, especially in relation to potential risks to human health

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and the environment from the chemicals used. The use of hydraulic fracturing is essential for shale and tight gas operations, but only sometimes required for CSG operations. Hydraulic fracturing, also commonly referred to as fraccing, is a method used to increase the rate and total amount of oil and gas extracted from reservoirs. Fluid, which typically comprises of more than 99 ％ water and sand plus a small amount of chemicals, is pumped down a well at high pressure to produce tiny cracks in the target rock reservoirs to stimulate the flow of oil and gas＊61. State and Territory governments have in place legislation and /or policy that require the disclosure of the chemicals used in hydraulic fracturing.　Since the 1960s around 1 , 500 we l l s i n South Australia, Western Australia, Queensland, New South Wales , and the Northern Terr i tory have been hydraulically fractured with no adverse impacts on water aquifers（geological formations containing groundwater）＊62.

（3） Stalled State and Territory Onshore

Petroleum Exploration & Production

Activity

　In the states of New South Wales（NSW）, Victoria and to a lesser extent Tasmania regulatory changes have impacted the development of onshore resources, in particular unconventional resources such as CSG, shale and tight gas.　In NSW the Petroleum（Onshore）Act 1991 covers onshore exploration and production of petroleum.Since early 2011 CSG exploration and development activities have been a f f ec ted by severa l po l i cy changes introduced by the NSW Government. The government implemented a moratorium on hydraulic fracturing as well as an independent review on CSG activities, and most recently released a new NSW Gas Plan, all of which has been in response to community concerns regarding the impact of CSG exploration on water supp l i e s（Tab le 6）.The F ina l Repo r t o f t h e Independent Review of Coal Seam Gas Activities in NSW was released in September 2014 and found that the technical challenges and risks posed by the CSG industry could in general be managed subject to appropriate safeguards＊63.　In NSW there is no conventional onshore petroleum production, but the state did produce 4.7 bcf（5 PJ）of unconventional CSG in 2014＊ 64. The majority of gas

NSW Government Action/PolicyTable6

Date NSW Government Action/Policy Remarks

April 2011 Moratorium on hydraulic fracturing. Moratorium lifted in September 2012.

May 2011 60 day moratorium on new exploration licences for coal, CSG and petroleum.

Allowed for the development of new provisions including the ban of BTEX※1 chemicals in hydraulic fracturing.

September 2012 Final Strategic Regional Land Use Policy.The policy introduced an approval process to assess the impacts of proposed CSG activities on areas deemed strategic agricultural land.

February 2013 2km exclusion zone around current and future residential growth areas.

Exclusion zone to prohibit new CSG exploration and production activities on land, as well as certain viticulture and equine industry areas.

January 2014 2km exclusion zone extended to include additional areas.

Extended to include rural villages, residential zones and future growth areas.

March 2014 6 month freeze on new petroleum exploration licence applications. Extended to September 2015

September 2014 Final Report of the Independent Review of Coal Seam Gas Activities in NSW.

Concluded technical challenges and risks posed by CSG can be managed.

November 2014 NSW Gas Plan released. 16 petroleum exploration licences cancelled and government buyback scheme implemented.

July 2015 Environment Protection Authority began its new role as lead regulator for gas exploration and production.

Appointment of Environment Protection Authority as lead regulator part of the NSW Gas Plan.

※ 1. BTEX chemical compounds（benezene, toluene, ethylbenzene and xylene）Source： NSW Government Department of Resources and Energy Website/Announcements, Final Report of the Independent Review of Coal Seam

Gas Activities in NSW.


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production comes from AGL Energy’s Camden Gas Project, which has been producing CSG for the NSW domestic market since 2001. Santos’s Narrabri pilot project also delivers gas to the Wilga Park power station. NSW imports about 95 ％ of its gas supply from other states. NSW has two major potential CSG projects that could supply the state’s domestic market, but in March 2011 the government effectively put a ho ld on the indus try wh i l e i t e s tab l i shed new regulations, which included a Strategic Land Use Policy

（Table 6）and delayed the development of these projects. Originally Santos’s Narrabri CSG Project was targeting a start-up date in 2015, but the project is unlikely to be developed before the end of the decade. Santos said the project could supply up to 50％ of the state’s gas supply＊65. AGL Energy’s Gloucester CSG Project was scheduled to commence in 2016, but is now targeting 2018. AGL Energy says it could supply around 15 ％ of the state’s gas demand＊ 66. In July 2015 AGL Energy also announced that its Camden North Expansion project, which has been on hold since February 2013, would not go ahead.　In Victoria, the Petroleum Act 1998 regulates petroleum（including shale and tight gas）exploration and development activities in onshore and coastal waters . However , CSG l i cens ing and approva l requirements are regulated under the state’s mining legislation, the Minerals Resources（Sustainable Development）Act 1990.　Since 1969 Victoria has had a stable supply of oil and gas from the offshore petroleum fields discovered in the Bass Strait, which continue to be an important supply of energy not only for the state, but the country. Oil and gas piped from offshore fields is processed onshore and there are also gas storage facilities onshore. In complete contrast to the state’s thriving offshore petroleum industry, the Victorian Government has in place a

moratorium for new onshore petroleum, CSG, shale and tight gas exploration licences, hydraulic fracturing and drilling activity pending a Victorian Parliamentary Inquiry into the exploration, extraction, production and rehabilitation for onshore unconventional gas＊67. The moratorium is expected to remain in place until at least the end o f 2015 . The morator ium on hydrau l ic fracturing, which has been in place since August 2012 has remained despite the recommendations of a report by the Victorian Gas Market Taskforce released in November 2013 to lift the hold on hydraulic fracturing and support development of onshore gas to avoid rising gas prices＊68.　In Tasmania offshore petroleum exploration and production is well established, but the state’s onshore petroleum resources are mostly unexplored. The Minerals Resources Development Act 1995 regulates onshore petroleum, CSG and oil shale activities.　In 2014 the state government imposed a 12 month moratorium on hydraulic fracturing in Tasmania to enable a review into hydraulic fracturing in the state. So far there has been no hydraulic fracturing activity undertaken in Tasmania. Following the review the government released a policy statement detailing its intent to maintain a moratorium on the use of hydraulic fracturing for the purposes of hydrocarbon resource extraction, e.g. shale gas and petroleum, for five years, until March 2020＊69.　Even though the development of onshore resources in the states of Victoria and Tasmania has stalled, there has been progress in NSW. Production testing at AGL Energy’s Gloucester CSG Project is underway and the company is targeting a final investment decision in 2016.Furthermore, the appraisal pilot wells associated with Santos’s Narrabri CSG Project are online and delivering gas to the Wilga Park power station.

4. Petroleum Resources Taxation

（1）Taxation Overview

　In Australia oil and gas companies are subject to specific petroleum resources taxation including the Petroleum Resource Rent Tax（PRRT）, royalties and

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excise. In Federal jurisdictional areas fields are subject to the PRRT or Resource Rent Royalty（RRR）. For more details on RRR refer to item （5） on page 51. In State and Territory jurisdictional areas fields are subject to royalty and PRRT. The amount of taxation paid by Australia’s oil and gas sector is expected to rise from $8.8 billion in 2012 to almost $13 billion in 2020＊70.

（2）Petroleum Resource Rent Tax（PRRT）

　Since 1 July 2012, the Petroleum Resource Rent Tax（PRRT）has applied to all Australian onshore and offshore oil and gas projects, including the North West Shelf and CSG projects. The PRRT is a profit based tax levied at 40 ％ of net revenues（sales receipts less eligible expenditures）from a project＊71. It is important to note that royalties paid to the State and Territory governments are a deductible expense for PRRT calculation purposes.　The PRRT was or ig ina l ly in troduced by the Australian Government in 1987 to replace royalties and crude oil excise in most areas of Commonwealth waters. At the time of its introduction in 1987, the PRRT applied to petroleum projects in all offshore

areas except the Bass Strait and the Northwest Shelf. In 1990, the PRRT was extended to petroleum projects in the Bass Strait and, from 2012, to petroleum projects in all onshore and offshore areas except the Joint Petroleum Development Area in the Timor Sea.　The extension of the PRRT to all Australian onshore and offshore oil and gas projects adds an extra layer of compliance costs on companies, while uncertainties with the var ious roya l t ies reg imes i s creat ing unnecessary administrative burdens on companies, according to the Australia Petroleum, Production and Exploration Association（APPEA）＊72.

（3）Royalties

　Royalties are payable to the State and Territory governments for production from onshore and coastal water areas and to the Commonwealth（Federal）Government for offshore production.　The North West Shelf is currently the only offshore area in Commonwealth waters which is subject to royalty. The royalty rate for the North West Shelf is set at between 10-12.5 ％ of the wellhead value depending on the size of the area covered by the production licence＊73.

State and Territory Government Royalty RatesTable8

State and Territory Royalty Wellhead Deductions

New South Wales 10％ of wellhead value Excise, downstream operating and capital costs.

Northern Territory 10％ of wellhead value Excise, downstream operating and capital costs.

Queensland 10％ of wellhead value Excise, downstream operating and capital costs.

South Australia 10-12.5％ of wellhead value Excise, downstream operating and capital costs.

Tasmania No royalty N/A

Victoria 10％ of wellhead value None

Western Australia 10％ of wellhead value Downstream operating and capital costs.Source： State and Territory Government Websites

PRRT and Royalty RatesTable7

Tax Rate Payable to Area

PRRT 40％ tax on profits Commonwealth All onshore and offshore petroleum projects.

Royalty（State/Territory） 10-12.5％ of wellhead value State and Territory Onshore and coastal

waters.

Royalty（Commonwealth） 10-12.5％ of wellhead value Shared between Commonwealth

and State/Territory Offshore waters.

Source： Department of Industry, Innovation and Science


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　Onshore , r oya l t i e s a re l ev i ed on pe t ro l eum production and are collected by the State and Territory governments. The rate is between 10-12.5 ％ of net wellhead value of production（Table 7）. State and Territory governments receive 100％ of royalties from onshore and coastal water areas and share royalties from offshore fields with the Federal Government.

（4）Crude Oil Excise

　The Commonwealth Government applies Crude Oil Excise to eligible crude oil and condensate production from state coastal waters, onshore areas, and the North West Shelf Project area in Australian waters. The excise rate ranges from 20％ to 55％ of the volume weighted average of the realised free-on-board price of crude oil sales, depending on the annual rate of production of crude oil and condensate, the date of discovery of the

pe t ro l eum reservo i r and the da te produc t i on commenced. The first 30 million barrels of crude oil and condensate from a field are excise exempt＊74.

（5）Resource Rent Royalty

　In 1985 the Commonwealth Government announced the introduction of new legislation to apply to onshore oil production. Under the Petroleum Revenue Act 1985, a new profits based, Resource Rent Royalty

（RRR）similar to the PRRT, could replace excise and royalties on onshore projects. The legislation is implemented when both Commonwealth and State or Territory governments agree on an RRR regime. Currently, the RRR only applies to production from Western Australia’s Barrow Island. For Barrow Island, RRR is shared between the Australian Government

（75％）and Western Australia（25％）＊75.

　Australia’s production of petroleum liquids has been steadily declining since it peaked in 2000-01, but gas production is expected to more than double by the end of decade primarily due to the huge expansion in LNG capacity. A large portion of the gas production will continue to come from offshore fields, but the rapid expansion of onshore unconventional CSG production to supply Queensland’s LNG export projects means onshore fields share of gas production is growing. Despite the major i ty of Austra l ia’s oi l and gas production continuing to be sourced from offshore fields, the development of onshore gas resources has become increasingly important.　The potential of other unconventional gas resources such as shale and tight gas is enormous, but still uncertain with only limited production in the Cooper Basin. It is unclear how long it will take these shale and t ight gas resources to produce substant ia l

quantities of gas particularly in the remote areas of Australia that lack infrastructure.　The petroleum legislation, regulation and taxation regimes in place in Queensland, Western Australia, the Northern Territory and South Australia have not interfered with the ongoing exploration and production of onshore resources. Whereas regulatory changes in the states of NSW, Victoria and Tasmania have delayed or completely halted the development of onshore resources, especially unconventional resources such as CSG, shale and tight gas.　The emergence of CSG, shale and tight gas resources has brought onshore exploration and production to the forefront again in Australia. However, the development of some onshore resources may take longer than others depending on the location and which regulatory f r amework i t s p r op onen t s mus t n av i g a t e t o commercialise the resources.

Conclusion

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<注・解説>＊1： Geoscience Australia and the Bureau of Resources and Energy Economics, 2014, Australian Energy Resource

Assessment http：//www.ga.gov.au/corporate_data/79675/79675_AERA.pdf＊2： Ibid＊3： Ibid＊4： Ibid＊5： Ibid＊6： Ibid＊7： US Energy Information Administration（EIA）, 13 June 2013, Technically Recoverable Shale Oil and Shale Gas

Resources： An Assessment of 137 Shale Formations in 41 Countries Outside the United States http：//www.eia.gov/analysis/studies/worldshalegas/pdf/fullreport.pdf

＊8： Geoscience Australia and the Bureau of Resources and Energy Economics, 2014, Australian Energy Resource Assessment http：//www.ga.gov.au/corporate_data/79675/79675_AERA.pdf

＊9： Ibid＊10： Ibid＊11： US Energy Information Administration（EIA）, 13 June 2013, Technically Recoverable Shale Oil and Shale Gas


＊12： Santos, 2015, History http：//www.santos.com/company-profile/history.aspx＊13： Ibid＊14： Wood Mackenzie, August 2015, Cooper Basin Available through Wood Mackenzie www.woodmac.com ＊15： Ibid＊16： Santos, 2015, Cooper Basin（Overview）http：//www.santos.com/our-activities/eastern-australia/cooper-basin-

overview-.aspx＊17： Wood Mackenzie, August 2015, Cooper Basin Available through Wood Mackenzie www.woodmac.com＊18： Ibid＊19： Owad-Jones, D, and Ellis, G 2000, Western Australia Atlas of Petroleum Fields, Onshore Perth Basin, Petroleum

Division, Department of Minerals and Energy Western Australia, Volume 1＊20： Ibid＊21： Australian Petroleum, Production and Exploration Association（APPEA）, Industry Statistics, Annual Production

Statistics 2014 http：//www.appea.com.au/industry-in-depth/industry-statistics/＊22： Ibid＊23： AWE, 2015, Website/Announcements http：//www.awexplore.com/irm/content/investor_asx.html＊24： Wood Mackenzie, August 2015, Mereenie Available through Wood Mackenzie www.woodmac.com＊25： Ibid＊26： Ibid＊27： Ibid＊28： ExxonMobil, 2015, About Us, Bass Strait http：//www.exxonmobil.com.au/Australia-English/PA/about_what_

gipps_bs.aspx＊29： EnergyQuest, March 2015, EnergyQuarterly Available through EnergyQuest www.energyquest.com.au＊30： Ibid＊31： Ibid＊32： EnergyQuest, August 2015, EnergyQuarterly Available through EnergyQuest www.energyquest.com.au＊33： Queensland Government, Business and industry portal, 2015 https：//www.business.qld.gov.au/invest/investing-

queenslands-industries/investing-in-queenslands-csg-lng-industry/investing-csg-lng-supply-chain


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＊34： QGC Website/Announcements http：//www.qgc.com.au＊35： Santos GLNG Website/Announcements http：//www.santosglng.com＊36： Australia Pacific LNG Website/Announcements http：//www.aplng.com.au＊37： Australian Government Department of Industry, Innovation and Science, Office of the Chief Economist, Resources

and Energy Quarterly Report March 2015, http：//www.industry.gov.au/Office-of-the-Chief-Economist/Publications/Pages/Resources-and-energy-quarterly.aspx#

＊38： Ibid＊39： US Energy Information Administration（EIA）, 11 April 2011, World Shale Gas Resources： An Initial

Assessment of 14 Regions Outside the United States http：//www.eia.gov/analysis/studies/worldshalegas/archive/2011/pdf/fullreport.pdf

＊40： US Energy Information Administration（EIA）, 13 June 2013, Technically Recoverable Shale Oil and Shale Gas Resources： An Assessment of 137 Shale Formations in 41 Countries Outside the United States http：//www.eia.gov/analysis/studies/worldshalegas/pdf/fullreport.pdf

＊41： Beach Energy Website/Announcements www.beachenergy.com.au＊42： Santos, Macquarie Australia Conference, May 2015 http：//www.santos.com/library/070515_Macquarie％

20Australia_Conference_Presentation.pdf＊43： Drillsearch Energy Website/Announcements http：//drillsearch.com.au＊44： US Energy Information Administration（EIA）, 13 June 2013, Technically Recoverable Shale Oil and Shale Gas


＊45： Buru Energy Website/Announcements www.buruenergy.com＊46： AWE Website/Announcements www.aweplore.com＊47： Central Petroleum Website/Announcements www.centralpetroleum.com.au＊48： Petrofrontier Website/Announcements www.petrofrontier.com＊49： INPEX given green light for Northern Territory onshore exploration acreage, INPEX Announcement, 13

February 2015 http：//www.inpex.com.au/news-media/news/inpex-given-green-light-for-northern-territory-onshore-exploration-acreage/

＊50： Falcon Oil & Gas Australia Website/Announcements www.falconaustralia.com.au＊51： EnergyQuest, March 2015, EnergyQuarterly Available through www.energyquest.com.au＊52： Australian Government Department of Industry, Innovation and Science, Office of the Chief Economist, Resources

and Energy Quarterly Report March 2015 http：//www.industry.gov.au/Office-of-the-Chief-Economist/Publications/Pages/Resources-and-energy-quarterly.aspx#

＊53： Ibid＊54： Australia Government Department of Industry, Innovation and Science, Offshore Petroleum Regime – Offshore,

2015 http：//www.petroleum-acreage.gov.au/node/443/document＊55： Ibid＊56： Ibid＊57： Gasfields Commission Queensland Website http：//www.gasfieldscommissionqld.org.au/gasfields＊58： Australian Government Department of Industry and Bureau of Resources and Energy Economics, Eastern

Australian Domestic Gas Market Study 2014 http：//www.industry.gov.au/Energy/EnergyMarkets/GasMarketDevelopment/Pages/EasternAustralianDomesticGasMarketStudy.aspx

＊59： South Australian Government Department of State Development, Roadmap for Unconventional Gas Projects in South Australia, 12 December 2012 http：//www.petroleum.statedevelopment.sa.gov.au/__data/assets/pdf_file/0008/179621/Roadmap_Unconventional_Gas_Projects_SA_12-12-12_web.pdf

＊60： APPEA, 2015, Hydraulic Fracturing（fraccing） http：//www.appea.com.au/oil-gas-explained/operation/hydraulic-

542015.11 Vol.49 No.6

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アナリシス

fracturing-fraccing/＊61： APPEA Submission to the ‘Review of Hydraulic Fracturing in Tasmania’, December 2014 http：//www.

appea.com.au/wp-content/uploads/2014/12/APPEA-Submission-to-the-Review-of-Hydraulic-Fracturing-in-Tasmania.pdf

＊62： Report of the Independent Inquiry into Hydraulic Fracturing in the Northern Territory, November 2014 http：//www.hydraulicfracturinginquiry.nt.gov.au/docs/report-inquiry-into-hydraulic-fracturing-nt.pdf

＊63： NSW Government, Final Report of the Independent Review of Coal Seam Gas Activities in NSW, September 2014 http：//www.chiefscientist.nsw.gov.au/__data/assets/pdf_file/0005/56912/140930-CSG-Final-Report.pdf

＊64： EnergyQuest, March 2015, EnergyQuarterly Available through www.energyquest.com.au＊65： Santos, About Narrabri Gas Project, Narrabri Gas Project Overview factsheet https：//narrabrigasproject.com.

au/about/narrabri-gas-project/＊66： AGL Energy, About Coal Seam Gas, http：//www.agl.com.au/about-agl/how-we-source-energy/natural-gas/

about-coal-seam-gas＊67： Victorian Government, Onshore Gas Community Information http：//onshoregas.vic.gov.au/regulation/current-

status-and-allowable-activities＊68： Victorian Government, Gas Market Taskforce： Final Report and Recommendations, November 2013 http：//

www.energyandresources.vic.gov.au/about-us/publications/Gas-Market-Taskforce-report＊69： Tasmanian Government, Government Policy on Hydraulic Fracturing（Fracking）in Tasmania http：//dpipwe.tas.

gov.au/about-the-department/government-policy-on-hydraulic-fracturing-（fracking）-in-tasmania＊70： APPEA, Submission To The Tax White Paper Taskforce, June 2015 http：//www.appea.com.au/wp-content/

uploads/2015/06/APPEA-Tax-White-Paper-Submission-1-June-2015.pdf＊71： Department of Industry, Innovation and Science, Resources Taxation http：//www.industry.gov.au/resource/

Enhancing/ResourcesTaxation/Pages/default.aspx＊72： APPEA, Submission To The Tax White Paper Taskforce, June 2015 http：//www.appea.com.au/wp-content/

uploads/2015/06/APPEA-Tax-White-Paper-Submission-1-June-2015.pdf＊73： Department of Industry, Innovation and Science, Resources Taxation http：//www.industry.gov.au/resource/

Enhancing/ResourcesTaxation/Pages/default.aspx＊74： Ibid＊75： Department of Industry, Innovation and Science, Resources Taxation http：//www.industry.gov.au/resource/

Enhancing/ResourcesTaxation/Pages/default.aspx

執筆者紹介

Lainie Kelly （レイニー・ケリー）オーストラリア・シドニー生まれ。University of Sydney, Bachelor of Arts（シドニー大学、文学部）卒業。JETROシドニーの調査員を経て、2005年7月よりJOGMECシドニー事務所調査員（石油・天然ガス部門）となり、現在に至る。古代史に関心を寄せ、趣味の水泳とスキューバダイビングに励んでいる。

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