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Editor: Paul Sullivan Pex Publications Pty Ltd. 5/1 Almondbury Road, Mt Lawley WA 6050

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IN THIS ISSUE

Rig Schedule

Seismic Schedule

Commentary

News In Brief

Other Announcements

Drilling Updates

Well Tickets

oil & gas insider

Wednesday, 4 April 2012

P U B L I C AT I O N S

Current Drilling Activity

1 P’Nyang South-1 8 Haslam-1

2 Tallaganda-1 9 Sasanof-1

3 Triceratops-2 10 Norton-A

4 Ketu-2 11 Glencoe-2

5 Growler-10 12 Moonta-1

6 Marsden-1 13 Evandra-2

7 Boreas-1

IN THIS ISSUE

AJ Lucas executives

anxiously looking out windows

Mar 29: AJ Lucas can’t take a trick lately. This week it announced that another wet s u m m e r i n m u c h o f Queensland had put a dent in its revenue forecasts for the year ending June 30, down from $37mil to $32mil...

Aussie juniors put spotlight on East Africa

Mar 29 & Apr 2: East Africa is attracting increasing world-wide attention as a potential new oil & gas hot spot, with two Aussie explorers keen to be involved. One of them, FAR Ltd, was one of the early movers in the region, while Jacka Resources has more recently been building its presence there....

Green Rock takes bigger bite of Canning Basin

April 2: Green Rock Energy builds on its Canning Basin acreage by farming into Oil Basins’ Backreef project in a deal potentially worth up to $3.6mil... A trouble free re-start for

Galoc with new & improved FPSO

Apr 2: There would be high fives all round in the Philippines this week as the newly upgraded Galoc field resumes production on schedule in SC14C with the newly upgraded FPSO, following a period of time where the field has been shut in while the Rubicon Intrepid h a s b e e n u n d e r g o i n g refurbishment...

News In Brief Octanex Central

Other Announcements Coretrack

Exoma Energy Rawson Resources

MEO Australia Dart Energy Titan Energy

Advent Energy Lochard Energy

AWE Senex Energy Neon Energy

New Guinea Energy Challenger Energy Buccaneer Energy

Nexus Energy Bass Strait Oil Key Petroleum Cooper Energy MEO Australia

Westside Quest Petroleum

oil & gas insider


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This week’s edition of Oil & Gas Insider has been brought forward by a day due to the Good Friday public holiday this week. The next edition will return to Thursday publication.

oil & gas insider


Onshore Rig Schedule 1 15 16 30 1 15

MB Century Rig-3

Senex

MB Century Rig-7

ConocoPhillips

ADS Rig-2

Oil Basins

Ensign Rig-918

Beach

Ensign Rig-916

Beach

Ensign Rig-930

Beach

Ensign Rig-932

Buru

Ensign Rig-950

Santos

Ensign Rig-948

Senex

Ensign Rig-919

Saxon Rig-183

Santos

Saxon Rig-182

Santos

Saxon Rig-184

Santos

Parker Rig-226

Horizon

Hunt Rig-3

Hunt Rig-2

InterOil

Weatherford Rig-100

Geodynamics

Weatherford Rig-826

BG/QGC

AWE

Buru

MB Century Rig-14

Lakes

InterOil Rig-2

Ongoing Santos (Fairview area)

April May

Tasmania-1

Ongoing Santos

Ongoing Santos

Available

Available

Backreef-1 testing

Ongoing Santos

Moonta-1

Habanero-4

Talaq-1

Ketu-2

Haslam-1

Marsden-1 (flood delays)

Wait on weather

Yulleroo-3

Snatcher-4

Evandra-2

Davenport-1

Streaky-1

Growler-10

Wait on location Moreys-1

Tindilpie-15

Southend-1

Skipton-1

Paradise Deep-1

Unavailable

Boston-1

Riley-1

Stanley-3

Mobilising to Darwin Unavailable

Snatcher-5

Triceratops-2

oil & gas insider


Offshore Rig Schedule

1 15 16 30 1 15

Atwood Eagle

BHP Billiton

Atwood Osprey

Chevron

Ensco-104

Apache

Ensco-109

PTTEP

Ocean Patriot

PTTEP

Stena Clyde

Origin

Nanhai 6

BHP Billiton

Transocean Legend

ConocoPhillips

Jack Bates

Hess

Deepwater Frontier

ExxonMobil

Ocean America

Woodside

Gorgon Development (8 wells)

April

Montara Dev (5 wells, until Q1 2013)

Boreas-1

Jabiru/Challis dev

May

Norton-A

Thistle-1

Jansz Dev (10 wells)

Woodside TBA

Glencoe-2

Tallaganda-1

Bambra-10 tri-lateral

Stickle-8H4

Unavailable

Rig acceptance

Ongoing Chevron

HJV abandonments

Maple-2

Ravensworth W/O

oil & gas insider


Current & Planned Offshore Seismic CLIENT CONTRACTOR WHERE WHEN STATUS

Survey Name Vessel Basin

CURRENT

BP PGS EPP-37, -38, -39, -40 Nov 18

~66% of 12,500km2 3D. Waiting on weather. Continuing ~late May Ceduna 3D Ramform Sterling Great Australian Bight

TGS CGGVeritas WA-364-P, WA--365-P, WA-367-P Nov 7

81% of 8850km2 3D on Mar 5 Mary Rose MC3D Viking Vision Exmouth Sub

Chevron PGS WA-253-P, WA-16-R, WA-17-R Dec 16

1060km2 (x2) 3D continuing ~late Mar Wheatstone MAZ 3D Ramform Explorer Carnarvon

TGS Fugro WA-347-P, WA-348-P Feb 16 50% of 2093km2 3D on

Mar 5 Gnaraloo Geo Atlantic Carnarvon

Shell SeaBird WA-385-P, lines into WA-384-P, WA-271-P Mar 21 782km 2D started

Tortilla 2D Voyager Explorer Exmouth Sub

OMV Polarcus PMP-38160 Mar 28 280km2 scheduled started

- Alima Taranaki

PLANNED

Origin PGS TAS-30-P, VIC-P-43, TL-2/3 Nov-Dec 520km2 3D scheduled

Astrolabe 3D Ramform Sterling Otway

Chevron PGS Multi-permit Dec 2012 1700km2 3D scheduled

Nothern Deepwater 3D Ramform Explorer

Bight Petroleum Uncontracted EPP-41, EPP-42 1H 2013 2500km2 2D scheduled

- Ceduna

Bengal Energy Uncontracted AC-P-47 Early 2012 750km2 3D scheduled

- Timor Sea

Trident Energy Uncontracted VIC-P-62 May 8 - Apr 30

246km2 3D scheduled Torquay Sub Basin 3D Torquay Sub

Gulf Energy Nordic Maritime Q-23-P Late Mar 2226km 2D scheduled

- Orient Explorer Gulf of Carpentaria

Woodside Polarucs WA-462-P, WA-464-P. WA-466-P Apr 11,500km2 3D scheduled

Curt 3D Alima Rowley Sub

Flow Energy Uncontracted WA-457-P. WA-458-P Unknown 564km2 3D scheduled

- Dampier

Chevron PGS WA-455-P, WA-456-P Mar 27

270km2 plus optional 20km 2D scheduled Osprey 3D Ramform Explorer Carnarvon

Geoscience Aust Uncontracted - Late Feb - Early Mar 300km2-3D scheduled

Vlaming CO2 3D Vlaming Sub

Chevron PGS WA-37-L, WA-14-R, WA-15-R, WA-22-R Apr 4 50km 2D scheduled

Dionysis 2D Ramform Explorer

PTTEP PGS AC-RL-7, AC-RL-7, AC-P-54 Apr 1048km2 3D scheduled

Sandalford 3D Ramform Explorer Vulcan Sub

Searcher Seismic SeaBird WA-364-P, WA-365-P, WA-346-P, WA-386-P, WA-434-P Mid Apr 3700km long offset 2D

scheduled Duvalia MC2D - (outer Exmouth Sub)

Searcher Seismic SeaBird WA-447-P, WA-449-P, WA-462-P, WA-464-P, WA-466-P Early-mid

May 3100km 2D scheduled Mariner NE 2D - Browse

Apache PGS WA-28-L, WA-35-L, WA-44-R, WA-357-P Q2 108km2 3D scheduled

CVG 3D Ramform Explorer Exmouth Sub

Arcadia Uncontracted WA-379-P, WA-380-P Q4 2012/Q1 2013 1500km2 3D scheduled

- Bremer Sub

PGS PGS WA-281-P, WA-285-P, WA-413-P, WA-414-P, WA-424-P, WA-425-P, WA-429-P, WA-431-P, WA-432-P Q2 7500km2 3D program

resuming Aurora MC3D (resumption) Ramform Explorer Browse

oil & gas insider


CLIENT CONTRACTOR WHERE WHEN STATUS


PLANNED

Beach Terrex PEP-168 Early Apr 100km 2D and 50km2 scheduled

- Crew 407 Otway

PetroFrontier Terrex EP-104 Q3 800km 2D scheduled

Owen 2D Crew 401 Georgina

Drillsearch Uncontracted ATP-940-P Unknown 1050km2 3D scheduled

- Cooper

BG/QGC Terrex - Jun/Jul 250km 2D scheduled

Sark 2D Crew 405 Surat

Holloman Terrex PEL-112 Unknown 125km2 3D scheduled

- Crew 402 Cooper

UIL Uncontracted EP-447 Late 2012 - Early 2013

~200km 3D scheduled Badgnigarra 2D - Perth

Armour Energy Terrex EP-171 Apr 15 67km 2D scheduled

- Crew 404 McArthur

Apache Uncontracted PEP-38348, PEP-38349 1H 2012 130km 2D scheduled

- East Coast

Empire Uncontracted EP-389 Q2/Q3 90km2 scheduled

Heliseis Perth

Origin WesternGeco EP-368, EP-426 Mid Apr 100km2 3D scheduled

North Erregulla 3D Perth

Senex Terrex PEL-88, PEL-95, PEL-514 Mid Apr 790km2 3D scheduled

Cordillo 3D Crew 403 Cooper

Drillsearch Uncontracted ATP-539-P, ATP-549-P Unknown 560km2 3D scheduled

- Eromanga

BG/QGC Terrex - Jun/Jul 367km 2D scheduled

Middlemount 2D Crew 405 Surat

Santos Terrex ATP-752-P May 17 237km2 3D scheduled

Greater Leleptian Crew 402 Surat Bowen

Metgasco Terrex PEL-13 May 35km 2D scheduled

2012 MET 2D Crew 404 Gunnedah

Origin Geokinetics PL-226 Mid-late Apr

228km2 3D scheduled Dalwogan 3D Crew 488 Surat

Origin Geokinetics - Early Apr 45km2 3D scheduled

Farawell 3D Crew 488 Surat

Santos Terrex - Mid Apr 70km 2D scheduled

Tonto 2D Crew 402 Eromanga

NZEC Webster Drilling PEP-51151 May-Jun 50km2 3D scheduled

Alton 3D Taranaki

Larus Energy Uncontracted PPL-326 2H 2012 1100km 2D scheduled

- Papuan

Current & Planned Onshore Seismic

CLIENT CONTRACTOR WHERE WHEN STATUS


CURRENT

Santos Terrex PL-148, ATP-259-P Jan 31 47% of 399km2 3D on Mar 21 (wait

on weather) Scarabwhanto 3D Crew 402 Surat

Origin WesternGeco EP-320, L-1, L-2 Feb 16 40% of 450km2 3D on Mar 23

Redback/Irwin 3D Crew 1160 Perth

Beach Terrex ATP-855-P Feb 18 39% of 425km 2D on Mar 21 (wait

on weather) Gallus 2D Crew 404 Cooper

Beach Terrex PEL-92 Mar 23 197km2 3D started

Ricon 3D Crew 403 Cooper

AJ Lucas executives anxiously looking out windows

Mar 29: AJ Lucas can’t take a trick lately. This week it announced that another wet summer in much of Queensland had put a dent in its revenue forecasts for the year ending June 30, down from $37mil to $32mil. Much of the downgrade was due to wet weather in March impacting on its drilling operations, “with almost the entire Queensland rig fleet stood down at various times”. While contract terms negate the loss of income due to down time to some extent, “these have not been sufficient to compensate the Company entirely for lost production”. AJ Lucas believes the weather is improving as we go further into autumn, with all its contracted fleet expected to resume normal operations soon. However additional mobilisation costs will be incurred to get the rigs and crews back onto locations. Overall AJ Lucas expects a “substantially improved financial performance in the second half and that the underlying financial result for the financial year would be as previously advised, that is in excess of $50 million”. No doubt it will be hoping for more juicy contracts such as the newly negotiated multi-well work for Armour Energy, which is planning a McArthur Basin program starting this May. Likely to be undertaken by the currently stacked 2000m capacity, 600 horsepower Rig-DRS085, Armour is planning nine vertical and three lateral wells - plus two multi-stage fracs - in its EP-171 and EP-176 permits. Armour’s 2012 work program is focussing on conventional targets as well as establishing the potential prospectivity of unconventional resources in its frontier Northern Territory permits. The company has also contracted Terrex Seismic to conduct a 67km 2D seismic survey in EP-171 starting in mid-April.

DGRGlobal (ASX:DGR) spinoff Armour has launched one of the bigger oil & gas IPOs for many years, seeking to raise $75mil. If successful as confidently predicted, Armour could have ongoing work across its other NT and Queensland permits and applications as these are awarded; an alliance that AJ Lucas would be keen to attach itself to. AJ Lucas has also advised that it will make a share placement to raise approximately $15.5mil after its rights issue fell well short of the intended target of $51.3mil. On 21 February AJ Lucas announced that out of a maximum number of entitlement shares of just over 38mil available for subscriptions under an entitlement offer, only an embarrassingly small number of under 6.8mil were applied for. This meant less than 20% of the target amount was raised and threw the underwriters into spasms. While the new placement will be at the same share price as the entitlement offer, $1.35, the combined funds raised will still only be around half the amount of $51.3mil the company originally wanted to gain. The other area of AJ Lucas’s operations that has gone awry is its upstream Cuadrilla shale gas project in the UK. Here activities are still stalled while the JV waits on the British government to allow fraccing to resume. The ban was largely put in place due to Cuadrilla’s fraccing operations causing small earth tremors around the Blackpool location. AJ Lucas says it expects “that the government decision on the resumption of fracking will be made in the next few weeks, the outcome of w h ich w i l l de te rmin e Cuad r i l l a ’ s commercialisation plan”. While AJ Lucas (AJL) bought its latest disappointing news to the market on 29 March, its share price started to decline from 27 March when it was trading at $1.16. Three days later on 30 March it reached its lowest point of the week at $1.085 before starting a recovery, at one stage on Monday reaching $1.13.

oil & gas insider Wednesday, 4 April 2012

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AJ Lucas was trading down $0.025 at $1.07 on volumes around 394,000 earlier today. AJ Lucas announcement: Operations Update and Earnings Guidance The Company reported in its half year results released on 29 February 2012 that it expected a substantially improved financial performance in the second half and that the underlying financial result for the financial year would be as previously advised, that is in excess of $50 million. Wet weather over the past few weeks has, however, had a major impact on the Company’s drilling operations, with almost the entire Queensland rig fleet stood down at various times. Whilst the Company’s contracting terms mitigate the effect of the down time, these have not been sufficient to compensate the Company entirely for lost production. The weather has now improved and it is hoped that all the contracted rigs will soon resume normal operations. There will however, be additional mobilisation costs associated with the resumption of activities. The Company’s drilling activities have also been impacted by various delays and other interruptions in the coal seam gas drilling business due to site access factors. This has impeded the Company’s resource allocation and resulted in increased unrecovered overhead costs. The Company’s BCI division has been impacted by continuing resource constraints and delays in the award of projects and their progress. These factors are, in turn, impacting on the profitability of this division. Capital constraints continue to impede progress on the tooling up for several projects. Nevertheless, the Company expects a much stronger final quarter as some of the contracts awarded over the last few months commence in earnest, assuming no resumption of wet weather.

Having regard to all these circumstances, the Company now expects the full year underlying EBITDA to be in the range of $32 million to $37 million. Cuadrilla Regarding the Company’s European shale gas portfolio, limited activity has been carried out over the past six months while awaiting a decision from the British government on their consent to resume fracking. Cuadrilla has, however, commenced shooting 3D seismic over 150 sq Km of the Bowland prospect in anticipation of the resumption of fracking, to be complemented by a micro-seismic program. In addition, drilling will commence shortly on a fourth well to be known as Anna’s Road. It is expected that the government decision on the resumption of fracking will be made in the next few weeks, the outcome of which will determine Cuadrilla’s commercialisation plan. Following the resumption of fracking, the four wells would be expected to take up to 12 months to be fracked after which Cuadrilla will have a good understanding of the gas flow rates and the amount of recoverable reserves. Further details will be released as soon as they become available. Equity Raising As has been announced previously to the market, the Company did not raise the full $51.3 million from the rights issue conducted earlier this year. The Company has explored various options to determine the most appropriate method of raising the $15.5 million shortfall to ensure that the Company is placed in the same economic position that it had anticipated to be in before the rights issue. To that end, the Board has resolved to proceed with a placement to raise approximately $15.5 million. The placement will be subject to shareholder approval and made on terms similar to the recently completed Entitlement Offer, that is at an issue price of $1.35 per share. The Board has identified parties willing to subscribe to the placement on these terms. Currently, it is expected that this placement will be completed no later than the end of this financial year. This timetable is required to enable the Company to secure the relevant commitments and then prepare the necessary EGM documentation and independent expert’s report. The Company is looking to issue a notice of meeting for the EGM to approve the placement in or about mid-May. Banking Facilities The Company’s Senior Financier has confirmed the continued provision of banking facilities to the Company subject to the completion of the placement and settlement of the amounts owing to the Australian Taxation Office by 30 June 2012. The Board, at this date, has no reason to believe this will not be achieved having regard to the interest shown by potential investors in participating in the equity placement.


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Contact Allan Campbell Chairman and CEO AJ Lucas Tel: (02) 9490 4000

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Back to Index

Aussie juniors put spotlight on East Africa

Mar 29 & Apr 2: East Africa is attracting increasing world-wide attention as a potential new oil & gas hot spot, with two Aussie explorers keen to be involved. One of them, FAR Ltd, was one of the early movers in the region, while Jacka Resources has more recently been building its presence there. Last week FAR announced its intention to undertake a fundraising of $15mil to be put towards its offshore Kenya oil and gas exploration. A placement of 280mil shares is expected to raise just over $12mil, with another $3mil earmarked from a share purchase plan to existing shareholders. The SPP, which will offer approximately 70mil shares, opened on Monday and is scheduled to close on Friday 13 April. FAR says the capital raising will allow the company “to maintain its equity interest in Kenyan Block L6 and Block L9, close to a string of recent major offshore gas discoveries”. Managing director Cath Norman said she was confident that shareholders will soon start to see the rewards of the company’s early move into East Africa, where interest is growing. “Shell’s recent takeover offer for a leading junior East African player, Cove Energy, which was subsequently overbid by the Thai company PTTEP demonstrates the accelerating global interest that is in this region,” Norman said. Norman also pointed to “recent offshore gas discoveries by companies such as BG, ENI Spa, Anadarko Petroleum Corp, Statoil, ExxonMobil and Ophir Energy off the coasts of Mozambique and Tanzania.” After coming off a trading halt pending the capital raising announcement, FAR’s shares immediately fell $0.02 to $0.047 on volumes of almost 15mil shares. Since Thursday they have recovered to be trading as high as $0.053 on Monday before closing that day at $0.05.

The other East African news involves Jacka Resources, which has farmed into an initial 50% operating interest in onshore Somaliland. Covering an area of approximately 22,000km2, the block features “a working petroleum system demonstrated by nine independently verified oil seeps” and is on-trend with oil producing fields in Yemen across the Gulf of Aden. The farmin agreement over the so-called Habra Garhajis block is with little-known Petrosoma Limited, which Jacka says can provide the JV with in-country “operational capability”. Under the deal Jacka will repay a contribution towards Petrosoma’s past costs, then fully-fund the JV’s “third period minimum work program, consisting of studies, gravity survey and a minimum 500 kms of 2D seismic”. A gravity and magnetics dataset is scheduled to be acquired in Q2 . Jacka has an option to earn an additional interest in the Habra Garhajis block if it decides to enter the fourth period. A little ominously, one of the in-country services Petrosoma will provide is security, in a country that over decades has seen civil war and political and social unrest. Jacka glosses over these problems by saying “Somaliland is acknowledged as having established a stable, democratic political system over its territory”. However it fails to mention that the Republic of Somaliland is not yet recognised as an official state/country by the UN. Similar to FAR, Jacka points out the spotlight that is being shone on East Africa, saying the region “is the subject of an increasingly strong and competitive industry focus with companies such as BG, Ophir, ENI, Africa Oil, Anadarko, Total, CNOOC and others taking positions, along with wells being drilled or planned in the neighbouring basins of the Dharoor and Nugaal”. Jacka’s chairman Scott Spencer said that “Jacka’s management have held the belief for a long time that Somaliland holds great potential. This is a quality underexplored basin with enormous potential that reinforces the company’s new venture strategy both in East Africa and rift systems”.


Cont’d next page

Spencer and Jacka executive director Richard Aden both worked with former ASX-listed Hardman Resources, which tasted success in Africa before being acquired by Tullow Oil in 2006. The Somaliland project builds on Jacka’s other African acreage in Tunisia, Nigeria where it has a 5% net revenue interest in the Aje oil and gasfield, and Tanzania which is still going through the approvals process. The market liked Jacka’s move into Somaliland sending the shares (JKA) up to $0.19 on Monday, its highest price in 13 months, before settling back to $0.17 later in the week. Jacka was trading up $0.01 at $0.175 on volumes around 2.2mil while FAR was down $0.003 at $0.047 (+12.5mil) earlier today. FAR announcement: FAR Raises $15 million to Fund East African Exploration FAR Ltd plans to raise $15.04 million, to fund offshore oil and gas exploration in East Africa off the Kenya coast. The funds will be raised through a placement of 280 million shares at 4.3 cents per share to raise up to $12.04 million and a Share Purchase Plan of up to $3 million to existing shareholders. The placement is being made predominantly to international and domestic institutional clients of Hartleys Limited, broker to the offer. A total of approximately 70 million shares at 4.3 cents per share will be offered under the SPP to eligible shareholders registered at 28 March 2012, with SPP documentation to be sent to eligible shareholders shortly. The SPP will open on Monday 2 April 2012 and close on Friday 13 April 2012. The capital raising will allow FAR to maintain its equity interest in Kenyan Block L6 and Block L9, close to a string of recent major offshore gas discoveries. FAR’s managing director Cath Norman said “We were overwhelmed by the support shown for the placement. We received offers for a multiple of the money we sought to raise, which shows the interest that is building in the East African oil and gas province.”

“FAR is one of the early movers in East Africa and has accumulated an enormous acreage position in prime exploration areas.”

“I am confident that the rewards from several years of hard work in this area will now start to flow to shareholders,” said Ms Norman.

“Shell’s recent takeover offer for a leading junior East African player, Cove Energy, which was subsequently overbid by the Thai company PTTEP demonstrates the accelerating global interest that is in this region.”

“Adding to this excitement are the recent offshore gas discoveries by companies such as BG, ENI Spa, Anadarko Petroleum Corp, Statoil, ExxonMobil and Ophir Energy off the coasts of Mozambique and Tanzania.”

This announcement lifts the trading halt on FAR’s securities.

Jacka Resources announcement: Jacka farms in to Somaliland block Key Highlights: Jacka to acquire initial 50% interest and be Operator The Block encloses some 22,000km2 with natural oil

seeps within the block A working petroleum system demonstrated by nine

independently verified oil seeps On trend with the prolific producing basins of Yemen

estimated to contain up to 9.8 billion barrels of oil equivalent Jacka increases East African oil footprint

Jacka Resources Limited (“Jacka” or “the Company”) is pleased to announce that it has entered into an agreement with Petrosoma Limited (“Petrosoma”) to become Operator and a 50% equity holder in Blocks 6,7 (partial) and 10 (partial), located onshore Somaliland (see Figure 1 & 2) which are the subject of a Production Sharing Agreement (“PSA”) with the Government of the Republic of Somaliland. The PSA area, which was formerly known as ‘block 26’, is informally referred to hereafter as the “Habra Garhajis block”.

Block Overview The Habra Garhajis block lies in the south west of Somaliland and covers an area of some 22,000 km2. The Block completely encloses what became known during British colonial times as the Habra-Garhajis basin. This is one of three genetically-related, en-echelon Jurassic rift basins in the Horn of Africa that are the continuations of the prolific Jurassic rift basins of Yemen (Figure 3). Yemen and the Horn of Africa have been separating since the Oligocene due to the ongoing East African Rift and opening of the Gulf of Aden.

The Habra-Garhajis basin is an estimated 220km long and 50km wide. Based on existing gravity and magnetics data, these are typical rift segment dimensions, amply demonstrated in the modern East African Rift including the Albertine graben in Uganda.

The geology of the Habra-Garhajis basin is expected to be very similar to the prolific producing basins of Yemen where 9.8 billion barrels of oil equivalent have been discovered or are to be discovered1.

A working source kitchen is demonstrated within the Garhajis basin by nine already identified individual oil seeps (to date). Geochemical analysis points to an original light oil or condensate, consistent with the oils produced in Yemen. The 20km - 40km migration distance implied by the location of some of the seeps suggests potential for a prolific source kitchen and a regional seal. 1 Per US Geological Survey 2002


Contact Catherine Norman Managing Director FAR Limited Tel: (03) 9618 2550 Richard Aden Executive Director Jacka Resources Limited Tel: (08) 9388 8041

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Cont’d next page

Operations Jacka’s joint venture partner in the block, Petrosoma, has an established in-country office and team which will provide immediate operational capability to the Joint Venture. An aggressive work program is scheduled, starting with acquisition of a comprehensive gravity and magnetics dataset in the second quarter of 2012. The entire East African region is the subject of an increasingly strong and competitive industry focus with companies such as BG, Ophir, ENI, Africa Oil, Anadarko, Total, CNOOC and others taking positions, along with wells being drilled or planned in the neighbouring basins of the Dharoor and Nugaal.

Somaliland Overview Somaliland was a British protectorate from 1883 until 1960 when it gained independence. Shortly thereafter the country merged with former Italian Somalia and formed the Somali Republic. In 1991, following years of civil war Somaliland withdrew from the union with Somalia and reinstated Somaliland’s sovereignty. Somaliland is acknowledged as having established a stable, democratic political system over its territory.


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Transaction Overview The key terms of the transaction are as follows: Jacka to earn 50% equity (subject to government

approval) by paying a contribution toward past costs on the licence and 100% of the PSA third period minimum work program, consisting of studies, gravity survey and a minimum 500 kms of 2D seismic.

Petrosoma to provide in-country logistics, security and government relations to the joint venture

If Jacka elects to enter the PSA fourth period it has the option to earn additional equity in the licence area (subject to performance and government approval); otherwise if Jacka elects not to complete the farm-in it will re-assign its participating interest to Petrosoma with no further obligation

Jacka and Petrosoma have agreed the Republic of Somaliland is an area of mutual interest, with any further projects in the region to be pursued on a 50/50 basis

Jacka’s Chairman Scott Spencer commented “Jacka’s management have held the belief for a long time that Somaliland holds great potential. This is a quality underexplored basin with enormous potential that reinforces the company’s new venture strategy both in East Africa and rift systems”.

We are delighted to be partnering Petrosoma and entering this block in Somaliland. We look forward to working with Petrosoma over the coming months and executing the exploration program”.

Green Rock takes bigger bite of Canning Basin

April 2: Green Rock Energy builds on its Canning Basin acreage by farming into Oil Basins’ Backreef project in a deal potentially worth up to $3.6mil. A heads of agreement has been signed through which Green Rock has an option to acquire up to 20% of the Backreef area in L-6. The deal is timed strategically for Oil Basins, which is lining up a cased hole production test of its inconclusive Backreef-1 oil discovery, scheduled to start next month. A second well in the Backreef area is also planned for Q3 this year. Green Rock will tip in an up-front option payment of $1.1mil which is expected to fully fund the cased hole production test for an estimated cost of $900,000. From that point on Green Rock will contribute to the project on a pro rata basis and, if it decides to participate at the full 20% farmin interest, will contribute another $2.5mil towards future operations. These consequent operations could include an extended production test of Backreef-1, and/or the drilling and completion of a second well - most likely an appraisal Backreef-2 or exploration drill East Blina-1 - by 31 October 2012.

Green Rock says the deal enables it “to increase its footprint in the Canning Basin and gain exposure to a near term production oil well, the Backreef-1”. The company is also excited by the proximity of Backreef-1 to other nearby discoveries such as the Blina field and Ungani-1; both operated by Buru Energy. Part of the “strategic rationale” from the company’s perspective was that the acquisition of “a 20% interest in the Backreef Area aligns with Green Rock’s strategy to diversify by acquiring additional acreage in the Canning Basin with the additional prospect of near term production, while also complementing the existing hydrocarbon interests in EP-417 and the Area of Mutual Interest Agreement with New Standard Energy (ASX:NSE)”. Unfortunately EP-417, in which Green Rock holds 15%, hasn’t proved fruitful for the company so far, with the deepening of Lawford-1 in September/October last year throwing up some disappointing results. As 35% partner Buru explained compellingly at the time, Lawford-1 was terminated at 2690m MD above the original PTD because of; slow drilling due to very hard and abrasive formations, geological uncertainty, lack of significant hydrocarbon shows, and the encroaching wet season. Hard to argue with that. What’s more, Buru was dismissive of the well and - by inference - the surrounding area, saying “No distinctive geological or geophysical markers have been encountered, and the depth to the top of the Laurel Formation cannot be estimated with any certainty at this time”. Originally formed solely as a geothermal explorer, Green Rock will be banking on a better result from the less risky Backreef project. As outlined in last week’s Oil & Gas Insider, Oil Basins has secured Australian Drilling Services Rig-2 for the upcoming testing program at Backreef-1, and also has an option on either Rig-2 or ADS Rig-6 for two more wells later in the year. Green Rock considered having a rig in the pocket was a big plus, executive chairman Richard Beresford saying, “Oil Basins securing the drilling rig was a positive sign for Green Rock to advance negotiations as it provides the potential of near term production and subsequent value for Shareholders”.


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Whichever way you look at it though, the Backreef farmin is quite a big roll of the dice for Green Rock which had just over $0.5mil cash at hand at the end of the last quarter before last month raising $2mil via a placement of 400mil shares at $0.005. The Lawford-1 result started a decline in Green Rock’s share price from a 6-month high of around $0.022 to its lowest point at the beginning of last month of $0.002. On the day of the Oil Basins farmin announcement, Green Rock (GRK) traded as high as $0.015 before settling back down to $0.013. On the same day, Oil Basins (OBL) shares initially jumped from $0.084 to $0.089, before profit-taking saw a plunge down to $0.075. It closed the day at $0.078 on volumes of more than 20mil shares. Oil Basins was trading down $0.006 at $0.07 on volumes around 12.9mil earlier today. Oil Basins announcement: OIL BASINS FARMOUT OF UP TO 20% BACKREEF AREA FOR UP TO $3.6 MILLION KEY POINTS: Oil Basins Limited (ASX codes OBL, OBLOA & OBLOB)

and Green Rock Energy Limited (ASX code GRK) have executed a Heads of Agreement (HOA) relating to the farmout of up to a 20% interest in the Backreef Area, Canning Basin, Western Australia with an up-front Option Payment from GRK of $1.1 million.

This will fund 100% of the Backreef-1 cased hole production test estimated at $900,000 and thereafter GRK will contribute to it pro rata and, should GRK elect to participate at 20% in the Backreef Area, GRK has agreed to contribute a further $2.5 million on future operations such as an Extended Production Testing of Backreef-1 and/or the drilling and completion of a second well or Backreef-2 appraisal or East Blina-1 exploration well by 31 October 2012.

If fully completed (as contemplated in the executed HOA with GRK), OBL is fully funded in its present Backreef Area 2012 Work Program (Backreef-1 cased hole production test and at least one additional exploration well by 31 October 2012).

OBL will retain 80% net beneficial rights and operatorship of the Backreef Area.

OBL will retain 100% of any benefits from a future Buru Energy Limited backin.

OBL is pleased to welcome GRK as its new Backreef Area Joint Venture Partner and the newest emerging junior Canning Basin oil and gas explorer.

The directors of Oil Basins Limited (ASX codes OBL, OBLOA, OBLOB or the Company) are pleased to make the following ASX and Media Announcement.

OBL and Greenrock Energy Limited (ASX code GRK) have executed a HOA whereby for a non-refundable Option Payment of $1.1 million to OBL (within 48 hours of executing the HOA), GRK has the following Farmin rights to the Backreef Area: By payment of the Option Payment, GRK at its sole

election may elect to exercise an option to either a 5% or 20% interest in the Backreef Area by purchasing an OBL subsidiary.

Should either the budgeted or actual costs for the Backreef-1 cased hole production test exceed $900,000 - GRK will be charged appropriate pro rata costs dependent upon its Backreef Area holding percentage.

Subject to GRK entering into an unconditional agreement to attain up to 20% Backreef Area to be finalised no later than the earlier date of 24 hours prior to the rig-up of Australian Drilling Services Pty Ltd Rig-2 onsite at Backreef-1 or COB 30 April 2012 (“the Effective Farmin Date”).

Option 1: GRK Farmin for 5% Backreef Area Under this agreed scenario, GRK can elect to attain a 5%

net beneficial right to the Backreef Area by acquiring OBL’s wholly owned subsidiary OBL Backreef No 5 Pty Ltd ABN 57 119 477 084, which is entitled to 5% of the Backreef Area, by making a second non-refundable payment of $625,000.00 to OBL for future 2012 operations. These funds are intended to be used for conduct of the possible EPT operations at Backreef-1, and/or proposed new drilling operations at either a Backreef-2 appraisal well or East Blina-1 exploration well or any JV approved Lead no later than 31 October 2012.

GRK will appropriately rename the subsidiary upon Sale and Purchase Agreement finalisation/satisfaction.

Under this 5% farmin scenario, all expenditures over and above both the initial Backreef-1 production test and the additional further $625,000 amount to be shared 95% / 5% pro rata with OBL / GRK.

Option 2: GRK Farmin for 20% Backreef Area Under this agreed scenario, GRK can elect to increase its

interest from 5% to 20% net beneficial right to the Backreef Area by acquiring OBL’s wholly owned subsidiary OBL Backreef No 5 Pty Ltd ABN 57 119 477 084 (whose net beneficial interest to be appropriately increased to 20% of the Backreef Area from OBL) by making a second non-refundable payment of $2,500,000.00 to OBL for future operations. These funds are intended to be used for conduct of the possible EPT operations at Backreef-1, and/or proposed new drilling operations at either a Backreef-2 appraisal well or East Blina-1 exploration well or any JV approved Lead no later than 31 October 2012.


Contact Neil Doyle Director/CEO Oil Basins Ltd Tel: (03) 9692 7222 Fax: (03) 9529 8057 Richard Beresford Executive Chairman Green Rock Energy Tel: (08) 9482 0482

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GRK will appropriately rename the subsidiary upon Sale and Purchase Agreement finalisation/satisfaction.

Under this 20% farmin scenario, all expenditures over and above both the initial Backreef-1 production test and the additional further $2,500,000 amount to be shared 80% / 20% pro rata with OBL / GRK.

Other agreed conditions of the executed HOA Should GRK fail to deposit either of the non-refundable

payments ie $625,000 for confirming 5% or $2,500,000 for confirming 20% by the Effective Farmin Date, for whatever reason, the Farmin will have deemed to have lapsed and will be terminated and all Farminee rights with respect to the ownership of OBL Backreef No 5 Pty Ltd ABN 57 119 477 084, the Backreef Area and any payments made therefor other than the Option Payment, will be immediately and irrevocably rescinded.

Under no account will an incomplete Farmin be permitted by OBL once the Backreef-1 cased hole production test operations have commenced.

No fractions or other percentages other than 5% or 20% are contemplated by the Conditional Farmin Agreement.

GRK will not be a recipient of any benefits to OBL and the OBL Group resulting from Buru Energy Limited exercising its backin rights under the Backreef Play Agreement (BPA).

GRK agrees at all times to align its voting interests with OBL until all aspects of the Farmin Terms (including any possible New Licence Award and/or future Unitisation) of the BPA is complete.

Farmout is wholly in accordance with the BPA and subject to usual DMP consents.

Finally, the directors of Oil Basins Limited are pleased to welcome Green Rock Energy Limited as its new Backreef Area Joint Venture Partner and the newest emerging junior Canning Basin oil and gas explorer.

Green Rock Energy announcement: Green Rock option to acquire up to 20% interest in Canning Basin acreage adjacent to Blina Oil Field Highlights HoA executed with Oil Basins Limited (OBL) for option

to acquire up to 20% interest in the Backreef Area in the Canning Basin for up to $3.6 million

Cased Hole Production Test drilling planned to commence early May 2012

Re-entry into existing well with indications of oil on the logs Backreef Permit is directly adjacent to the producing

Blina Oilfield, currently held by Buru Energy Limited Second well to be drilled Q3 of 2012 Builds on the Company’s existing hydrocarbon interests

in the Canning Basin Overview Green Rock Energy Limited (ASX:GRK) (“Green Rock” or “the Company”) is pleased to advise that it has executed a binding Heads of Agreement with Oil Basins Limited (ASX:OBL) (“Oil Basins”) in relation to an option to acquire up to 20% of the highly prospective Backreef Area in the Canning Basin. This acquisition has enabled Green Rock to increase its footprint in the Canning Basin and gain exposure to a near term production oil well, the Backreef-1. Other commercial oil discoveries in the area include the producing Blina Oilfield, with oil intersected in the Yellow Drum Formation, and the Ungani Well, also operated by Buru Energy Limited. A map of the area and the Backreef-1 well location is below. A driling rig has been contracted by Oil Basins and is scheduled to conduct the Backreef-1 Cased Hole Production Test in May 2012. Strategic Rationale The opportunity to acquire up to a 20% interest in the Backreef Area aligns with Green Rock’s strategy to diversify by acquiring additional acreage in the Canning Basin with the additional prospect of near term production, while also complementing the existing hydrocarbon interests in EP417 and the Area of Mutual Interest Agreement with New Standard Energy (ASX:NSE).


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The Backreef-1 well was originally drilled by Oil Basins in October 2010, with the well cased and suspended at 1,155m pending production testing. Testing conducted after the original drilling demonstrated positive oil shows from the Yellow Drum Formation at a depth of 917-994m. In its ASX Announcement on 22 March 2012 Oil Basins confirmed that it has formally contracted Australian Drilling Services Petroleum Drilling Rig 2 for the cased hole production test at Backreef-1, and that the rig will be mobilised and on site on or prior to 1 May 2012. Green Rock’s Executive Chairman, Richard Beresford said, “Oil Basins securing the drilling rig was a positive sign for Green Rock to advance negotiations as it provides the potential of near term production and subsequent value for Shareholders”. In its ASX Announcement on 16 January 2012, Oil Basins said that RPS Energy Services Pty Ltd (“RPS”) were engaged in October 2011 to perform an independent evaluation to delineate Prospective Resources for the Backreef-1 oil show and the Backreef Area. RPS concluded in accordance with PRMS guidelines that the Kimberley Downs Embayment contained within the Backreef Area could host significant Undiscovered Oil Initially in Place volume between 45.6 to 117 MMbbls with an expectation of 77.7 MMbbls and a mean estimate of 20.6 Mmbbls Prospective Resources. Oil Basins has conducted significant evaluation of the Backreef-1 Well since casing, including petrophysical assessment, extensive re-processing of existing seismic data and interpretation of the oil shows. The comprehensive analysis of the well data has encouraged Oil Basins to immediately perforate Backreef-1 to confirm the fluid content, permeability and hydrocarbon productivity of the reservoir. The Backreef Area is located in the onshore Canning Basin, approximately 70km east of Derby, and comprises part thereof of 3 licences. The Backreef Area is to the immediate north of the producing Blina Oil Field, which is the largest oil field discovered so far within the Fitzroy Trough. Attractiveness of the Canning Basin The Canning Basin until recently has been relatively underexplored for the last 20 years due falling oil prices, gas prices, difficult native title process and lack of funding for exploration. The Canning Basin is the largest sedimentary basin in Western Australia covering an area of approximately 530,000 square kilometres. Recent exploration has been enhanced by continuous high oil prices and increased gas demand. The interest in the Canning Basin is growing, due to a number of significant farm-ins such as, Mitsubishi Corporation and Buru Energy Limited and ConocoPhillips and New Standard Energy Limited. “To be able to acquire a project this advanced is encouraging for Green Rock as it will further broaden our activity across the Canning Basin with the opportunity of near term production. The previous oil shows for Backreef-1 have de-risked the asset in our opinion, with the positive oil shows at a depth of 48.9m gross and the comprehensive study completed on the Backreef-1 well,” Mr Beresford said. In 2011 Green Rock farmed into EP417 with New Standard Energy Limited, earning a 15% interest in the licence area with a right to earn up to 20%. In addition to the farm-in Green Rock and New Standard Energy Limited executed an Area of Mutual Interest (40% and 60% respectively), whereby the parties actively pursue new exploration opportunities for unconventional hydrocarbons.

The acquisition of the Backreef Area increases Green Rock’s interest in the Canning Basin but in addition provides near term value for the Company and Shareholders through the potential production of the Backreef-1 Well. Mr Beresford said, “The Canning Basin is a key area of interest, not only in our opinion but recognised internationally also. We are pleased to be able to increase our footprint in the Canning Basin and provide this opportunity for our shareholders. We will continue to pursue new opportunities with a hydrocarbon focus to add additional value to our portfolio of hydrocarbon and geothermal interests”.

A trouble free re-start for Galoc with new & improved FPSO

Apr 2: There would be high fives all round in the Philippines this week as the newly upgraded Galoc field resumes production on schedule in SC14C with the newly upgraded FPSO, following a period of time where the field has been shut in while the Rubicon Intrepid has been undergoing refurbishment. Otto Energy and Nido Petroleum, the two locally listed equity holders, announced on Nov 23 last year that the field was being shut in while the FPSO sailed to Singapore’s Keppel shipyard for a turret installation work program, expected to take about three months. The upgrade of the vessel’s mooring capability to a bow-mounted, non-disconnectable turret system was undertaken to improve the reliability of the FPSO and its uptime on the field, ahead of the green light being given for the project’s expansion in the Galoc phase II development in a few months time. The upgraded equipment the Rubicon Intrepid is in receipt of is a mooring system where lines are connected to the turret which, via bearings, allows the vessel to rotate around the anchor legs. The single-point mooring system permits the vessel to "weathervane" 360 degrees, facilitating normal operations in moderate to extreme sea conditions, with the external turret system, like the one installed on the FPSO, being less expensive than internal turret designs. While the FPSO was out of the picture, the JV also carried out some seabed anchoring and riser modifications in advance of the vessel’s reconnection, in a bid to ensure previous lengthy periods of downtime do not occur again.


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In the past, the Rubicon Intrepid has been plagued by some horrendous periods off location, when problems have arose following during and subsequent to some of the many severe storms that the Philippines is prone to. From the announcement in Dec 2007 of the expectation of first oil from the field in Apr 2008, it seemed to be one setback after another for the JV. Typhoon Fengshen, and subsequent patches of inclement weather, coupled with persistent issues with the FPSO during disconnection and reconnection to the field, delayed the first oil date for Galoc to Oct 9 2008. Again, in mid Dec 2008, a weather event required the FPSO to disconnect from the location to take shelter, and a routine survey of the mooring system and riser uncovered a parted component that needed to be hooked back up before reconnection and delaying the resumption of production to late Jan 2009. Specialist support vessels and deepwater divers were deployed to the area to rectify the issues in Jan, but it took until Feb 26 for production to re-start and the field to ramp back up to pre-shut down levels of 14,000BOPD. Not long after resuming, on Mar 9 2009, the field had produced its first million barrels of oil. Almost three years later to the day the more streamlined JV – including Otto operating with 33% via its wholly owned subsidiary Galoc Production Company and Nido with 22.87% - is starting to put it all together in SC14C. Oil will start to flow again, likely at rates of around 7000BOPD following the four month shut down, and the hardware upgrades have been designed to alleviate future down time, and ensure the field can continue operating in the typical sorts of weather disturbances that are all too common in the region. In addition, the field’s reserves have been upgraded, and the phase II development of the field is closing in on being sanctioned towards midyear. Around a month ago on Mar 1, the Galoc partners reported the results of an independent reserves audit undertaken by Gaffney Cline & Associates, which reported an increase in the Estimated Ultimate Recovery at the Proved reserves level from 12.4mil bbls to 14.44mil bbls, with the EUR for the 2P and 3P reserves increasing by 0.17 and 3.14mil bbls respectively.

On the JV’s impending field expansion decisions, Peter Strachan commented on the phase II development of Galoc in the Apr 4 2012 edition of StockAnalysis: “Over the coming 2-3 months, finishing touches will be added to a final investment decision (FID) which could see the drilling of two new horizontal production wells at Galoc, accessing up to 7 mmbbls of additional oil, as well as an exploration well on the North Galoc structure that could add 3-5 mmbbls more. Newly acquired 3D seismic data over the field and prospects will inform decisions on well location and orientation. Success with this re-development could see Galoc in profitable production through until at least 2017 and possibly beyond.” Nido closed down $0.005 at $0.058 on volumes around 23.7mil while Otto closed up $0.005 at $0.145 (+2.2mil) on Apr 2. Nido was trading up $0.02 at $0.057 on volumes around 6.8mil while Otto was down $0.015 at $0.12 (+2.3mil) earlier today. Nido announcement: Galoc Oil Field Recommences Production The Galoc Production Company (GPC), operator of the Galoc oil field offshore Palawan in the Philippines, advises that production has restarted from the Galoc field on 2 April 2012 following a planned shutdown for refurbishment of the Floating Production Storage and Offloading vessel (FPSO). During the shutdown, the FPSO Rubicon Intrepid has undergone planned re-certification, maintenance, inspection and turret installation work. The most significant work scope has been the installation of a bow mounted, non-disconnectable turret mooring system to replace the previous disconnectable system. The upgrade of the FPSO mooring system is expected to increase the reliability and uptime of the FPSO and is a crucial component of infrastructure to enable the Galoc Joint Venture to move ahead with a potential Phase II development of the Galoc field.

Figure 1: FPSO Rubicon Intrepid with bow mounted non-disconnectable turret installed


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Galoc Phase II Update Front End Engineering and Design ("FEED") The joint venture commenced the engineering design work in late 2011 and remains on schedule for the Final Investment Decision ("FID") around mid-2012. The scope of FEED work, to be undertaken prior to FID, includes detailed subsurface modeling of the reservoir, drilling and completion design, subsea engineering and tie-back design for new wells as well as joint venture financing considerations. The FEED work is being undertaken in Perth primarily, with support from Otto Energy’s Manila-based Galoc Production Company personnel. Acquisition of 3D Seismic In addition to engineering and design works, acquisition of 184 km2 of new 3D seismic data was completed in late 2011, covering the Galoc field and adjacent Galoc North exploration prospect. The new 3D seismic will support the placement of Phase II wells in the reservoir and de-risk this major capital expenditure. In addition, it will also allow full evaluation of the Galoc North exploration prospect, which may realize further development opportunities for the Galoc field. Targeting Project Sanction mid-2012 The final project approval, Final Investment Decision ("FID"), for the Galoc Phase II development is targeted for around mid-2012. The Galoc Joint Venture will consider preinvestment in required infrastructure, including wellheads, flowlines and umbilical lines during the FEED stage.

News in Brief Apr 2: Octanex (OXX) updates the market about the timing of a couple of its big upcoming projects, in the process reminding us of two high-profile wells it will be involved in over the next 12 months. First there is Winchester-1 in which Octanex will have a 25% stake after farming out 75% and operatorship of Carnarvon Basin WA-323-P and WA-330-P to Santos. The JV has secured a jackup rig to drill the well, the Ensco-109, but delays with the current operator will push Winchester-1 back to Q1 next year. PTTEP is currently using the Ensco-109 for its Montara field redevelopment project in 100%-held AC-L-7 in the Vulcan Sub-basin. Montara infamously suffered a blowout and fire, destroying the platform and rig above it, in August 2009. PTTEP is now working to restore production to 35,000bbl/day from the field. Octanex has been advised that PTTEP requires further time to complete Montara development drilling, and so instead of a Q4 2012 spud Winchester has been pushed back into Q1 2013. As Oil & Gas Insider understands it, Santos will be second in the queue to take the Ensco-109 after PTTEP is finished with it behind Eni, which – along with JV partner ASX-listed MEO Australia - is planning to drill a couple of wells in the NT-P-68 permit starting with Heron-3. The other well Octanex will be involved in, albeit in an indirect manner, is Palta-1 in Exmouth Sub-basin WA-385-P. This week the 783km 2D Tortilla seismic survey was completed by operator Shell, fulfilling the final work commitment for WA-385-P in the current term. Palta-1 is an LNG-sized prospect that Shell intends to drill in Q3 this year. Octanex originally held full interests in WA-384-P, WA-385-P and WA-394-P before assigning them over 100% to Shell while retaining a “1% royalty over any production from the permits, as well as rights of reconveyance”. Noble Corp’s deepwater rig Noble Clyde Boudreaux is due into Australia for Shell around

October with Palta-1 on its drilling schedule. Even if Palta-1 is first well off the block for the floater, however, Q3 may be a bit too much of an optimistic time frame to get this big gas prospect started. Apr 3: The next move in the chess game for control of Central Petroleum was made on Tuesday with the under-siege board reporting of a “Purported Requisition Of Meeting”. In the announcement to the ASX, where the words “purported” and “claiming” are significant, Central says it has now received a request for a general meeting “from shareholders claiming to hold 10.14% of the Company’s shares”. The meeting is aimed at replacing three of

Central’s directors - chairman Dr. Henry Askin, and NEDs Richard Faull and William Dunmore - with Peter Cockcroft, Colin Goodall and Simon Philis. This latest intelligence follows a release last Wednesday, put out when the company “became aware of certain public statements made”, in which the company said it had not received a requisition for exactly this purpose. Only one of the proposed replacement directors’ names was different in last Wednesday’s refutation. Instead of John Jetter being put forward we now learn it will be Simon Philis – a replacement replacement director. Central this week also confirms what the market rumour mill had been suggesting for a couple of weeks now, that “Mr. John Phillip Heugh, a Non-Executive Director of the Company is one of the shareholders requisitioning the meeting”.


Contact Phil Byrne Chief Executive Officer Nido Petroleum Tel: (08) 9474 0000 Fax: (08) 9474 0099 Gregor McNab Chief Executive Officer Otto Energy Tel: (08) 6467 8800

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In fact such is the level of information already out there in Daytrader Land about this “purported” putsch, that it’s difficult to separate whether the big rise in share price since rumours about it first started is due to the fact that Heugh was sacked as M/D, or because those in the know were aware he was leading a move to overthrow the rest of the board. Since 28 March Central’s (CTP) shares have risen from $0.076 to trade as high as $0.11 briefly on 30 March before a trading halt was placed on the shares at $0.105. By the way, the latest one doing the rounds is that Clive Palmer’s buying into Central. Meanwhile Central’s directors are “currently in the process of determining that the requisition is made in compliance with the relevant provisions of the Corporations Act”, and if it is will “undertake the necessary steps to convene a general meeting in compliance with the Corporations Act”.

Other Announcements Coretrack: Mar 29: $2.5M REALISED - OVERSEAS OILFIELD ASSETS STILL TO GO UNDER THE HAMMER Coretrack Limited (“Coretrack”) (ASX:CKK), with the assistance of Ross’s Auctions, has completed the auction of its saleable assets, realising approximately $2.5 million. Approximately 200 people attended the auction on the day at Coretrack’s Bibra Lake facility. Interest remained high from 10a.m when the auction kicked off, until the last lot went under the hammer in the early evening. The Coretrack overseas oilfield assets are expected to be liquidated in April. In addition, Coretrack continues to reduce its operating costs, the Bibra Lake facility will be vacated in the coming months and personnel will be further reduced as the team at Coretrack focuses on the Core Level Recording System (CLRS).

Exoma Energy: Mar 29: Exoma to Drill Large Gas and Oil Targets in Extensive 2012 Exploration Program HIGHLIGHTS: Up to 22 wells in 2012. Drilling program expected to begin in April targeting:

Coal Seam Gas 31 TCF in 7 Prospects; Conventional Oil in Place 80-280 MMBO at

Katherine Prospects; Shale Oil & Gas Prospects to be tested over

20,000km² Exoma Energy Limited (ASX: EXE) is pleased to announce a planned 2012 exploration drilling campaign of up to 22 wells which is scheduled to begin next month in Central Queensland. The Galilee Joint Venture (Exoma 50%, CNOOC Gas & Power 50%) has agreed to an extensive exploration program across its five permits covering over 27,000 km² within the Galilee Basin in 2012 (see attached map). To achieve this, Exoma has contracted Ausdrill (ASX Code: ASL) to provide a rig and drilling services to carry out part of the 2012 drilling program. The rig is presently being commissioned at Ausdrill’s Toowoomba yard. Negotiations for a second rig for the 2012 program are well advanced with mobilisation into the field of the first rig planned for April, subject to weather and land access considerations. Exoma and CNOOC’s 7 well exploration program in 2011 confirmed the existence of three separate hydrocarbon systems: Coal Seam Gas, Conventional Oil, Shale Oil and Gas within the Joint Venture permits. The 2012 exploration program will systematically appraise each of these potential resources in more detail. Exoma’s programs are therefore designed to deliver a strategic understanding of the basin geology with the objective of defining the most favourable areas in which to develop reserves. Coal Seam Gas Initially, the main focus of the CSG is contained within the Permian Betts Creek and Aramac coal measures. These coals cover approximately 12,000 km² of the Joint Venture acreage and represent a potentially strategic gas resource. Exoma’s objectives in 2012 are to continue to measure and map the distribution of gas within the coal and to identify production ‘sweet spots’ for long term testing in 2013. The 2012 CSG program is targeting 31 trillion cubic feet (TCF) of potential resource in 7 independent prospect areas and aims to provide the technical basis to convert resource into reserves during 2013. Exoma expects to drill and test up to 13 CSG core wells in these prospect areas during 2012. These wells will also provide data on the Toolebuc shale formation within the permit areas. Conventional Oil The Katherine-1 well, drilled in 2011 as an extension to a Toolebuc shale core test, discovered oil in the Hutton and Adori sandstones. This well confirmed that a stratigraphic trap model is a valid play in the Hutton sandstone and structural trapping is a valid play in the Adori sandstones. Based on independent log analysis, Exoma has identified a potential oil resource of some 80 million barrels of oil (MMBO) in the Katherine West structure. In addition, Katherine East, an adjacent structural trap identified from seismic, holds potential Oil on Place of up to 200 MMBO.


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Contact Bernie Kelly CEO Coretrack Limited Tel: (08)9410 9600 Fax: (08)9410 9601

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Exoma’s objectives in 2012 are to test the two oil prospects and establish the technical and commercial basis for development and production. At Katherine West the plan is to cut a core through the Hutton and Adori reservoir section and conduct drill stem tests. In the event that this well confirms the presence of recoverable oil, Exoma plans to then drill the Katherine East structure. The aim of the 2012/13 program is to obtain independently certified oil reserves, which will provide the basis for appraisal and development decisions in 2013. Exoma has also identified a number of independent oil prospects that will be reviewed against the results of the 2012 conventional oil program. Shale Oil and Gas The 2011 exploration program confirmed the Toolebuc shale as a potentially world-scale oil and gas resource. These shales cover approximately 20,000 km² of the Joint Venture acreage. Independent analysis of the core recovered in 2011 shows that the shale has excellent generative potential. The Toolebuc shale has a very high organic content and testing shows that part of the organic material (the kerogen) has generated liquid and gaseous hydrocarbons. Samples of liquids and wet gas were recovered during drilling and in laboratory testing. The results from the core wells drilled at the Bessies-1, Euston-1 and Katherine-1 locations show that the shale has generated significant quantities of hydrocarbons. Samples of liquids and wet gas were recovered during drilling and in laboratory testing. Based on the laboratory results, Exoma estimates the following ydrocarbons in place at the Bessies location: Oil-in-Place (mmstb/km²) Gas-in-Place (bcf/km²) 0.2 to 4.5 (ave 2.2) 2.9 to 6.4 (ave. 4.0) The Joint Venture is analysing the complex geological and geochemical data obtained in 2011 in order to characterise the shale, understand how the shale hydrocarbon system works and to identify ‘sweet spots’ for production testing and to assess recoverability. The 2012 program is designed to collect further shale geological and geochemical data across the five permit areas. The Joint Venture plans to drill and core 7 shale exploration wells in ATP-999-P, ATP-1005-P and ATP-1008-P, with this program aimed at measuring the regional distribution of the many factors that are known to influence petroleum shale productivity. In ATP-991-P and ATP-996-P, CSG exploration wells will intersect and sample the Toolebuc shale as they are drilled through to the underlying Permian coal measures. Samples of shale will be recovered from these CSG wells and the shale section will be geophysically logged. Project Team Exoma has recently appointed a number of senior industry professionals to support this accelerated exploration program. In particular, the Company has been pleased to welcome Vic Palanyk as General Manager Subsurface and Andrew Saville as Safety Manager. In addition to these appointments, Exoma has concluded the appointment of a number of secondees from CNOOC Gas & Power in a range of technical, operational and commercial positions. This will provide valuable access to the CNOOC Group technical resources and capabilities.

Exoma Chairman, Brian Barker, said: “Last year we consolidated our technical knowledge of the Galilee Basin CSG, demonstrated that the Toolebuc is a highly prospective shale oil and gas resource and established a stratigraphic play for conventional oil. Given the large size of the Joint Venture acreage, these accomplishments create really significant value. We will build off these successes in 2012 with follow-up exploration designed to position the company to start booking reserves in 2013. Exoma is operating an aggressive exploration program in 2012. Our program funding is secured by the farmin by CNOOC and our cash reserves.” Exoma has a 50% beneficial interest in five ATP’s in the Galilee Basin covering approximately 27,000 km². CNOOC Galilee Gas Company Pty Ltd, a local subsidiary of leading Chinese integrated energy company China National Offshore Oil Corporation (“CNOOC”), is earning its participating interest via a farmin whereby CNOOC provide the initial $50 million of joint venture expenditures on Exoma’s five Galilee Basin ATP’s. Rawson Resources: Mar 29: Kea spuds Puka-1 Rawson Resources Limited (ASX: ‘RAW’) is pleased to advise that Kea Petroleum Plc. (‘Kea’) has released the attached announcement to the London Stock Exchange concerning the spudding of the Puka-1 well in the onshore Taranaki Basin. The location is shown on the map below.


Contact Rob Crook Chief Executive Officer Exoma Energy Tel: (07) 3226 5600 Email: [email protected]

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Rawson Taranaki Limited holds 27,307,692 shares in Kea Petroleum Ltd giving Rawson a 5.4% holding. Further information will be available from the Kea website. Rawson will issue further announcements of significance as they occur. MEO Australia: Mar 29: Tassie Shoal LNG project environmental approval updated Key Points: Tassie Shoal LNG project environmental approval

updated & extended for at least 5 years Environmental approval terms consistent with recently

sanctioned projects MEO Australia Limited (ASX: MEO; OTC: MEOAY) is pleased to advise that the Federal Government has updated the Timor Sea LNG Project environmental approval. Concurrent with this revision the Department confirmed that the approval will remain valid until at least 28th March 2017. The Federal Department of Sustainability, Environment, Water, Population and Communities reviewed the status of the environmental approval under the Environment Protection and Biodiversity Conservation Act 1999 (EPBC Act) and requested a revision to the terms of the approval to bring it into line with recent approval decisions. Several of the revisions are now standard features of current approvals and are primarily borne out of the Montara Incident and subsequent Inquiry. Other revisions reflect contemporary practice and provide greater guidance on the requirements for the construction, operations and oil spill plans which will form the basis of subsequent approvals required before project commencement. MEO’s CEO and MD Jürgen Hendrich commented on the announcement: “We are very pleased that the Government has revised the terms of the Tassie Shoal LNG project environmental approval and has given a clear, minimum five year extension. This initiative supports our efforts to commercialise this Project together with the Tassie Shoal Methanol Project and provides the clarity needed by prospective project partners to evaluate the projects.

Dart Energy: Mar 29: Dart Energy and Maria’s Farm Veggies win gas innovation award Dart Energy (ASX:DTE, “Dart”) together with Maria’s Farm Veggies Pty Ltd (MFV), have won the FutureGAS Innovation Award for 2012. The award is for the MFV combined heat and power glasshouse project that will produce vegetables and generate electricity. The project is a model of sustainability that demonstrates that coal seam gas (CSG) production can bring with it significant benefits to communities and the economy. Not only will this project produce food and electricity but in doing so it will have a much lower impact on the environment than conventional food and power production techniques. Project benefits include: Gas supply up to 6.3PJ over 10 years, based on an

~8MW combined heat and power plant; potential expansion to 32 MW.

10x food production compared to conventional techniques

Near zero CO2 emissions for power exported to the grid Beneficial re-use of CSG water +125 new jobs in stage 1 alone “We are very pleased to have won the award with Maria’s Farm Veggies and see that this project represents a highpoint of sustainable production solutions, whilst also offering attractive financial returns,” Robbert de Weijer, Dart Energy Australia CEO said today. “Through other CSG projects, Dart Energy is committed to providing gas to the domestic market in NSW which will help ease the pressure on households from rising gas and electricity prices,” Mr de Weijer said. Dart Energy will start work on its coal seam gas production pilot near Maria’s Farm Veggies once formal approvals have been received. FutureGAS is the annual gas conference organised by Gas Today magazine.


Contact John Doughty General Manager Rawson Resources Limited Tel: (02) 9255 7428

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Contact Jürgen Hendrich Managing Director & CEO MEO Australia Tel: (03) 9614 0430 Fax: (03) 9614 0660

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Contact John McGoldrick Chief Executive Officer Dart Energy Tel: +65 6508 9840

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Titan Energy: Mar 29: TITAN ENERGY FINALISES OVERSUBSCRIBED $2.33m FUNDRAISING FOR MULTI-WELL USA EXPLORATION PROGRAM HIGHLIGHTS: Applications received to raise $1,225,000 by

placement to sophisticated investors – significantly oversubscribed.

A further $1,112,500 to be raised from directors and sophisticated investors subject to shareholder approval.

US exploration programme now fully funded. Preparations well advanced on spudding of

Company’s first well in Franklin Prospect in Illinois. Multi-well drilling options also being studied in

Texas and Colorado. Australian oil and gas company Titan Energy Ltd (ASX: TTE) (Titan Energy or the Company) is pleased to announce it has received firm commitments from sophisticated investors to raise $1,225,000 by a placement of 98,000,000 fully paid ordinary shares in Titan Energy at an issue price of $0.0125 each. These shares will be issued from the Company’s current 15% placement capacity and will rank equally with the existing shares on issue. The shares will be issued on a date to be determined. The placement was managed by Pursuit Capital Pty Ltd and Pendulum Capital Pty Limited and was oversubscribed with scale backs required. Due to the strong interest received in the placement the Company has also received commitments for a further 49,000,000 fully paid ordinary shares at an issue price of $0.0125. The issue of these shares will be subject to shareholder approval at which time the Company will also seek shareholder approval for two directors of the Company, Mr Paul Garner and Mr Darren Levy, to each subscribe for 20,000,000 fully paid ordinary shares in Titan Energy at an issue price of $0.0125 each. The issue of these shares is on the same terms and conditions as the placement referred to above. These shares will rank equally with the existing shares on issue. The shares will be issued on a date to be determined. The Company will also seek shareholder approval for the issue of 8,580,000 free options as commission to the parties arranging the funding. The options will be exercisable at $0.015 and expire on 31 December 2012. These options will rank equally with the existing listed options on issue (ASX Code: TTEO) and will have the same terms and conditions. The options will be issued on a date to be determined. Funds raised from the all the above issues of securities will be applied to the Company’s exploration activities, administration costs and working capital. As a consequence of this raising, the first phase of Titan Energy’s proposed exploration program in the US is fully funded. This program may include: the upcoming Midyett #8-1 exploration well which the

Company is preparing to drill into the Franklin Prospect area of the Midyett South Development Project in Illinois (see ASX announcement 26 March 2012);

A potential multi-well programme in the historic, oil producing Allen Dome area in Texas, in which the Company is acquiring an 87.5% Working Interest (WI);

A potential 10 well programme at the Sodbuster Prospect in Logan County, Colorado, in which the Company is acquiring a 40% WI.

Titan Energy Managing Director, Stephen Thomas, said the Company was delighted with the strong response to the capital raising and to the new project acquisitions. “This is a strong vote of confidence in Titan Energy’s international expansion strategy. Importantly the Company is well funded with the capacity to finance a major, multi-well program across our three new project areas, which in turn has the potential to bring significant returns for shareholders in the near term.” Advent Energy: Mar 30: Advent Energy: EP-386 Permit Extension MEC Resources Ltd (ASX: MMR) investee company Advent Energy Ltd (“Advent Energy”) has advised of an extension on the permit terms of EP-386 in the onshore Bonaparte Basin, north-eastern Western Australia. Following application by Advent Energy through its wholly owned subsidiary Onshore Energy Pty Ltd, the WA Department of Mines & Petroleum granted a suspension of the condition requiring the completion of the Year 1 work by 31 March 2012 for a period of twelve (12) months to 31 March 2013. Advent Energy expects to conclude its production activities during the 2012 dry season and has commenced preparation for this activity. The extension application followed delayed approvals for production testing of the Waggon Creek-1 and Vienta-1 discoveries in EP-386 in 2011 and the early commencement of the northern wet season which prevented Advent Energy concluding its production testing programme as planned. In addition, the term of EP-386 has been extended for a period of twelve (12) months from 31 March 2016 to 31 March 2017.


Contact Stephen Thomas Managing Director Titan Energy Ltd Tel: (08) 9388 0944

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Contact David Breeze Executive Director MEC Resources Tel: (08) 9328 8477

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Lochard Energy: Mar 30: Re: Ithaca Energy reserves upgrade Lochard Energy Group Plc (“Lochard” or the “Company”) (AIM: LHD, ASX: LHD) notes the announcement made on 29 March 2012 by Ithaca Energy Inc relating to the increased reserves for the Athena project where Proved plus Probable reserves increased approximately 7% from 24.4 mmboe to 26.10 mmboe Gross (2.61 mmboe Net to Zeus) post drilling and completion of the wells on the field. Lochard has a net 10% interest in this field through its 100% ownership of Zeus Petroleum Limited. AWE: Mar 30: AWE completes BassGas sale Further to the ASX Release dated 8 December 2011, AWE Limited (“AWE”) is pleased to announce that the sale of an 11.25% interest in TAS-L-1 and a 2.75% interest in TAS-18-P in the Bass Basin to Toyota Tsusho Gas E&P Trefoil Pty Ltd (“Toyota Tsusho”) has been completed. Accordingly, AWE has received the cash consideration of $80.125 million from the sale. Further, working capital adjustments representing Toyota Tsusho’s net cash flows from the assets between the effective date of 1 November 2011 and the completion date will be settled by the parties in the June 2012 quarter. AWE looks forward to working with Toyota Tsusho and Origin Energy to successfully complete the major investment phase of the BassGas Mid Life Enhancement Project and to benefiting from the future long term production of gas and condensate from the project. The participants in the BassGas Project after completion of the transaction are:

The participants in T-18-P after completion of the transaction are: Senex Energy: Mar 30: Senex extends its successful oil appraisal program in the South Australian Cooper Basin Senex Energy Limited (Senex) and Beach Energy Limited (Beach) have agreed to add three more appraisal wells to their successful drilling campaign in the South Australian Cooper Basin, which will see the joint venture partners drill a total of 14 wells. The first new well in the expanded campaign is the Growler-10 oil appraisal well in PRL-15. This will be the sixth appraisal well to be drilled following five consecutive successes in recovering oil from the Jurassic Birkhead Formation at Growler oil field on the Cooper Basin’s western flank. Growler-10 spudded on 27 March 2012, with Ensign rig-48 currently setting surface casing after drilling to a depth of 658 metres at 6.00 am today. The well is expected to reach a total depth of 1,838 metres. In addition to Growler-10, Senex and Beach have agreed to drill two appraisal wells at the Snatcher oil field in PEL-111: Snatcher-4 and Snatcher-5. Senex Managing Director Ian Davies said the joint venture partners were excited about the prospect of resuming production at the Snatcher oil field, which has been offline since a one-in-forty year flood inundated the field in January 2010. “We recently regained access to Snatcher oil field following the completion of road works by Santos and the joint venture is looking forward to finally being able to restore production from this successful oil field in April” he said. Senex has constructed earthen causeways to the previously inundated Snatcher-1 and Snatcher-2 wells and is in the process of connecting both of these wells to a new production facility that is currently being constructed. In addition, the existing Snatcher-3 well, which was drilled and suspended for future production in 2009, will be completed and connected to the Snatcher facility for production.


Contact Haydn Gardner CEO Lochard Energy Group Plc Tel: (08) 9335 8848

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BassGas Project

Origin Energy (via subsidiaries)* 42.50

AWE Limited (via subsidiaries) 46.25

Toyota Tsusho Gas E&P Trefoil Pty Ltd 11.25

*operator

T-18-P

Origin Energy (via subsidiaries)* 39.00

AWE Limited (via subsidiaries) 44.75

Toyota Tsusho Gas E&P Trefoil Pty Ltd 11.25

*operator

Acer Energy Limited 5.00

Contact Bruce Clement Managing Director AWE Limited Tel: (02) 8912 8000

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Senex holds a 60% interest in PRL-15 and PEL-111 and is Operator of the joint ventures, with the remaining 40% interest held by Beach. Neon Energy: Mar 30: PALOMA DEEP TESTING UPDATE Highlights Encouraging new production test

of oil shale zone Lower Stevens/Fruitvale previously

tested at significant rates Paloma Deep #2 well to spud late

April 2012 Neon Energy Limited (ASX: NEN) is pleased to provide the following update regarding the ongoing production testing operations at its Paloma Deep discovery, located in the San Joaquin Basin, onshore California.

The Lower Antelope interval, a member of the prolific Monterey Shale Formation, has produced oil and gas during swabbing operations from an interval of naturally fractured interbedded chert, siliceous shale and sandstone. The unstimulated recovery of 35 barrels of 30° API gravity oil from this zone is significant in that these preliminary results are comparable to early results from a number of nearby fields which produce from the Monterey Shale (see figure below). The US Energy Information Administration(1) estimates that the California Monterey Shale play has potential for 15.4 billion barrels of technically recoverable oil, compared to the Bakken play’s 3.6 billion barrels and the Eagle Ford play’s 3.4 billion barrels. Based on historical production from the nearby fields the Monterey Shale may have potential to produce 10 to 30 bbls of oil per acre-foot(2). In the case of Neon’s estimated 366 foot gross (276 foot net) pay over its 2,847 gross acres, this may translate to 7.9 to 23.6 million barrels of recoverable oil, however additional drilling and production testing is required to confirm this estimate. Neon will also investigate whether modern stimulation techniques, coupled with horizontal development drilling, might accelerate recovery of oil from this zone. During the next few weeks the Company plans to pump-test the lower Antelope Shale oil zone in Paloma Deep #1 in order to determine commerciality.


Contact Ian Davies Managing Director Senex Energy Limited Tel: (07) 3837 9900

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Based on the encouraging results to date the Company is preparing to drill a follow-up well, to be drilled concurrent with ongoing testing operations at Paloma Deep #1. This second well is designed to evaluate the areal extent of the zones of interest, and to re-evaluate the Lower Stevens/Fruitvale section which previously produced at an unassisted rate of 1.9 MMcfd (million cubic feet per day) of gas and 226 bpd (barrels per day) of oil/condensate, prior to premature cessation of the test as a result of plugging of the test tool. Since the previous update Neon has also tested a shallower member of the Lower Stevens Formation, and while a small initial gas flow was observed it has now been determined that this zone is non-commercial at the well location. Neon Energy Managing Director, Ken Charsinsky commented “The Paloma Deep #1 well represents a significant milestone which could transform the resource base of the Company. We have now proven up two potential Monterey Oil Shale zones in the Fruitvale and the Lower Antelope, in addition to gas/condensate in the Lower Stevens zone. We are bringing forward the drilling of Paloma Deep #2, one month ahead of initial projections, and the well is expected to yield sufficient information to complete a reliable resource assessment.” The project is operated by Neon with a 75% working interest. Solimar Energy Limited (ASX: SGY) is participating with a 25% working interest, of which 12.5% is being earned through a Farmout Agreement under which Solimar is paying a promoted share of the dry hole and completion/testing costs of the Paloma Deep #1 well, up to an agreed cost cap. Further updates will be provided as the testing programme progresses. 1. US Energy Information Administration, July 2011

Review of Emerging Resources: US Shale Gas and Shale Oil Plays

2. After Louis J. Regan Jr., 1953, Fractured Shale Reservoirs of California, Bulletin of the AAPG

NOTE: Solimar Energy (SGY) also made a release on this topic

New Guinea Energy: Apr 2: TALISMAN-MITSUBISHI PNG STRATEGIC JOINT VENTURE: PPL-268 AND PPL-269 TRANSACTION DETAILS New Guinea Energy Ltd (NGE) refers to its announcement of 23 February 2012 regarding the news release by Talisman Energy Inc. (Talisman) of its strategic joint venture with Mitsubishi Corporation (Mitsubishi) to aggregate natural gas in the Western Province of PNG with a view to potential LNG export of approximately 3 million metric tonnes per annum. As part of that strategic joint venture, Talisman will assign to Mitsubishi interests in nine licences in PNG’s onshore Western Province. Of relevance to the licences in which NGE has a participating interest, Talisman has agreed to transfer to wholly-owned subsidiaries of Mitsubishi, named Diamond Gas Foreland 268 B.V. and Diamond Gas Foreland 269 B.V, a 20% participating interest in PPL-268 and a 20% participating interest in PPL-269. Talisman has advised that the arm’s length value of the consideration payable by Mitsubishi for these transfers is as follows: a. For 20% participating interest in respect of PPL-268,

US$5.18 million (US$259,000 per 1% participating interest acquired); and

b. For 20% participating interest in respect of PPL-269, US$25.7 million (US$1,285,000 per 1% participating interest acquired).

As noted in Talisman’s announcement, the effective date of the transaction is 1 January 2012. Upon the sale process being approved by the joint venture participants and relevant authorities, the resulting participants in PPL-268 and PPL-269 will be:


Contact Ken Charsinsky Managing Director Neon Energy Tel: (08) 9481 1176

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PPL-268

Engelberg Limited (an NGE subsidiary) 50.00 Talisman Niugini Pty Ltd 30.00

Diamond Gas Foreland 268 B.V. 20.00

PPL-269

Kirkland Limited (an NGE subsidiary) 50.00 Talisman Niugini Pty Ltd 30.00

Diamond Gas Foreland 269 B.V. 20.00

Contact Michael Arnett Executive Chairman New Guinea Energy Tel: (02) 9252 0010 Fax: (02) 9252 0039

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Challenger Energy: Apr 2: Well successfully cased and cemented – Frac slot secured Mercury Stetson well successfully cased and

cemented with 7” casing Frac program secured- commences in 3 weeks Initial Rockview processing of Baker Hughes Flex

log completed Logs confirm excellent shale properties across both

Barnett and Woodford shales Challenger Energy Ltd (“Challenger”) is pleased to announce that it has successfully cased and cemented a 7” casing string into the recently drilled hole, and is currently demobilising the drilling rig from location. Challenger has secured a Frac slot with Baker Hughes for the week commencing 23 April 2012 to expedite the first stage of testing on this exciting project. Frac Program The first stage of testing will include a single stage frac on the Woodford Shale, followed by flow testing of this formation. Challenger expects the initial flow testing of the Woodford to take between 2-4 weeks to complete. Recent log analysis suggests that this frac will be addressing 200 ft of highly organic, very porous and brittle shales equivalent to the best productive zones in adjacent basins. At the conclusion of this testing, a bridge plug will be set above the Woodford Shale, and a similar stimulation and testing completed on the Barnett Shale. Log analysis indicates that the Barnett Shale interval in the well contains 450 net feet of richly organic, porous and, brittle shale with characteristics equivalent to the productive zones in the Fort Worth Basin to the West. The company is evaluating the option of a two stage fracture stimulation in the Barnett given the thickness and attractive properties identified in the shale. Log results Challenger has received the initial results from the Flex log which was run across the shale intervals. This log determines the detailed mineralogy of the shales providing an excellent guide to their fracturing properties. The company is extremely encouraged by the results it has received which confirm: High TOC across the shale sequences consistent with

the highest expectations for both shales Very good porosity in both the shales Very brittle shale sequence with multiple perforation

targets Challenger is still waiting on the processing of the Formation Image Log (FMI) that has been run over the interval which will assist in understanding the natural fracturing and structure of the shale horizons and enclosing rocks. In commenting on the results Mr Paul Bilston the Managing Director of Challenger said: “We are excited with the outcome of this well to date. With a small team we have been the operator of a well safely drilled and cased to a depth of almost 3.5 km. The thicknesses and log characteristics of the shales are excellent and are consistent with a world class shale gas target. ” “We eagerly await the results of the fracture stimulation of these shales which will confirm the productive potential of this massive prospect.”

Prospect Overview. The Mercury Stetson Prospect contains two of the premier shale formations in the US – the Woodford and Barnett shales – in geological extensions of the core producing areas in the Arkoma and Fort Worth Basins. The key well on the Mercury Stetson Prospect was drilled in 1978 before the development of any of the shale gas plays in the US. It identified that both shales present in the well had the same log signatures, geochemical characteristics and thicknesses as those found in the core producing areas of both the Barnett and Woodford shales. Based on the technical information available from this well, the two shales are estimated to contain in excess of 360 BCF/sq mile of gas in place. Interpretation of the current seismic data suggests that the prospect area is ~ 55,000 acres (85 sq miles). The core objective of the testing program is to demonstrate that gas can be delivered to surface from both the Barnett and Woodford shales in the prospect area. This is the critical piece of information that will underpin the validity of the massive gas in place and commercial potential of the prospect area. Challenger Energy has agreed to farm in to earn 50% of the Mercury Stetson Prospect which includes the Barnett and Woodford shales - both proven shale formations. The prospect which is potentially up to 55,000 acres (86 sq miles) has a massive potential gas in place with OGIP estimated at 360 BCF/sq mile. The JV area initially includes 26,000 acres contiguous land position with three pipelines across prospect with an initial target of 35,000 acres across the prospect. Further updates will be provided in due course. Buccaneer Energy: Apr 2: ACQUISITION OF INTEREST IN COSMOPOLITAN PROJECT In early February 2012 Buccaneer Energy Limited (“Buccaneer” or “the Company”) advised that it was acquiring an interest in the Cosmopolitan Project (“Cosmo”). Cosmo was being jointly acquired with privately owned Fort Worth, Texas based BlueCrest Energy II, LP (“BlueCrest”) acquiring a 75% working interest, with Buccaneer acquiring a 25.0% working interest and assuming operatorship of the project. The parties have mutually agreed with the vendor Pioneer Natural Resources Alaska, Inc. to extend settlement of the acquisition until the 28 June 2012. Background Cosmo is an undeveloped oil and gas field located in 50 feet of water in the Cook Inlet of Alaska and is in close proximity to the shoreline at Anchor Point on the Kenai Peninsula. Cosmo has regional proximity to Buccaneer’s other Alaskan assets and will utilise the capabilities of the Endeavour rig during the northern hemisphere winter.


Contact Paul Bilston Managing Director Challenger Energy Tel: 0402 060 405

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The strong interest in the region, which contains the Cosmo project, is demonstrated by Apache Corporation acquiring leases surrounding and adjoining the leases near Cosmo during the last State lease sale conducted in June 2011. Reserves As part of its due diligence on Cosmo, Buccaneer and BlueCrest engaged respected consulting firm Ralph E Davis to conduct an independent reserve estimate on the project. The 2P Reserves of Cosmo increase Buccaneer’s independently assessed Alaskan 2P Reserves from 17.5 million barrels of oil equivalent (“MMBOE”) to 31.3 MMBOE. Cosmo Reserves Estimates

These Reserves estimates for the Cosmo project are supported by drilling, production testing and 3D seismic. Preliminary Development Plans Development of the Cosmo project involves two separate plans: A shallow gas development (3,000 – 4,000 feet) to be

drilled with a jack-up rig; and A deeper oil development (6,000 – 8,000 feet) that can

be exploited using directionally drilled wells from the shoreline.

An offshore well using the Endeavour jack-up rig is planned for late 2012 that will further quantify both the oil and gas zones of the project. Development of the Cosmo project will begin in the northern hemisphere winter of 2012 and continue through to 2014. The preliminary development plan includes drilling and producing oil wells from the existing onshore production site and drilling offshore water injection wells for reservoir pressure maintenance. Separately, offshore gas wells will be drilled and tied back to the existing onshore site which will be connected to ENSTAR’s recently completed gas transportation line. Increased Jack-Up Rig Utilisation Improves Economics The acquisition will allow the use of the Endeavour jack-up rig to provide a more efficient development plan than was previously available to Pioneer. Without access to a jack-up rig, all wells, including water injection wells needed to be drilled as long reach directional wells from onshore. Further, the shallower gas reserves could only be reached by an offshore drilling program that will utilise the Endeavour. Utilisation of the Endeavour jack-up rig materially improves the economic parameters of the overall project. The Cosmo project is located in the southern part of the Cook Inlet which is free of ice flows during winter. Cosmo will provide a winter operational location for the Endeavour jack-up rig to utilise the rig when ice flows in the northern part of the Cook Inlet preclude drilling during the November – March period.

This provides several years of winter drilling business and is expected to materially improve the profitability of the Company’s offshore drilling division which was previously based on a 240 day drilling season.

Nexus Energy: Apr 3: Lucio Della Martina appointed Nexus CEO The Board of Nexus Energy Limited (Nexus) has appointed Mr Lucio Della Martina as its Chief Executive Officer. Mr Della Martina will take up his appointment with Nexus mid-May and will be relocating from Perth to Melbourne. Following a short handover period, Executive Directors, Michael Fowler and

Ian Boserio will resume the positions of Non-executive Chairman and Non-executive Director respectively.

Mr Della Martina’s most recent position was Executive Vice President - Australia Business with Woodside Energy Ltd (Woodside) and he has led the Pluto project development since the field was discovered in 2005.

Mr Della Martina comes to Nexus with more than 20 years of experience across refining technology, international oil trading, gas business development, LNG marketing and LNG supply planning. He held various positions within Woodside including General Manager of Gas Business Development, General Manager of LNG Marketing and Vice President, ALNG (the marketing arm of the North West Shelf Venture). Mr Della Martina was employed by Shell from 1980 to 1991 in roles covering refining technology, operations, economics, planning and international oil trading.

The remuneration package for Mr Della Martina will include a market based salary, short-term and long-term incentives. In addition, Mr Della Martina will receive a sign-on fee comprising of ordinary shares and performance rights. The focus of the package is performance based, aimed at increasing shareholder value. The long-term incentive is based on market conditions immediately prior to the announcement.

Mr Della Martina commented, “Nexus Energy is in a very strong position to take its key assets forward towards development and has the opportunity to capture very substantial shareholder value along the way. I look forward to joining the team at Nexus.”

Nexus Chairman, Michael Fowler said “On behalf of the Board, I welcome Lucio to the Company and look forward to working with one of the recognised leaders of the Australian petroleum industry as we work to crystallise the value of our assets for shareholders.”


Contact Dean Gallegos Director Buccaneer Energy Limited Tel: (02) 9233 2520

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Contact Michael Fowler Chairman Nexus Energy Tel: (03) 9660 2500 Back to Index

Bass Strait Oil: Apr 3: BASS LIFTS INTEREST IN PEP-167 TO 100% Bass Strait Oil Company Ltd (ASX:BAS) advises that Interra Resources (Australia) Pte Ltd (IRA) has decided to withdraw from the joint venture in relation to PEP-167 between BAS and IRA. In accordance with the joint venture operating agreement, IRA served notice to BAS of its intention to withdraw from the PEP-167 Joint Venture effective 30th June 2012, and offered to assign its 50% participating interest in the PEP 167 Joint Venture to BAS. BAS has accepted IRA’s offer to withdraw and agreed to take assignment of IRA’s interest in the permit. This means that BAS will hold 100% interest in the permit. The relevant transfer documents have been submitted to the local authority for approval. PEP-167 expires 1st July 2012 and the permit has an option to renew for a further 5 years once 50% of the area is relinquished. BAS has determined that the permit is prospective for the Casterton oil shale play and the Waarre conventional gas play and will apply to renew the permit in its own right. The documents associated with the relinquishment and renewal have also been submitted to the local authority for approval. Key Petroleum: Apr 3: APPOINTMENT OF JOHN LLOYD KANE MARSHALL AS MANAGING DIRECTOR OF KEY PETROLEUM LIMITED The Board of Key Petroleum Limited is pleased to announce the appointment of Mr John Lloyd Kane Marshall as Managing Director of Key Petroleum Limited and its subsidiary companies. Mr Marshall was appointed to the position of Chief Executive Officer in early February 2012 and since that time has actively reviewed the Company’s projects and has provided a focus on pursing new ventures. Mr Marshall holds a Bachelor of Science (Petroleum Geology), a Bachelor of Commerce (Investment Finance and Corporate Finance) and a Masters in Petroleum Engineering. The Directors of Key Petroleum Limited welcome Mr Marshall’s technical and business skills to the Board at a time when the Company is consolidating its current asset position and actively pursuing new opportunities.

Further, Mr John Sheppard has tendered his resignation as a director of the Company to concentrate on other business interests. The Board of Key Petroleum Limited would like to express its gratitude to Mr Sheppard for his contribution to the Company and wish him all the best for the future. Cooper Energy: Apr 3: HAMMAMET WEST 3 UPDATE: APPROVAL OF DRAGON OIL FARM-IN, DRILLING PREPARATION ON TRACK Cooper Energy Limited (ASX: COE) (“the Company” or “COE”) is pleased to advise that the Conditions Precedent enabling Dragon Oil Ltd to become a full participating member of the Bargou joint venture in Tunisia are now all satisfied following approval of the Dragon farm-in from the Tunisian Hydrocarbons Consultative Committee. Following the approval, the Bargou Joint Venture comprises Dragon Oil (LSE, ISE: DGO) 55%, Cooper Energy (ASX: COE) 30% and Jacka Resources (ASX: JKA) 15%. Operational Update – Hammamet West 3 (HW3) – Well services contract awarded Preparations for drilling of the Hammamet West-3 well in the Bargou permit have progressed consistent with the plan with CE Tunisia Bargou Ltd awarding a contract for Well Management Services to AGR Petroleum (ME) Ltd – Dubai. The scope of the contract includes planning and executing drilling operations and post well activity. Drilling of the Hammamet West-3 well is targeted to commence in Q4 2012. The Hammamet West-3 well will include a horizontal well using modern drilling techniques to increase the potential for the reservoir to flow at commercial rates. A fracture study for the Hammamet West-3 well is being undertaken to determine the optimum horizontal drilling path for the well. The fracture study will be a key input to the well basis of design.


Contact Dr Steve Mackie CEO Bass Strait Oil Tel: (03) 9927 3000 Fax: (03) 9614 6533

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Contact Kane Marshall Managing Director Key Petroleum Limited Tel: (08) 9389 2111 Fax: (08) 9389 2199

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Contact David Maxwell Managing Director Cooper Energy Limited Tel: (08) 9489 3777

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MEO Australia: Apr 3: Major Project Facilitation (MPF) Status renewed for Tassie Shoal Projects Key Points: MPF Status for Tassie Shoal LNG and Methanol

Projects renewed until 31st December 2015 MPF Status will assist in expediting any additional

project approvals in addition to the existing environmental approvals

MEO Australia Limited (ASX: MEO; OTC: MEOAY) is pleased to advise that the Minister for Infrastructure and Transport, the Hon Anthony Albanese MP has granted MPF Status for the Tassie Shoal gas processing projects until 31st December 2015. The MPF program provides a service to support a timely and efficient approvals process for the proposed developments. Through this service the Department of Infrastructure and Transport will ensure that: All information on government approvals processes is

provided; All relevant government processes are coordinated so

that, as far as possible, they occur simultaneously and without duplication;

The Australian Government responds promptly to issues relating to the projects raised by MEO Australia Limited and its subsidiaries; and

Assistance in identifying and accessing government programs is provided

More information regarding the MPF program is available on the program website at www.majorprojectfacilitation.gov.au. MEO’s CEO and MD Jürgen Hendrich commented on the announcement: “The Tassie Shoal Projects have the potential to provide substantial benefits to the Australian people via tax and PRRT revenue and export earnings. MPF status further supports our efforts to commercialise these Projects and sends a clear signal of Government. MEO acknowledges and is extremely grateful for this support.” Additional information regarding MEO’s Tassie Shoal Projects is included in the attached Business Overview flyers.

Westside: Apr 3: Meridian and Dawson Mine reach mutually beneficial legacy well agreement Key Points Meridian SeamGas has executed an agreement under

which the adjacent Dawson coal mine will gain early access to 0.8 km2 within a co-development area of the mining lease, while Meridian continues to drain gas from existing wells

Early access has been granted in exchange for a commitment to compensate Meridian SeamGas for any loss of production revenue from five associated wells, for a period of two years, should production be adversely affected

The Meridian SeamGas project¡¦s certified gas reserves will be unaffected because the area concerned has never been included for reserves assessment.

As Operator of the Meridian SeamGas CSG gas fields, WestSide Corporation Ltd (ASX Code: WCL) advises that the Meridian SeamGas joint venture and the owners of the adjacent Dawson coal mine (the "Coal Party") have signed an agreement to optimise management of five well-sets located within a co-development area of the mining lease. Meridian SeamGas has the right, under a Co-Development Agreement with the Coal Party, to extract gas from specific areas of the mining lease prior to the expansion of mining into those areas. Under this new agreement the Coal Party will be granted access to a 0.8 km2 of the co-development area 12 months earlier than would otherwise be the case. In return for gaining expedited access the Coal Party has committed to fully compensate Meridian SeamGas for any loss of production from the five wells at agreed gas prices, for a period of two years, should production be adversely affected. WestSide CEO Dr Julie Beeby said Meridian SeamGas was producing gas from five legacy wells drilled within seams beyond its reserve boundary and would now seal off the non-producing ends of the lateral wells so mining operations could expand into this area immediately. “The methane drained from this area of the mining lease has always contributed upside to Meridian SeamGas as it has been coming from wells the mine drilled some years ago,” Dr Beeby said. “This new agreement means that we will be compensated for any loss of revenue from these wells for the next two years if production is impacted by the sealing of the lateral well heads, or the mine’s subsequent activities affect production.” The compensation arrangements recognise the fact that the lateral sections of these wells will no longer be accessible for work overs once their well heads have been sealed. Under this new arrangement Meridian SeamGas will gain at least 12 months of additional production revenue at a rate of approximately 2 Terajoules a day from wells which, under the terms of the Co-Development Agreement, would otherwise have had to be decommissioned within 12 months. The Coal Party will meet the initial cost of sealing the lateral ends of the wells, which potentially could continue to produce gas for extraction via the remaining vertical well sections beyond the two-year compensation period.


Contact Jürgen Hendrich Managing Director & CEO MEO Australia Tel: (03) 9614 0430 Fax: (03) 9614 0660

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Dr Beeby said the Meridian SeamGas project’s certified gas reserves would not be affected by this new arrangement because the area concerned had never been included for reserves assessment. “By working together in this way, the coal and gas parties have jointly ensured optimal recovery of both coal and gas resources for the benefit of all stakeholders,” Dr Beeby said. Quest Petroleum: Apr 3: DRILLING PROGRAMME IN JAYA SUB-BASIN, SOUTH SUMATRA BROUGHT FORWARD AND NEW BOARD AND MANAGEMENT APPOINTMENTS Highlights 3 high priority leads planned to be drilled in calendar 2012 Initial target to be the Komering Lead with target

potential of 340 Bcf gas High profile addition to the Quest board with appointment

of highly regarded Indonesian oil and gas identity (Mochamad Thamrin) Deputy Chairman of Quest and

Technical Adviser to Prabu Energy Activity Update The Company has recently appointed a project manager Mr. Rusdiyo Harjodarsono based in Indonesia to manage the exploration program. The Joint Study prioritised 3 high priority leads located within the Jaya sub-basin . A review of the existing data has confirmed the Company’s intention to commence drilling prior to June 30, 2012. Quest has commenced discussions with drilling contractors and expects to negotiate and sign a 650HP or 750HP onshore drilling rig to be deployed in the Ranua area by June 2012. It is expected that Quest will contract for a 3 well programme aimed at testing the Komering Lead plus the Sawat and Tabat leads. Board Appointments Quest Petroleum NL (Company) is pleased to announce the appointment of Mr.Mochamad Thamrin as Deputy Chairman of the Company and Senior Technical Advisor of its subsidiary PrabuEnergy Pty Ltd (PrabuEnergy). Mr.Thamrin is a leading industry professional with a deep knowledge of South Sumatra�fs petroleum geology. Mr Thamrin has over 45 years experience in the Indonesian oil and gas industry, including senior geological positions at PT. Shell Indonesia and as a production geologist with Indonesian government owned Pertamina , one of the largest oil and gas companies in the world. From 1976 to 1987 Mr Thamrin was Head of Geological Evaluation in the R&D Division at Pertamina.

Mr Thamrin was also Chairman of the Geology Department and Dean of the Mineral Technology Faculty at the University of Trisakti in Jakarta, from 1980 to 1994 and 1999 to 2011 respectively. Trisakti conducted the Ranau Joint Study with PrabuEnergy and BPMIGAS. Mr Thamrin is widely regarded as a leading expert in the Indonesian Oil and Gas field and has authored over 30 publications and text books on geology and related topics within this area. With such an extensive background in the Indonesian oil and gas industry, Mr Thamrin has developed enduring strategic relationships with all key stakeholders in the industry and the Company believes this, in addition to his vast knowledge of petroleum geology in the region, will be invaluable in executing the exploration programme at the Ranau projects. Quest Chairman Mr. Gus Simpson stated “We are delighted to appoint Mr Thamrin to the Board of Quest and also as technical advisor to our operating subsidiary PrabuEnergy. We also welcome Mr. Rusdiyo Harjodarsono into the team. Both Mr Thamrin and Mr. Harjodarsono's significant experience and the relationships they have developed within the Indonesian oil and gas industry will be an important asset as the Company advances its exploration programme at the Ranau Projects”. Empire Oil and Gas’s Perth Basin Permits and the Red Gully Development Presentation can be found here. Oil Search Investor Field Trip presentation is available here. MEO Global LNG Summit Presentation is available here. Tangiers Petroleum’s Milligans Formation Oil Play release is available here.


Contact Dr Julie Beeby Chief Executive Officer WestSide Corporation Ltd Tel: (07) 3020 0900

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Contact John (Gus) Simpson Chairman Quest Petroleum Tel: (08) 9380 9920

http://www.asx.com.au/asxpdf/20120329/pdf/425bb69tz67zcc.pdf

http://www.oilsearch.com/Media/docs/1203%20Investor%20Field%20Trip-188b7087-46f1-45c0-8c39-0fb8d1c4d618-0.pdf

http://www.meoaustralia.com.au/page/Home/Latest_Releases/Global_LNG_Summit_Presentation_29_March_2012/

http://clients2.weblink.com.au/clients/tangierspetroleum/article.asp?asx=TPT&view=6584424

Drilling Updates Taratu-1

Location PEP-38219

Equity

TD 378.8m. Suspending while analyses is being carried out.

L&M 100.00


International Drilling Updates

Gazelle-P3

Location Cote d’Ivoire

Equity

1070m. Mechanical problems with the rig equipment occurred and are currently being rectified by the drilling contractor.

Rialto

Midyett 8-1

Location Franklin County, Illinois

Equity

Spudded April 2nd.

Titan 81.00

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Mercury Stetson Prospect

Location USA

Equity

TD 3641m. C&S with a casing string.

Challenger Energy 50.00

Shepard’s Channel Prospect

Location LaFourche Parish, Louisiana

Equity

3878m. Commence operations to recover stuck pipe.

Target 15.33


WELL TICKETS BOREAS-1

WA-315-P Browse ConocoPhillips Transocean Legend 13-39-24.80 S 122-17-52.70 E

ConocoPhillips 60.00 Karoon 40.00

26-03-12 Due to spud ~Apr 6

PTD 5500m

GLENCOE-2 WA-390-P Carnarvon Hess Jack Bates 20-04-57.00 S 113-49-56.00 E

Hess 100.00

04-01-12 Re-commenced 24-01-12 Continuing 25-01-12 De-manning rig due to weather 01-02-12 Re-manning rig after cyclone, continue rig acceptance

PTD UNKNOWN

08-03-12 Continuing rig acceptance activities 15-03-12 Rig secured due to Cyclone Lua. Rig acceptance to continue once rig is re-manned 04-04-12 Continuing rig acceptance

MOONTA-1 PEL-218 Cooper

Beach Ensign Rig-916

27-45-02.09 S 140-51-50.05 E

Beach 100.00

23-01-12 Spudded 01-02-12 1979m and DA in Wallumbilla formation 01-03-12 Continuing

PTD 3800m

07-03-12 2924m wait on weather to re-establish access to site 22-03-12 Waiting on weather 04-04-12 Continuing

MARSDEN-1 PEL-95 Cooper


28-34-33.55 S 140-35-41.19 E

Beach 50.00

Strike 50.00

22-02-12 Spudded 01-03-12 Continuing 07-03-12 1908m wait on weather to re-establish access to site

PTD 2640m

04-04-12 Waiting on weather to re-gain location access

HASLAM-1 PEL-106B Cooper


28-01-45.56 S 139-40-44.19 E

Beach 50.00

Drillsearch 50.00

20-03-12 Spudded 04-04-12 Continuing

PTD 2828m

GROWLER-10 PRL-15 Cooper

Senex Ensign Rig-948

Unavail Unavail

Senex 60.00

Beach 40.00

27-03-12 Spudded 30-03-12 658m and DA after setting surface casing

PTD 1838m

NORTON-1 WA-36-R Exmouth Woodside Ocean America 21-32-12.00 S 113-52-30.00 E

Woodside 60.00 Mitsui 40.00

27-02-12 Spudded 15-03-12 Continuing, waiting on weather (Cyclone Lua)

PTD 1700m

04-04-12 Continuing

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WELL TICKETS

SASANOF-1 PEL-516 Cooper

Senex MB Century Rig-3

28-21-38.32 S 140-19-49.44 E

Senex 100.00

04-01-12 Spudded 06-01-12 850m and setting surface casing

09-02-12 2560m and DA 15-02-12 2711m and DA

200m of core samples collected, with 13 cores taken for desorption and testing from the Toolachee, Roseneath, Murteree and Patchawarra formations

PTD 3200m

19-01-12 2198m run 7” casing prior to commencing coring work

23-02-11 Running core 11 04-03-12 Rig evacuated by helicopter due to weather, with roads closed due to flood waters 20-03-12 Waiting on weather 22-03-12 Resume drilling 28-03-12 TD 3102m prepare to log ahead of casing for fraccing 04-04-12 TD 3102m logging ahead of casing

P’NYANG SOUTH-1 PRL-3 Papuan

ExxonMobil Oil Search Rig-103

05-33-11.00 S (approx) 141-34-53.00 E

(approx) ExxonMobil 49.00

Oil Search 38.50

29-01-12 Spudded 02-02-12 366m and DA in 17-1/2” hole 09-02-12 871m and DA in 12-1/4” hole

PTD UNKNOWN

JX Nippon 12.50

16-02-12 1205m and DA in 12-1/4” hole 23-02-12 1788m and DA in 8-1/2” hole 01-03-12 1991m prepare to run 7” liner 08-03-12 2427m and DA in 6” hole

15-03-12 2508m prepare to plug well before initiating sidetrack

29-03-12 2182m and DA in 12-1/4” hole 22-03-12 1628m and DA in 12-1/4” hole

TRICERATOPS-2 PPL-237 Papuan

InterOil InterOil Rig-2

06-58-37.66 S 144-46-36.50 E

InterOil 100.00

17-01-12 Spudded 23-01-12 120m running 18-5/8” casing

05-03-12 1231m and DA in 12-1/4” hole 22-03-12 Continuing

Since intersecting the carbonate reservoir to current TD, background gas and persistent mud losses of between 5-40bbls per hour have been encountered

PTD 2300m

02-02-12 516m and DA in 17-1/2” hole

at 1253m 02-04-12 1366m and DA in 8-1/2” hole after setting 9-5/8” casing

TALLAGANDA-1 WA-351-P Carnarvon BHP Billiton Atwood Eagle 20-52-30.00 S 113-44-36.00 E

BHP Billiton 55.00 Apache 25.00

01-03-12 Spudded 07-03-12 2070m in 17-1/2” hole with surface casing run and

PTD 3109m

Tap 20.00

cemented. Testing BOP’s 14-03-12 2070m BOPs tested, rig secured and de-manned for Cyclone Lua 21-03-12 2070m install BOPs and DA in 12-1/4” hole 28-03-12 3329m and DA in 12-1/4” hole

ahead of resumption of drilling in 12-1/4” hole to TD 04-04-12 3955m and coring ahead in the Mungaroo formation

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