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EditorPaul [email protected](t) 08 9272 6555

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

Tel 08 9272 6555 Fax 08 9272 5556 [email protected]

IN THIS ISSUE

Rig Schedule

Seismic Schedule

Commentary

News In Brief

Other Announcements

Drilling Updates

Well Tickets

oil & gas insider

Thursday, 26 April 2012

P U B L I C AT I O N S

Current Drilling Activity

1 P’Nyang South-1 8 Moreys-1

2 Thistle 9 Davenport-1

3 Triceratops-2 10 Vucko-1

4 Ketu-2 11 Glencoe-2

5 Tigercat-2 12 Moonta-1

6 Talaq-1 13 Southend-1

7 Boreas-1

IN THIS ISSUE

Cooper to expand

onshore presence via tie-up with Somerton

Apr 19: A new rationalisation push at the junior end of the oil and gas sector may be starting to emerge, but in comparison to the recent spate of reported small cap stoushes - most involving some form of management conflict or boards versus disgruntled shareholders - this particular play is likely to be a very clean G-rated event...

Empire announces postponement

of seismic, and meeting Apr 19 & 24: Again, what could be construed to be an event of moderate significance has occurred relating to northern Perth Basin permits EP-368 and EP-426, and again, Origin has not seen fit to inform the ASX of the latest developments...

Humble Beach casually reports gas find of significance

Apr 20 & 24: Beach continues its rich vein of form in the Cooper shale exploration game. Without much by way of flag waving or fist pumping, Beach announces its latest successful exploration outcome in its steadily building basin-centred shale gas program, into a relatively neutral overall market...

Tap not content to miss out on WA shale

stampede Apr 24: With Buru’s recent roaring success in confirming wet gas discoveries of significance at Valhalla-2 and Yulleroo-2 in the Canning Basin , everyth ing and everyone seems to be heading towards ‘unconventional’ in WA’s north, with primarily offshore player Tap seeing the light this week to vie for a slice of the future spoils of the onshore market...

News In Brief Origin

Other Announcements Sun

Maverick Solimar Molopo

Buccaneer Jupiter

Hawkley Titan

Marion New Standard

oil & gas insider


ASX 200 ASX 200 Energy

4,200

4,250

4,300

4,350

4,400

26-M

ar-1

2

31-M

ar-1

2

05-A

pr-1

2

10-A

pr-1

2

15-A

pr-1

2

20-A

pr-1

2 13,500

13,750

14,000

14,250

14,500

27-M

ar-1

2

01-A

pr-1

2

06-A

pr-1

2

11-A

pr-1

2

16-A

pr-1

2

21-A

pr-1

2

oil & gas insider


Onshore Rig Schedule 1 15 16 30 1 15

MB Century Rig-3

Senex

MB Century Rig-7

Buru

MB Century Rig-14

ConocoPhillips

ADS Rig-2

Oil Basins

Ensign Rig-918

PetroFrontier

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

Lakes

InterOil Rig-2

InterOil

Weatherford Rig-100

Geodynamics

Weatherford Rig-826

BG/QGC

Beach

Ongoing Santos (Fairview area)

May June

Tasmania-1

Ongoing Santos

Ongoing Santos

Stacked

Available

Backreef-1 testing

Ongoing Santos

Moonta-1

Habanero-4

Talaq-1

Ketu-2

Yulleroo-3

Tigercat-2

Davenport-1

Streaky-1

Moreys-1

Southend-1

Kruger-1

Paradise Deep-1

Mobilising

Boston-1

Riley-1

Stanley-3

Unavailable Darwin

Snatcher-4

Triceratops-2

Cook-22

Charo-13

Holdgate-1

Skipton-1

Mobilising

MacIntyre-2H Mobilising

Butlers/Christies Dev wells

Snatcher-5

Mobilising

Mobilising

oil & gas insider


Offshore Rig Schedule

1 15 16 31 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)

May

Montara Dev (5 wells, until Q1 2013)

Boreas-1

Jabiru/Challis dev

June

Thistle-1

Jansz Dev (10 wells)

Vucko-1

Glencoe-2

Bambra-10 tri-lateral

Stickle-8H4

Ongoing Chevron

Maple-2

Geographe Dev (2)

Bravo-1

Ravensworth-8H6

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

OMV Polarcus PMP-38160 Mar 28 254km2 3D completed on

Apr 16 - Alima Taranaki

TGS Fugro WA-365-P, WA-1-R ~Apr 10 450km2 3D continuing

Mary Rose NE extension Geo Atlantic Carnarvon

Chevron PGS WA-455-P, WA-456-P Apr 10 300km2 3D completed on

Apr 19 Osprey 3D Ramform Explorer Carnarvon

Fugro Fugro WA-435-P, WA-436-P, WA-443-P Apr 23 75% of 4246km2 3D

suspended for completion Zeester MC3D Geo Atlantic Canning

Oil Search CGGVeritas PPL-244, PPL-276 ~Apr 16 1000km2 3D underway

- Amadeus Papuan

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 2H 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 Apr 2226km 2D scheduled

- Orient Explorer Gulf of Carpentaria

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

Curt 3D Alima Rowley Sub

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

- Dampier

Geoscience Aust Uncontracted - May-Sep 200km2-3D scheduled

Vlaming CO2 3D Vlaming Sub

PTTEP PGS AC-RL-7, AC-RL-7, AC-P-54 Late May 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 June 3700km long offset 2D

scheduled Duvalia MC2D Aquila Explorer (outer Exmouth Sub)

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 ~Apr 23 800-1000km2 3D program

resuming Aurora MC3D (resumption) Ramform Explorer Browse

Woodside Uncontracted WA-447-P, WA-449-P Q4 2900km2 3D scheduled

Admiral 3D Browse

Woodside Fugro WA-275-P Early May 660km2 3D scheduled

Rafter 3D Geo Atlantic Browse

oil & gas insider


CLIENT CONTRACTOR WHERE WHEN STATUS Survey Name Vessel Basin

PLANNED

PetroFrontier Terrex EP-104 Q3 800km 2D scheduled

Owen 2D Crew 401 Georgina

Drillsearch WesternGeco ATP-940-P Mid May 1050km2 3D scheduled

- Crew 1160 Cooper

BG/QGC Terrex - 2H 250km 2D scheduled

Sark 2D Crew 405 Surat

Holloman Terrex PEL-112 Nov 125km2 3D scheduled

- Crew 402 Cooper

UIL Uncontracted EP-447 Feb 2013 ~200km 3D scheduled

Badgnigarra 2D - Perth

Armour Energy Geokinetics EP-171 Late Apr 67km 2D scheduled

- Crew 486 McArthur

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

- East Coast

Empire Uncontracted EP-389 2013 90km2 scheduled

Heliseis Perth

Origin WesternGeco EP-368, EP-426 Q1 2013 100km2 3D scheduled

North Erregulla 3D Perth

Senex Terrex PEL-88, PEL-95, PEL-514 May 12 790km2 3D scheduled

Cordillo 3D Crew 403 Cooper

Drillsearch WesternGeco ATP-539-P, ATP-549-P Late Apr 260km2 3D scheduled

- Crew 1160 Eromanga

BG/QGC Terrex - 2H 367km 2D scheduled

Middlemount 2D Crew 405 Surat

Santos Terrex ATP-752-P Late Jun 400km2 3D scheduled

Greater Leleptian Crew 402 Surat Bowen

Metgasco Terrex PEL-13 Late Aug 35km 2D scheduled

2012 MET 2D Crew 404 Gunnedah

Origin Geokinetics PL-226 Late May 228km2 3D scheduled

Dalwogan 3D Crew 488 Surat

Origin Geokinetics - Mid May 45km2 3D scheduled

Farawell 3D Crew 488 Surat

Santos Terrex PL-148 Mid Apr 70km 2D completed early Apr

Tonto 2D Crew 402 Surat

Larus Energy Uncontracted PPL-326 ~Sep 1100km 2D scheduled

- Papuan

Current & Planned Onshore Seismic

CLIENT CONTRACTOR WHERE WHEN STATUS

Survey Name Vessel Basin

CURRENT

Santos Terrex PL-148, ATP-259-P Jan 31 70% of 399km2 3D on Apr 19

Scarabwhanto 3D Crew 402 Surat

Origin WesternGeco EP-320, L-1, L-2 Feb 16 63% of 450km2 3D. Suspended on

Apr 10 Redback/Irwin 3D Crew 1160 Perth

Beach Terrex ATP-855-P Feb 18 420km 2D completed on Apr 11

Gallus 2D Crew 404 Cooper

Beach Terrex PEL-92 Mar 23 54% of 197km2 3D on Apr 19

Ricon 3D Crew 403 Cooper

Beach Terrex PEP-168 Apr 11 35% of 50km2 3D 3D on Apr 19

Nungamia 3D Crew 407 Otway

NZEC Webster Drilling PEP-51151 Early Apr 100km2 3D continuing

Alton 3D Taranaki

Cooper to expand onshore presence via tie-up with Somerton

Apr 19: A new rationalisation push at the junior end of the oil and gas sector may be starting to emerge, but in comparison to the recent spate of reported small cap stoushes - most involving some form of management conflict or boards versus disgruntled shareholders - this particular play is likely to be a very clean G-rated event. One of the companies once at the centre of some of the aforementioned incidents of inner turmoil, Cooper Energy, is also the protagonist in this latest friendly play. The move by Cooper will see it merge with ASX-listed, majority Beach-owned subsidiary Somerton Energy, which has most of its portfolio based around operated and non-operated exploration assets in the onshore Otway Basin, a region in which Cooper has been intent on expanding its presence. To join forces co-operatively with Somerton, Cooper will offer Somerton’s holders the choice between an all share (one Cooper share for every 2.8 Somerton shares held) and a share plus cash offer (one for 4.73 shares, plus $0.09 cash per share). Both offers work out relatively equal in valuing Somerton at around $31.5mil, with the all share alternative providing a value for each of Somerton’s shares at $0.218, and the shares plus cash option at $0.219, representing a 56% increase to Somerton’s Apr 18 closing price of $0.14. The last time Somerton traded as high as $0.17 was on Aug 16 2011, and since then, the trading range for the company has been $0.115 to $0.165. Cooper has an interest in just one Otway block currently, with a 50% free carried interest in a well in PEL-495, where partners Beach and Somerton plan to test the conventional 2500m Sawpit-2 oil prospect, considered to have potential for up to 4.2mil bbls oil in the lower Pretty Hill Formation sandstones plus shale gas potential in the deeper Casterton formation.

The merger with Somerton will greatly build Cooper’s position in similar shale prospective exploration assets in the Otway Basin. Somerton will deliver Cooper 33.33% in PEL-186 where operator Beach was planning a well late last year to test the Casterton formation and lower Otway Group shales, 20% in application PEP-150, 75% in PEP-151, 50% in PEP-168 where Beach recently completed the 100km Mactra 2D and is underway with the 50km2 Nungamia 3D, and 25% in the more recently acquired PEP-171. Cooper will also take on the 16.7% in Lakes’ Gippsland block PRL-2 that Somerton is working towards earning, operating in collaboration with primary funder Beach to spend up to $50mil on activity, including the fracture stimulation of existing wells, to jointly take 50% of the permit from Lakes. The Wombat tight gasfield has been estimated to house up to 787BCF of clean, low CO2 gas in place. Cooper’s pitch has obviously resonated more with Somerton’s board than the offer being worked up by Adelaide Energy around Aug last year, when a merger proposal between Adelaide and Somerton got to the point of “management level discussions”, but apparently unravelled before even making it as far as any sort of indicative ASX announcement. It should be smooth sailing for the two parties involved here, with a Merger Implementation Agreement entered into, and the full support of both boards, with Somerton’s directors and key shareholders committing the 19% of the company held between them as part of a pre-bid acceptance deal. Although Somerton’s non exec chairman, Robert Kennedy, has committed his Somerton stake to Cooper, he will abstain from making any recommendations on the deal due to his involvement as non exec chairman of Somerton’s biggest shareholder, Beach Energy. When the merger arrangement is finalised, Cooper will appoint Somerton’s managing director and former Beach CEO, Hector Gordon, as an executive director, and Beach will become Cooper’s biggest shareholder, with a stake of around 8.5% via its 56% holding in Somerton.

oil & gas insider Thursday, 26 April 2012

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Cooper has obviously been doing some things right of late in the eyes of its shareholders and the wider market, with the company now trading at four year highs at around $0.65. The last time Cooper traded over this price was in mid Apr 2008, before heading into the teeth of the GFC which took the company’s shares down to $0.20 over a period of around seven months. The recent share price strength has taken place since the appointment of former Woodside and QGC executive David Maxwell as Cooper’s managing director in Oct last year which, along with some other director resignations around the same time, helped defuse some of the tension between the company and a splinter group of shareholders. The shareholders, in support of Eddie Smith, had launched a boardroom tilt last Aug seeking to appoint Eddie Smith and James Crawford as directors at the expense of Greg Hancock, Stephen Abbott and Chris Porter. However the appointment of Maxwell, replacing former MD Michael Scott who resigned in July, and the subsequent resignations of the directors the Smith faction had sought to have removed, negated most of the need to call an EGM and took the wind out of their campaign. Cooper closed down $0.01 at $0.60 on volumes around 550,000 while Somerton closed up $0.06 at $0.20 (+2.4mil) on Apr 19. Somerton was trading steady at $0.205 on volumes around 676,000 while Cooper was steady at $0.615 (+601,000) earlier today. Cooper and Somerton announcement: COOPER ENERGY AND SOMERTON ENERGY MERGER Highlights Cooper and Somerton have agreed to merge via a

recommended off-market takeover bid under which Cooper will acquire all of the shares in Somerton.

Cooper and Somerton have entered into a MIA to progress the Offer.

The Offer represents a 56% premium to Somerton’s closing share price on 18 April 2012.

The Voting Directors of Somerton1 recommend that Somerton shareholders ACCEPT the Offer in the absence of a superior proposal.

All of the directors of Somerton, along with a number of Somerton shareholders have entered into pre-bid acceptance agreements in respect of 19% of Somerton’s issued shares.2

The merger is consistent with Cooper’s strategy to grow its presence in the Otway Basin and, along with existing assets and corporate activity, to build a well-funded production and exploration company focused on shareholder return.

Cooper and Somerton Merger The Boards of Cooper Energy Limited (ASX: COE) (“Cooper”) and Somerton Energy Limited (ASX: SNE) (“Somerton”) advise that they have agreed to merge via Cooper making a recommended off-market takeover bid (“Offer”) for all of the shares in Somerton. Cooper and Somerton have entered into a Merger Implementation Agreement (“MIA”) to progress the Offer. Offer terms Cooper will offer all Somerton shareholders the choice of either: a. one Cooper Share for every 2.8 Somerton Shares (“All

Shares Alternative”); or b. one Cooper Share for every 4.73 Somerton Shares plus

9 cents for each Somerton share (“Shares and Cash Alternative”).

1 Mr Robert Kennedy has abstained from making a recommendation due to being the non-executive Chairman of both Somerton and its largest shareholder Beach Energy Limited. 2 Notwithstanding note 1 above, Mr Robert Kennedy has entered into a pre-bid acceptance agreement in respect of all shares owned or controlled by him. Based on Cooper’s closing share price on 18 April 2012 of 61 cents, the All Shares Alternative is valued at 21.8 cents per Somerton share and the Shares and Cash Alternative is valued at 21.9 cents - valuing Somerton at around $31.5 million.3 The All Shares Alternative value of 21.8 cents represents a premium of: 56% to Somerton’s closing share price of 14.0 cents on

18 April 2012, being the last trading day prior to the announcement; and

46% to Somerton’s 30 day volume weighted average price of 15.0 cents.4

The Offer is to be subject to standard conditions as set out in Schedule 1 of this announcement, including a 90% minimum acceptance condition. Further details of the Offer will be provided in a Bidder’s Statement which is currently expected to be mailed to Somerton shareholders, along with the Target’s Statement, by mid May 2012. Greater Australian Focus The boards of both Cooper and Somerton believe there is a compelling strategic rationale for the merger. Combining the complementary assets and technical expertise of both companies together with Cooper’s strong cash balance and cash flow creates a focused oil and gas production and exploration company. The merged company will have a strong onshore Australia position in the Cooper, Otway and Gippsland basins (see attached maps). Strengthened Cooper Board Upon Cooper being entitled to commence compulsory acquisition of Somerton shares, Cooper will appoint Mr Hector Gordon (currently Managing Director of Somerton), as an Executive Director on the Cooper Board.


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Voting Directors of Somerton Recommend the Offer The Voting Directors of Somerton5 recommend that all Somerton shareholders ACCEPT the Offer in the absence of a superior proposal. Furthermore, each Somerton director6 has entered into a pre-bid acceptance agreement in relation to all shares owned or controlled by him. 3 On a fully diluted basis. 4 Based on the 30 trading days up to and including 18 April 2012. 5 Mr Robert Kennedy has abstained from making a recommendation due to being the non-executive Chairman of both Somerton and its largest shareholder Beach Energy Limited. 6 Refer to note 2 above regarding Mr Robert Kennedy. Cooper and Somerton have entered into a MIA to progress the Offer. Amongst other provisions, the MIA restrains Somerton from soliciting competing proposals and provides for a break fee payable to Cooper in certain circumstances. The MIA also provides for a reverse break fee payable to Somerton in certain circumstances. A copy of the MIA is attached at Schedule 2 of this announcement. Support of Somerton Shareholders Cooper has entered into pre-bid acceptance agreements with a number of Somerton shareholders, including all members of the Somerton Board of Directors for their entire holding, and other major shareholders, in respect of a total of 19% of Somerton’s issued shares. Under the pre-bid acceptance agreements, these shareholders have agreed to accept the Offer within two business days of receiving the Offer. Cooper Managing Director Mr David Maxwell said: “Somerton’s assets are a complementary fit in line with Cooper’s strategy and the merger will significantly enhance our position in the Otway Basin. The merged company will be in a very strong financial position to pursue organic growth opportunities and corporate activity to further add value and enhance shareholder return. The proposed merger provides the opportunity for Somerton shareholders to also participate in this growth.” Somerton Managing Director Mr Hector Gordon said: "We believe the merger with Cooper is a logical transaction that will create value for Somerton shareholders. The merged entity will have a dominant position in the Otway Basin and the financial strength to progress the exploration and development of emerging plays in this region. Somerton shareholders will also benefit from being part of a much larger ASX listed company with an attractive mix of production and high-impact exploration opportunities." Cooper has engaged Euroz Securities Limited as financial adviser and Squire Sanders as legal adviser. Somerton has engaged GMP Securities Australia Pty Ltd as financial adviser and TressCox Lawyers as legal adviser.

Empire announces postponement of seismic, and meeting

Apr 19 & 24: Again, what could be construed to be an event of moderate significance has occurred relating to northern Perth Basin permits EP-368 and EP-426, and again, Origin has not seen fit to inform the ASX of the latest developments, instead, leaving it all up to the junior JV players to construct their own market communications. Permit operator Empire, and even minor partner Norwest, have both reported that the upcoming 100km2 North Erregulla 3D, previously scheduled to be recorded in both permits by WesternGeco Crew 1160 around May 15, has been deferred to early next year. Even during the initial stages of the farmin in Aug last year, and again on completion of the deal on Dec 5 Origin, for whatever reason, didn’t see the need release the news to its shareholders, and left that task to the two junior parties. Origin will be earning 40% in each of EP-368 and EP-426 for providing 80% of the costs associated with recording the North Erregulla 3D, with Origin only taking over from Empire as operator if or when the work program in either block is progressed to the field development stage. The official line from the partners in relation to the survey, is that the JV ran into timing difficulties, and the proposed mid May start would now clash with the commencement of seeding activities by farmers, with the survey area around the towns of Mullewa and Mingenew located in the heart of wheat country. The revised timing of the survey could end up a much better fit with Empire’s wider objectives, giving the company up to a year to plan and permit a number of other surveys in the Perth Basin, allowing it to piggy back its additional programs onto the schedule of whichever crew ends up heading to the Perth Basin in the required time frame to complete the Origin-operated North Erregulla 3D. Although still in the planning stages, Empire will work up the Leschenault 2D in EP-416, the Launer 2D in EP-430 along with 2D over the Winchester/Garibaldi prospects in EP-454 to work up the namesake prospects to drillable target status ahead of sourcing a rig.


Contact David Maxwell Managing Director Cooper Energy Limited Tel: (08) 9489 3777 Hector Gordon Managing Director Somerton Energy Tel: (03) 9699 3009 Fax: (03) 9699 3110

Back to Index Cont’d next page

The WesternGeco crew has also been forced to terminate a survey for Origin and AWE that started in EP-320, L-1 & L-2 on Feb 16, with the 450km2 Redback/Irwin 3D suspended for later completion at 63% on Apr 10. Although not confirmed, that survey suspension was probably due to similar agricultural reasons. The crew has since left the state and is on its way to the Cooper Basin for a program for Drillsearch, involving an initial ~260km2 in Eromanga Basin permits ATP-539-P and ATP-549-P, followed by a substantial ~1050km2 in Cooper Basin ATP-940-P from mid May and potentially more work to follow. BG Group subsidiary and CSG specialist QGC exercised an option on Feb 1 this year to take a 9.4% stake in Drillsearch by subscribing for 31.6mil Drillsearch shares at $0.62 per share. The move by QGC forms part of an overarching strategic alliance between the two parties to “explore and develop unconventional shale and tight gas resources in the Cooper Basin,” which also involved QGC farming in for a 60% interest in 2000km2 ATP-940-P. The upcoming 3D survey will be the first step by the Drillsearch-QGC JV in defining a number of shale gas exploration targets for drilling later in the year. Back to Empire again, the company has been tinkering with dates for a planned general meeting of shareholders, moving the event from the previously scheduled Apr 26, out to May 23, to allow Empire time to “engage further with shareholders”. The items Empire’s shareholders will be asked to vote on are the issue of 100,000,000 shares to sophisticated investors at $0.015 per share, which represented a discount of around 21% compared to the $0.019 that the shares were trading at on Mar 23 when the initial GM announcement was made. The second item up for vote is the issue of 40mil options to new non exec director Jeffrey MacDonald, with the option exercise price to be based on the five day VWAP leading up to May 22.

There are some rumblings of discontent among a small but growing group of Empire’s retail shareholders, with a number of holders understood to be angry over what they perceive as the virtual handing over of the company’s Canning Basin assets, including the free-carried Cyrene-1 well in EP-438 on Buru’s schedule, to Key Petroleum in Dec last year. The fact that Empire MD Craig Marshall is also now a non exec director chairman of Key, with Key sharing premises with Empire, has added some fuel to the fire of the current discontent. Empire closed up $0.001 at $0.019 on volumes around 6mil while Norwest closed up $0.002 at $0.063 (+1.8mil) and Origin closed up $0.13 at $13.52 (+3.4mil) on Apr 19. Empire was trading steady at $0.018 on volumes around 2.5mil while Norwest was down $0.001 at $0.066 (+713,000) today. Empire announcements: EP-368 AND 426 FARMIN AGREEMENT WITH ORIGIN ENERGY DEVELOPMENTS PTY LIMITED Please find the revised timetable of the completion of the North Erregulla 3D 100 Square Kilometre Seismic Survey in EP-368 and EP-426, North Perth Basin, Western Australia from 15 May 2012 to 15 May 2013. The Farmin terms by Origin Empire Oil Company (WA) Limited (“Empire”), a wholly owned subsidiary of Empire Oil & Gas N.L., announced the execution of Farmin Agreements with Origin Energy Developments Pty Limited (“Origin”) for Petroleum Exploration Permits EP-368 and EP-426, North Perth Basin on 5 December 2011. These Agreements provide for the recording of a 100 square kilometre 3D Seismic Survey within EP-368 and EP-426 (“North Erregulla 3D Seismic Survey”) to provide for the delineation of drillable prospects in EP- 368 and EP-426. The parties to these Farmin Agreements are: EP-368 Origin (Farminee) and Empire EP-426 Origin (Farminee), Empire, ERM Gas Pty Ltd

(“ERMG”) and Allied Oil & Gas PLc (“Allied”). Origin will earn a 40% interest in each of EP-368 and EP-426 by paying 80% of the costs of the North Erregulla 3D Seismic Survey. Empire, ERMG and Allied will have their costs fully carried by Origin for the North Erregulla 3D Seismic Survey. Norwest Energy N.L. (“Norwest”) has elected to maintain its 20% working interest and will contribute 20% to the costs of the North Erregulla 3D Seismic Survey. Empire will retain operatorship of EP-368 and EP-426 and will also conduct the drilling programmes upon maturing drilling locations. Upon a decision to undertake an appraisal and development programme being made, Origin will assume operatorship.


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Empire is very encouraged by the North Erregulla prospectivity. The North Erregulla 3D Seismic Survey is designed to improve the structural interpretation of the North Erregulla Prospect. The North Erregulla-1 well was drilled by WAPET in 1967 which had a 3 metre oil column in the Dongara Sandstone. Recent interpretations indicate the well was drilled significantly down dip from the crest, suggesting there is a potentially large updip oil accumulation. In addition the prospect has gas potential in the deeper Irwin River Coal Measures and the High Cliff Sandstone. Empire has evaluated that the North Erregulla Oil Prospect has been estimated to have recoverable oil in the order of 22 million barrels in the Dongara Sandstone and 3 million barrels in the Arranoo Member the Kockatea Shale. The Permian aged Irwin River Coal Measures and the High Cliff Sandstone has potential to trap a further 100 billion cubic feet of recoverable gas. Revised timetable to complete the North Erregulla 3D Seismic Survey Origin has advised Empire that the seismic crew cannot be mobilised to the North Erregulla 3D Seismic Survey this season. The area of the North Erregulla 100km2 3D is located over extensive wheat belt country. Landowners are now preparing to seed wheat resulting in increasing difficulty to complete the survey in the timeframe prior to seeding commencing. Some very large wheat crops are “dry seeded” with some already commencing. Empire and Origin are working together with relevant land owners with a view to complete the North Erregulla 3D Seismic Survey early in 2013 when wheat has been harvested. Empire is also preparing to record additional seismic surveys in the Perth Basin in early 2013 following the completion of the North Erregulla 3D Seismic Survey, and may also be able to use the same seismic crew. These include the Leschenault 2D Seismic Survey in EP-416, the Launer 2D Seismic Survey in EP-430 and additional 2D seismic in EP-454 over the Garibaldi and Winchester Prospects. The Wannamal Seismic Survey in EP-389 over the Gingin Gasfield Area is planned as a separate Helicopter Seismic Survey of 85km2. All these operations are operated by Empire. RE: POSTPONEMENT OF GENERAL MEETING The Company advises that the General Meeting scheduled for 10:00 a.m. on Thursday, 26 April 2012 has been postponed. Details of the revised meeting date are as follows: Venue: Tawarri Reception Centre The Esplanade, Dalkeith WA 6009 Date: Wednesday 23 May 2012 Time: 10:00 a.m. The agenda for the General Meeting remains the same, namely to consider two resolutions summarised as follows: 1. Approval of a prior issue of shares, and 2. Approval of an issue of options to Mr Jeff MacDonald, a

Director of the Company.

The Meeting has been postponed in order for the Company to engage further with Shareholders. With regard to the second resolution, the period for calculation of the volume-weighted average market price of shares on which the options’ exercise price is to be based will shift to the five trading days up to and including 22 May 2012. The Company apologises for any inconvenience caused by the postponement. Should you have any queries concerning the postponement or the matters to be considered at the General Meeting, kindly contact myself or Dr Bevan Warris, Executive Director. Norwest announcement: North Erregulla seismic survey delayed until early 2013 Norwest Energy NL (ASX:NWE) (Norwest) advises the North Erregulla 3D 100 square kilometre seismic survey in EP368 and EP426, northern Perth Basin, Western Australia will now be delayed until early 2013. Origin Energy Limited (“Origin”) is paying 80% of the 3D survey cost to earn a 40% interest in the joint permits. The survey area is primarily located over wheat belt country in Western Australia’s mid west, where landowners are currently preparing to sow seed for the 2012 season (Figure 1). Due to the limited window of time that had been available following the 2011/12 harvest and prior to 2012 seeding program, Origin has now advised that it was unable to mobilise the seismic crew in time to carry out the survey. As such, the survey will now be carried out during early 2013, post harvest.


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Norwest is very encouraged by North Erregulla prospectivity, and elected to pay 20% of the survey costs to maintain its equity at 20% in both permits. The North Erregulla 3D seismic survey is designed to improve the structural interpretation of the North Erregulla prospect. The North Erregulla#1 well was drilled by WAPET in 1967 and encountered 3m of oil in the Wagina Formation. Recent interpretations indicate the well was drilled significantly down-dip from the crest, suggesting there is a potentially large updip oil accumulation. In addition the prospect has gas potential in the deeper High Cliff Formation. The 3D seismic data to be acquired will provide a better picture of where to locate the followup well and a better estimate of the resource potential.

Humble Beach casually reports gas find of significance

Apr 20 & 24: Beach continues its rich vein of form in the Cooper shale exploration game. Without much by way of flag waving or fist pumping, Beach announces its latest successful exploration outcome in its steadily building basin-centred shale gas program, into a relatively neutral overall market. The company appears to be on a winning formula in the early stages of its search for gas in the Permian shales of PEL-218, with the third

well in the block, Moonta-1, producing an outstanding initial outcome, reporting what at this stage appears to be the intersection of gas shows over an interval greater than 1000m. The Moonta-1 well has reached its final TD of 3810m, with evaluation and suspension

operations continuing for another week, but early indications from mud logging data suggest that the majority of the Permian target is gas saturated, from the Toolachee down to the base of the Patchawarra, the latter formation expected to be around 400-600m thick pre-drill. While a kilometre of gas shows would have most juniors, and even some mid-caps, with megaphone in hand and shouting from the rooftops, Beach has almost nonchalantly mentioned the Moonta result, in a single five-line paragraph. As if this sort of showing was the usual sort of thing to expect. The remainder of the less than two page release involves basic plans going forward, and the progress of frac stimulation activities at Encounter-1, which intersected a 200m thick section of Roseneath shale in late 2010 and where a 2TCF contingent gas resource has already been booked in combination with existing Nappameri Trough well Holdfast-1. At this point, the Halliburton fraccing unit has been released, with Encounter-1 flowing back frac fluid and steam. This will be diverted through a separator in the coming days, with a gas flow measurement to be recorded. The Halliburton crew will return again around mid year to frac the remaining sections at Encounter-1, and also undertake fraccing operations at Moonta-1.


Contact Craig Marshall Managing Director Empire Oil & Gas NL Tel: (08) 6389 2687 Peter Munachen Chief Executive Officer/Director Norwest Energy Tel: (08) 9227 3240

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When Ensign Rig-916 finishes suspension activities at Moonta-1, it will move to the Streaky-1 location, around 10km SE of Moonta, with operations to commence around mid May. Beach still has an extensive portfolio of targets to work through in PEL-218, with vertical exploration wells Boston-1 (to follow Streaky-1), Massena-1, Marble-1, Weyland-1, Dashwood-1 and Rapid-1, plus horizontal appraisals planned near the Encounter and Holdfast discoveries later in the year. Beach will also have large capacity Ensign Rig-965 under contract when it arrives later in the year for a shale specific exploration program in neighbouring ATP-855-P, to be carried out in conjunction with JV partner Icon. Unfortunately, from an originally anticipated start in Apr-Jun window, the program in this block has been delayed to Q3 due to industrial disputes and adverse weather conditions in the US holding up the mobilisation of the rig. Once landed and handed over to the JV, 5500m capacity Rig-965 will spud Halifax-1 as the first well in ATP-855-P, where Beach is farming in to earn an additional 40% on top of the 20% permit interest it already holds. In other news this week, also involving Icon and Ensign, Icon has announced that it has contracted Ensign Rig-960 to drill the Eolus-1 and Windom-1 CSG appraisal wells in Surat Basin ATP-626-P, starting in early May, as part of the $30mil stage two of the farmin agreement with Stanwell subsidiary Goondi Energy. Under the farmin, in return for its drilling funding, Goondi will earn 50% in four graticular blocks of ATP-626-P that make up the ‘Lydia Block’. Unfortunately for Qld-government owned utility Stanwell, it appears at this stage that Goondi has farmed in for half of not much, with Icon reporting an unspectacular conclusion to what was one of its most mature assets, the Lydia Project, around Jun 27 last year. Buried in the back of a glossy eight page newsletter at that time titled “Icon’s Breaking Through”, the company indicated that “despite a robust four well programme, drilling operations unfortunately revealed lower than necessary permeability to enable proceeding to a second pilot project in the area”. Attention will now be focused outside of the Lydia area, where the company hopes more permeable formations can be found, with Eolus and Windom in the north of the permit representing the initial components of this new push.

Ensign Rig-960 has been stacked since its last program for Blue Energy, when it drilled CSG core wells Monslatt-9 and Sapphire-4 in ATP-814-P from Aug 26 to Nov 25 last year. Icon is also understood to be eyeing Hunt Rig-2 for use around Jul this year for its two planned wells in 100% held Gippsland Basin PEP-170, where Strzelecki formation exploration wells Tiger West-1 and Dragon-1 will collectively target up to 1TCF of gas in place. Beach closed down $0.025 at $1.395 on volumes around 16.6mil on Apr 24 while Icon closed up $0.025 at $0.27 (+4.1mil) on Apr 20. Beach was trading up $0.025 at $1.42 on volumes around 6.5mil while Icon was steady at $0.265 (+368,000) earlier today. Beach announcement: MOONTA-1 GAS SATURATED THROUGHOUT TARGET ZONE, ENCOUNTER-1 FRACTURE STIMULATION COMPLETED Beach advises that the: Moonta-1 vertical exploration well has reached total

depth at 3,810 metres and appears to be gas saturated throughout the target Permian zone, which is over one kilometre in thickness; and

Encounter-1 well has completed fracture stimulation of the Patchawarra Formation.

Moonta-1 Beach Energy Limited (ASX: BPT, “Beach”) advises that the Moonta-1 shale and basin centred gas well has reached total depth of 3,810 metres yesterday. Beach is greatly encouraged by initial indications from mud logs that the well is gas saturated throughout the Permian target zone, from the Toolachee Formation to basement at the bottom of the Patchawarra Formation. This covers multiple intervals over a total target zone of greater than one kilometre. In considering the Shale and Basin Centred gas program moving forward, Beach believes that the well bore design can be such that a vertical production well could produce gas from the whole of the Permian target zone. This may possibly result in the Nappamerri Trough Basin Centred Gas play including both horizontal and vertical wells as part of the development plan in 2013. The Ensign 916 rig that drilled Moonta-1 will spend a further week on site for evaluation and suspension purposes, after which it will be mobilised to the Streaky-1 well location, approximately 10 kilometres to the South East of Moonta-1. Streaky-1 is expected to spud within two weeks of release from Moonta-1. Encounter-1 The fracture stimulation of the Patchawarra Formation (one stage only) at Encounter-1 has been completed with the well currently flowing back fracture stimulation fluid and steam. This will be diverted through a separator within days, at which point the first gas readings will be taken.


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The Halliburton fracture stimulation spread will now be released from PEL-218. It is anticipated that the spread will be available again in June/July, at which time it will complete the remaining target sections in Encounter-1 and undertake fracture stimulation of the Moonta-1 well. Icon announcement: ICON PLAN TO DRILL 5 WELLS Icon Energy Limited (ASX: ICN) today announced that it had signed a drilling contract with Ensign International Energy Services for the Ensign Rig-960. The Ensign Rig 960 will drill two wells, Eolus1 and Windom1 in ATP-626-P in Queensland and the first well is expected to spud in early May 2012.

“With the addition of the two wells in ATP-626-P this brings the total number of wells to be drilled over the next few months to five. This is the first time in our history that Icon Energy has been involved in such a concentrated exploration program across three tenements in two states, Queensland and Victoria”, said Mr James. The first drilling operations will be conducted in ATP-626-P, in which Goondi Energy (a wholly owned subsidiary of Stanwell Corporation) has farmed into and these two wells are part of the farmin agreement and the Stage 2 work program for 2012. In Victoria within our PEP-170 tenement we plan to drill our first natural gas wells, Tiger West-1 and Dragon-1 in Q3 2012.

“The Tiger West-1 and Dragon-1 well prospects have the potential of addressing more than 1 TCF of gas-in-place”, said Mr James. Beach Energy (Beach Energy), the Operator, inform us the first well, Halifax-1 for Ensign Rig 965 is expected to spud in Q3 2012. Icon Energy have a 40% interest and Beach Energy are farming in to earn a 40% interest in ATP-855-P in addition to the 20% interest they already hold. ATP-855-P is situated in the highly prospective Nappamerri Trough in the Cooper Basin. The independent United S t a t e s E n e r g y I n f o r m a t i o n Administration’s World Shale Gas Resources Report (EIA Report) has placed the shale gas resource potential in the Cooper Basin as a whole at 342 Trillion Cubic Feet (TCF) of gas, with the recoverable equivalent at some 85 TCF.


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The Ensign Rig-965 will be used to assess the continuation of what is considered to be a thick, multi-lithology gas accumulation which potentially extends into ATP-855-P from PEL218, located on the South Australian side of the gas rich Nappamerri Trough. In addition to our 5 well drilling program we plan to undertake over 600km of 2D Seismic acquisition 400 km in PEP-170 in Victoria and 200km in ATP-849-P in Queensland.

Tap not content to miss out on WA shale stampede

Apr 24: With Buru’s recent roaring success in confirming wet gas discoveries of significance at Valhalla-2 and Yulleroo-2 in the Canning Basin, everything and everyone seems to be heading towards ‘unconventional’ in WA’s north, with primarily offshore player Tap seeing the light this week to vie for a slice of the future spoils of the onshore market. Tap will enter the market at a similar grassroots level to New Standard, whose two Carnarvon Basin permits held in a JV with ConocoPhillips sit right in the middle of two new areas that Tap is seeking to have an involvement in. Tap views its pending move into the onshore unconventional market as a logical and relatively inexpensive bolt on to its existing offshore Carnarvon business, and will venture into new territory – on a number of different levels - via an agreement with private party Rusa Resources. While Rusa itself is something of an unknown entity, with little by way of readily available public information on the company, Tap claims the company’s principals have been involved in successful exploration ventures, both onshore and offshore, that have resulted in the discovery of commercial oil fields in addition to unconventional gas resources. So it appears there is a reasonably good track record already in place in terms of the technical credentials of Tap’s new partner.

Rusa currently holds full rights to two SPAs, running from just south of Exmouth, to the east and south of Carnarvon within the Merlinleigh and Byro Sub Basins, with STP-SPA- 0018 and STP-SPA-0021 covering a total of almost 9.5mil acres. At this stage, Rusa controls all of the area under an option, with permit 0018 covering just over 19,000km2 and 0021 spanning 19,378km2, although the exercise of the option to convert the areas to exploration permits will result in the reduction of each permit area by half. Upon conversion to exploration status, Tap then holds the right to take a 20% stake in the EPs, with an option to increase its holding by another 15% in each block. Tap would be happy with the location of the areas, which engulf the 8500km2 of territory held by New Standard and ConocoPhillips, with the ConocoPhillips operated JV controlling STP-EPA-0014 and STP-EPA-0015. New Standard was awarded its acreage around the area of the historical Merlinleigh-1 well in early Jun 2010, following a 12 month study that determined that the Goldwyer shale in the region was highly prospective for shale gas, over an area of 300km by 600km, which included the company’s tenements. Geochemical survey results, integrated with historical well results, identified a gas window in the Wooramel group shales, anticipated to be up to 300m thick at depths around 2000m with high total organic content percentages. The Moogooloo sandstone was also considered to have good reservoir qualities and sound permeabilities at shallower depths. Based only on these interesting preliminary findings New Standard attracted ConocoPhillips to the venture in Jul 2011, with the US major committed to spending up to US$109.5mil on unconventional exploration, albeit with a number of potential exit points along the way, in order to earn up to 75% in the Goldwyer Project from New Standard.


Contact Reg Nelson Managing Director Beach Energy Ltd Tel: (08) 8338 2833 Richard Holliday Commercial Manager Icon Energy Tel: (07) 5554 7111

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The JV now has a rig in hand, having executed a contract with MB Century for the use of incoming 4270m capacity Rig-14 for a program of five firm and up to six optional wells in New Standard’s Canning and Carnarvon acreage, with the optional slots potentially open for New Standard to sub-assign to third parties in the region. The program will include two wells in the Merlinleigh project area from early 2013, but will kick off with Nicolay-1 in 16,154km2 Canning Basin EP-456 in Jun. Obviously Tap will be watching any exploration activity in the vicinity of its two Carnarvon SPAs like a hawk, with any future drilling carried out by Tap and Rusa to target the same shale formations. Although looking a bit too far ahead for this stage of the process, the blocks held by Tap are in close proximity to both the Dampier to Bunbury gas pipeline for easy access to both the domestic gas or LNG export markets. Obviously, before the location of infrastructure becomes much of a consideration, commercially extractable quantities of gas must be found. With $100mil in cash and being debt free, Tap should be able to navigate its way financially through the early stages of assessment in the vast tract of land it will be participating in. However, when exploration licenses are granted and things start to get serious in terms of funding requirements for 3D seismic and wells, Tap will probably go the way of New Standard and sound out interest from cashed up internationals when that time comes. Tap closed down $0.01 at $0.77 on volumes around 195,000 on Apr 24. Tap was trading up $0.005 at $0.775 on volumes around 316,000 earlier today.

Tap announcement: T AP E N T E R S AG R E E M E N T T O P U R S U E UNCONVENTIONAL RESOURCES IN THE ONSHORE CARNARVON BASIN Highlights Early stage new ventures opportunity for both

conventional and shale oil and gas Large acreage position Close proximity to a delivery point into a very strong

gas market Tap Oil Limited (Tap) is pleased to announce that it has entered into a binding agreement with Rusa Resources Pty Ltd (Rusa) to participate in the exploration of a significant acreage position in the onshore Carnarvon Basin, Western Australia.

Rusa holds full equity ownership in two special prospecting authority (SPA) applications (STP-SPA-018 and STP-SPA-021) with acreage options. The acreage options allow for the potential to convert up to 50% of the SPA areas into exploration permits, subject to usual government and other approvals. Tap will earn the right to take a 20% interest in the resulting exploration permits on election, with an option to earn an additional 15% in each permit.


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These SPAs cover a total combined area of over 38,000 km2 (9.47 million acres), and contain a large part of the Palaeozoic Merlinleigh Sub-basin, the entire Byro Sub-basin, plus associated shelfal areas. The exploration focus is primarily on unconventional plays, with the main targets being Permian shale gas and Devonian shale oil. There is also conventional oil and gas potential. The acreage position is favourably located in close proximity to the Dampier to Bunbury natural gas pipeline which could provide access to either the growing Western Australian domestic gas market or the LNG export market. The forward program will see Rusa and Tap undertaking exploration work over the SPA areas, including geochemical surveys, with the intention of delineating the preferred acreage for conversion to exploration permits in 2013. Tap Managing Director Troy Hayden said: “The agreement with Rusa provides Tap with an early stage exposure to an unconventional play type in Tap’s existing focus area of the Carnarvon Basin.

We have been actively working on new ventures and business development for a long time and affordable, commercially and technically attractive opportunities are very hard to come by in the Australia and South East Asian region. We think this is a great opportunity for us. We see this as a logical extension for us given our experience in the Western Australian gas market and the northern Western Australian oil and gas upstream business in general. Targeting the unconventional plays in this area we know well is a logical direction for us. With around $100 million in cash and no debt, Tap remains well positioned to execute its current Thailand, Ghana and Australian programs.” Background Rusa Resources Pty Ltd is a private Australian company whose principals have previously undertaken successful onshore and offshore Australian focused exploration, resulting in the recognition and discovery of commercial oil fields and unconventional gas resources.

News in Brief Apr 23: While some onshore Perth Basin farmin operations may not, developments at the BassGas project definitely do rate on Origin’s announcement agenda, with the company announcing a major milestone achievement at the Yolla Mid Life Enhancement Project in

TAS-L-1 with the lifting of the accommodation and controls module from the Jascon 25 construction vessel onto the Yolla A platform. The platform and facilities upgrade, including the accommodation unit and addition of gas compression and condensate pumping facilities, form Phase I of the Yolla MLE project. Phase II of the project comprises the drilling of the Yolla-5 and -6 development wells using a particular type of jackup rig suited to being positioned on the upgraded platform, with drilling now expected to take place in the 2013/2014 summer. While the completion of a major aspect of the works is a good milestone for the JV to reach, there have also been some not so positive aspects to the story that have started to emerge, with the first relating to costs. The entire project, including new drilling, was previously budgeted at around $485mil, with Origin now indicating that Phase I alone, due to some “unique offshore construction challenges”, has blown out from around $360mil to $460mil. The second negative relates to timing, with the expected re-start of production being delayed, which will contribute to reducing 46.25% holder AWE’s 2011-2012 production guidance to 4.7mil boe from the previously reported 5-5.5mil boe, which would have generated revenues for the company of up to $300mil. Overall, the negative side won out, with AWE’s shares slipping by $0.10 to $1.81 on the news, while Origin, with a wider spread of upstream and downstream assets to absorb any shocks, gained $0.07 to $13.37.


Contact Troy Hayden Managing Director/CEO Tap Oil Tel: (08) 9485 1000

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Other Announcements Sun: Apr 20: Sun Resources NL: Update on the Delta Oil Project, Texas, USA Leasing continues towards Sun’s target of 10,000 net

acres in the highly prospective oil play along the trend of the prolific Eagle Ford Shale Fairway.

Sun Resources currently undertaking due diligence on its 7th tranche of leases, expected to take Sun’s total lease position in this exciting play beyond 8,000 net acres.

Strong oil production rates being reported in nearby Woodbine/Eaglebine horizontal production wells validate Sun’s entry into the Delta Oil Project.

Strong industry interest in nearby Woodbine/Eaglebine acreage confirms potential of Sun’s significant acreage position.

The Board of Sun Resources NL (“Sun Resources”, “Sun” or “the Company”) is pleased to provide an update on positive developments with respect to Sun’s Delta Oil Project, Texas. Sun Resources controls a 100% working interest in 7,605 acres of leases in the Delta Oil Project in Leon County, Texas, USA, along trend of the prolific Eagle Ford Shale oil and gas fairway. Sun is continuing to work with the vendor to complete the acquisition of the target 10,000 acres, subject to completion of due diligence. To this end Sun is currently completing due diligence on a 7th tranche of leases which will take Sun’s total lease position in this exciting play to beyond 8,000 acres. Sun Resources’ Managing Director, Mr Matthew Battrick commented on the acquisition, saying: “Sun Resources is pleased to continue to grow its outstanding, and now very sought-after, lease position. We will shortly have a 100% working interest (75% NRI), in over 8,000 acres of a high quality oil and gas area in the Eaglebine play of Leon County, Texas, on trend with the world-class, Eagle Ford Shale oil and gas fairway. Sun is also very encouraged by the reported successful drilling and production activity in nearby Woodbine/Eaglebine wells which lie only 10 to 15 kilometres south of our lease position.”

Sun Resources is aware of significant demand for land leasing and competitive sale activity within Leon County, as shown by the number of large independent drilling operators that now have substantial lease positions around the Sun acreage (Figure 1). There are unconfirmed reports of lease sales targeting Woodbine/Eaglebine objectives for up to US$2,500 per acre near Sun’s Delta Oil Project. It has been reported that the following companies are now also active in Leon County: Gastar, Halcón, Petromax, Encana and Chesapeake. Sun Resources also reports that during discussions with other operators and drilling contractors, most operators in Leon and Madison Counties are having greatest success with horizontal well bore lengths of 6,000 -7,000 feet (1,830-2,130 metres) delivering initial production rates of 800bopd and more after multi-stage fracture stimulations, or “fracs” and draining lease areas of at least 120 acres (about 50 hectares). These wells are being drilled, fracced and brought into production for an investment of about US$5-6 million (figure 2). Operators are also reporting that oil production decline rates are more modest than previously forecast, adding to the strong commercial potential in the Eaglebine/Woodbine play. These nearby drilling results indicate that pay-back can be achieved within 12 months, delivering strong rates of return and net present values comparable with the conclusions of the independent resource and economics assessment commissioned by Sun Resources, through Ralph E Davis. The Ralph E Davis report concluded that wells within this play could deliver an NPV10 of $10.333 million per well (see detail below under the heading: “About the Delta Project”). Recent industry research has listed the following characteristics of the Woodbine/Eaglebine oil play (Figure 3). Organic-rich, laminated sand above Buda Well cost = $5.5-6.5 million ~40% silica and clastics = natural fractures Spud to Production = 60-90 days Geologically equivalent to EFS in South Texas Well Spacing = 160 acres Modern drilling/completion skills critical EUR = 467 mboe per well per zone Multiple, high quality sand lenses Potential from 5,500-11,500 feet depth Premium pricing for oil, NGL’s and gas

Responds to multi-stage fracs (10-20 stages)

10%+ porosity, 4-5% TOC

High porosity = high storage capacity sands

Current IP’s 3-4 times higher than previous estimates

Downdip permeability traps hydrocarbons


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Sun Resources looks forward to providing further updates to shareholders as the acquisition is progressed over the coming weeks, and as the company progresses towards development of the Delta Oil Project.

Maverick: Apr 20: MAVERICK MORE THAN DOUBLES ACREAGE HOLDINGS AT NASH DOME The Directors of Maverick Drilling & Exploration Limited (ASX: MAD) are pleased to announce major acquisitions reflecting a significant increase in acreage holdings on and around Nash Dome. Highlights of the transaction: NASH PHASE 1 HOLDINGS. Previously Maverick’s

holdings in the field were approximately 2,740 net acres. This area is hereafter referred to as NASH PHASE 1 properties.

NASH PHASE 2 HOLDINGS. New leases have now

been acquired on approximately 2,895 net acres which will hereafter be referred to as NASH PHASE 2 properties. This acquisition more than doubles the Company’s leasehold interest on and flanking the known area of the field.

NASH PHASE 3 OPTIONED ACREAGE. Maverick also

secured a two year option to lease an additional 1,790 net acres in and around Nash Dome. Should the Company elect to exercise their rights on these properties, they will be referred to NASH PHASE 3 properties. Should the Company exercise its option rights on these tracts, this would almost triple its holdings in Nash.

NOW LARGEST SALT DOME HOLDINGS. This transaction brings Nash total leases to 5,635 net acres plus 1,790 net optioned acres. This becomes the largest holdings of any of Maverick three fields, with Blue total

Blue Ridge holdings at approximately 3,600 net acres and Boling Dome at 4,500 net acres. SEISMIC PERMIT S. I n

addi t ion to the above transactions, three year seismic permits were acquired on a total of 3,615 acres of the NASH PHASE 1 and PHASE 2 acreage. In some leases Maverick has acquired, seismic permits are required to be acquired separately from traditional oil and gas leases. Maverick anticipates beginning a seismic project on Nash following the acquisition and reprocessing of all existing seismic in the Nash area. That acquisition and reprocessing project is already underway.

NASH PHASE 1 RESERVES RECENTLY RELEASED.

The Company recently announced reserves on NASH PHASE 1 holdings of 2,740 net acres totaling approximately 22.5 million 1P oil reserves net to the Company’s interest and 50.6 million 2P oil barrels. The Company emphasizes there are no implications whatsoever that the doubling of Maverick Nash Dome acreage holdings implies the doubling of current disclosed reserves. Subject to the results of continued seismic work and future drilling the ultimate reserve impact of this acquisition could range from no additional NASH PHASE 2 reserves attributable to Maverick to reserves considerably higher than those attributable to current NASH PHASE 1 acreage holdings. Preliminary reserves, if any, attributable should be forthcoming within the next 4-6 months.

RECENT VICKSBURG DISCOVERY AND SALT

OVERHANG TARGETS CONTRIBUTING FACTORS FOR THE EXPANSION. The initial well Maverick drilled in the field, the Groce #181, encountered a new field pay oil sand in the Vicksburg formation. In addition, a documented salt overhang exists on Nash Dome. Neither of these significant geological factors have been evaluated or exploited and are contributing factors for the expansion of Company holdings in the area.

F U R T H E R E XP A N S I O N N E G O T I AT I O N S

UNDERWAY. While there is no guarantee of the Company’s success, negotiations are underway to further expand Maverick’s holdings in the Nash Dome area. Once those efforts are complete, the Company will disclose a revised map of holdings in the area.


Contact Matthew Battrick Managing Director Sun Resources Tel: (08) 9388 6501

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Commenting on the new Nash Dome acquisitions, Maverick’s Executive Chairman, Mr Don Henrich said: “It should now be clear to our shareholders that Maverick’s expansion strategy is well underway. Our recent Nash drilling success, a new Nash field pay discovery in the Vicksburg sand, the significant reserves identified in Nash Phase 1, and now the enormous amount of additional potential drilling ahead in Nash makes it another crown jewel in the Maverick family. Having several hundred developmental wells ahead in Blue Ridge to be drilled was not the complete picture of our efforts or time horizons. Additions of the new drilling rigs recently acquired and our expanding rig fleet of 14 rigs will have a home for many years to come across just these two fields alone. ” Solimar: Apr 20: Solimar commissions steam generation unit for Kreyenhagen field redevelopment Solimar Energy Limited (ASX: SGY) (TSXV: SXS) (“Solimar” or the “Company”) has commissioned the building of a 20 MMBTU capacity, portable steam generation unit to be used in the second stage of oil production testing at the Company’s 100% owned Kreyenhagen field during 2012. Construction of the steam generation unit, with a budgeted cost of approximately US$500,000 (including applicable tax), has a lead time of about 5 months. The steam unit will be required for a second stage, steam assisted cyclic oil production test (“Huff and Puff”) program, following an up to 3 month duration first stage of “Cold Flow” testing that will commence during May, 2012. This particular project will target the shallow Temblor Sandstone heavy oil resource which has been independently assessed to contain unrisked oil resources of up to 79 million barrels of oil in place net to Solimar’s working interest*. The Kreyenhagen field area also contains shale oil exploration upside and a smaller light oil and gas accumulation that will be assessed by future work programs. Solimar recently completed a C$1.1 million placement (the "Placement") at C$0.09 per share to strategic investors in Canada and Switzerland principally to fund the construction of the steam generation unit and the overall testing operations at the Kreyenhagen Field. Further details about the Placement were released to the ASX and Canada on 9 April, 2012. Highlights Commodity prices (high oil and low gas) have created a

robust commercial environment for a redevelopment of the shallow Kreyenhagen oil field. California heavy crude currently trades at a premium to WTI.

Commitment to the steam generation unit illustrates the

Company’s growing confidence in the field redevelopment.

Huff and Puff steam enhanced production testing is to

follow an initial primary or Cold Flow testing phase.

The steam assisted test is designed to improve flow rates and prove that high recoveries of oil in place (up to 60%) could be achieved in a full field, steam assisted development.

Equipment will be mobilised to commence the Cold

Flow testing in May, 2012. Commenting on the commitment to build the steam generation unit, Solimar CEO John Begg said : “It’s pleasing to continue achieving milestones toward a redevelopment of the Kreyenhagen oil field for which there is independently assessed, unrisked in place oil resources* net to the Company’s working interest of up to 79MMBBLS of 13o -18o degrees API gravity oil*. The start of the initial ”Cold Flow” or primary production testing program utilising a selection of 4 wells owned by the Company is imminent. This program is expected to run for approximately 3 months and then, using the same wells and the new steam generator, a cyclic steam or “Huff and Puff” testing program will be carried out. Solimar expects a full field development at Kreyenhagen to ultimately require a dedicated steam flood which will be designed based on the initial “cold flow” and “Huff and Puff “programs. These initial test programs to be carried out this year, combined with the drilling of shallow appraisal wells are expected to support booking of oil reserves. Steam flood projects in the San Joaquin Basin can achieve recovery of up to 60% of the oil in place. The Company’s timing is excellent as the current strong oil price for heavy crude in the Valley, combined with a currently low gas price is providing commercial conditions for a steam based redevelopment superior to at any time in the history of this field.” Solimar is embarking on a two stage production testing program of up to 4 wells to gather key reservoir and production engineering information about the shallow Temblor Sandstone heavy oil reservoir. This will be used to assess whether the field can be initially developed as a low operating cost, cold flow production project and to model an optimum, full field redevelopment as an enhanced oil recovery or EOR project using steam injection. The Company is encouraged by a commodity price environment that is currently pricing the benchmark heavy crude price in the San Joaquin Valley (Midway Sunset 13o degrees API) at over US$100/ BBL while gas prices are low, approximating US$2.70 / MCF in February, 2012. The impact of these economic conditions are illustrated in the attached graphs, the data for which has mostly been derived from the US Energy Information Administration** and combined with Solimar’s estimates of the indicative price impact on steam related operating costs per BBL. The data plotted show that if the oil vs. gas price conditions that have evolved over the past three years in particular continues, there would be highly favourable economic conditions for a steam based EOR redevelopment of the Kreyenhagen project. Solimar’s research indicates that conditions are robust even if relatively high ratios of steam injection relative to oil produced (Steam to Oil Ratio or “SOR”) are required.


Contact Don Henrick Chairman Maverick Drilling Tel: (02) 4925 3800 Fax: (02) 4925 3811

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Note that based on California Division of Oil, Gas and Geothermal Resources (DOGGR) records the average API gravity produced by historic wells at Kreyenhagen (there are 22 legacy, vertical oil producers that produced on pump at rates between 1-21 BOPD) has been approximately 15o degrees API. This would attract an approximate US$1.28 / BBL premium to the Midway Sunset 13o degree gravity reference price according to a pricing formula regularly published by Chevron Oil Trading. The differences between the three oil producing techniques planned for the Kreyenhagen field can be summarized as follows and are illustrated in the accompanying figure. Primary or “Cold Flow” production The shallow heavy oil zone is to be initially tested in up to 3 of the 4 existing wells in which the approximately 200 feet thick oil reservoir within the upper part of the Temblor Sandstone is preserved behind casing. Selected intervals will be perforated and the wells placed on pump. Historically, beam pumps were used in the field achieving initial flow rates of between 1 -21 BOPD with varying water cuts. Solimar will be applying both standard type beam pumps and modern progressive cavitating pumps (PCP’s) for this testing program that may continue for up to 3 months. The data will be examined to help design the following steam injection program. However if there is strong Cold Flow performance from any given zone or well, the production test may be prolonged. Depending on the results, a first phase Cold Flow redevelopment of the field may be warranted which would be characterised by low well costs due to the shallow reservoir depths (less than 1,000 feet). Typical recoveries of less than 15% are achieved from cold flow operations in a heavy oil reservoir. Cyclic Steam injection or “Huff and Puff” production This will involve re-entering a selection of the wells utilised in the Cold Flow program and injecting steam into the perforated heavy oil zone (s). The duration of the steam injection and the volumes involved have been modelled, but will be refined with the benefit of the Cold Flow results. A 20 MMBTU capacity, portable steam generator has been commissioned from Clayton Industries of Los Angeles with delivery within approximately 5 months. DOGGR permitting for the Huff and Puff program is in an advanced stage and is expected prior to delivery of the steam generation unit. After the steam has been injected, the well is allowed to soak for a defined period before being allowed to flow back out the same well bore. This process may be repeated with the period of each steam and following production cycle dependent on the flow response. The Huff and Puff steam process is designed to increase the mobility and hence flow rate of the oil and is generally classified as a recovery acceleration technique that if applied long term may achieve up to a 25 % recovery of the oil in place. Solimar’s engineering modelling, as also assessed by Sproule*, indicates that a steam flood process will be a superior long term recovery mechanism for the Kreyenhagen field.

Full EOR or Steam Flood Once sufficient data has been collected from the initial Cold Flow and Huff and Puff programs and confidence gained in moving the oil from the resource to reserves category, a comprehensive recovery program using a steam flood process can be more accurately modelled. This will also require access to whole core data and the Company is already advanced in permitting a program of shallow appraisal wells in the second half of 2012. These wells are planned to further appraise the extent of the oil field to support certification of additional reserves. A steam flood will require the drilling of dedicated steam injection and producing wells and is more capital intensive than the other production methods. A commitment to this phase would however follow booking of reserves and the resulting upward revaluation of the project. Steam flooding requires a lengthy period of time when the main activity is injection of steam into the reservoir creating a steam chamber that increases the pressure and oil mobility. It is likely to involve horizontal production wells which in combination with the impact of the steam would be expected to result in flows and recoveries per well at multiples for that achieved under Cold Flow. For reference such wells in the nearby Coalinga field, an analogue to Kreyenhagen field, have achieved initial steam enhanced production rates of 50 – 100 BOPD and are expected to deliver recoveries of up to 60% of the oil in place. Molopo: Apr 23: Molopo increases 2012 capital investment budget to $98 million Molopo Energy Limited (“Molopo”) (ASX:MPO) is pleased to announce that its Board of Directors has approved an increase in the 2012 capital investment programme to AUS$98 million (previously AUS$36 million). The forecasted end year production target has been increased to 2,300 boepd (85% oil and NGLs) (previously 730 boepd). This expanded investment program reflects the Company’s increased confidence in the Wolfcamp play based on the results from Molopo’s three recently completed wells in the Permian basin in West Texas. This revised budget is aligned with the Company’s commitment to shareholders to review the 2012 program during the first half of the year once the potential of the play was better understood. Molopo has contracted a rig in Texas to support this expanded drilling program and six new long horizontal wells (100% working interest (“WI”)) will be drilled in Molopo’s Permian Basin lands before the end of the calendar year. In Saskatchewan, one recompletion and two new horizontal wells will be drilled to test the emerging Midale play (100% WI), and two further non-Operated Bakken horizontal wells in the Taylorton area (25% and 50% WI) are anticipated. The Company has increased its annualised production target for 2012 to ~1,100 boepd (previously 680 boepd).


Contact John Begg Chief Executive Officer Solimar Energy Limited Tel: (03) 9347 2409

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CEO and Managing Director Tim Granger commented, “Our first wells in the Fiesta project in West Texas have confirmed that we’re in the oil window. We’re now moving quickly to the next phase of development of this asset, where we are looking to achieve the higher initial production (IP) rates seen from long horizontal wells recently drilled by nearby Operators. “We made the commitment in our strategy to become an oil producer. On the strength of our asset base and now with 100% ownership in our 26,000 acres in the Permian Basin, an exit rate for 2012 of 2,300 boepd will see us progressing aggressively along this path, with scope for significant growth in 2013 and beyond.” Based on current forecasts, the Company expects to exit 2012 with a cash balance of approximately $25 million, excluding potential divestment proceeds. The 2012 capital program, which includes provisions for additional land acquisitions and seismic, will be fully funded by cash and internally generated funds. The on-market share buyback has been halted in light of the expanded capital program and anticipated future funding requirements.

This budget is based upon a WTI price of US$103/bbl and exchange rates of 0.97 US$/A$ and 1 US$/C$. All dollar amounts are Australian dollars unless otherwise stated. “2012” refers to calendar year 2012. Buccaneer: Apr 24: HIGHLIGHTS High quality 3D seismic shoot successfully completed Encompasses full 9,308 acres under lease Data processing now in progress Buccaneer Energy Limited (“Buccaneer” or “the Company”) is pleased to advise that the 3D seismic program that commenced in December 2011 has been successfully completed. Preliminary evaluation of the quality of the data is very positive and we are looking forward to the results of the 3D seismic processing now in progress. As an exploration expense, up to 65% of the costs associated with the seismic program will be covered by the ACES program through the State of Alaska.

The seismic covered a total of 23.4 square miles and includes the full 9,308 acre (14.5 square miles) lease position on the Company’s 100% owned Kenai Loop project located onshore Cook Inlet, Alaska. The final coverage was slightly smaller than the planned 25 square mile program due to some wetland restricted areas but well within our design to properly image our targeted productive horizons. The 3D seismic was designed to provide high resolution structural and stratigraphic imaging down to 20,000’ below surface. This will allow for the further development of the Company’s discovery and the assessment of exploratory oil and gas opportunities in the Tyonek and Hemlock formations below the producing formations in the Kenai Loop # 1 gas discovery well. “Use of the Weems-Global Nodal GPS system eliminated the need for seismic cables and allowed Buccaneer to record seismic data from over 2,000 plus geophones for each shot” Said Craig Moore Buccaneer’s Chief Geophysicist.

Data from the 3D seismic is currently being processed and is expected to be completed in the middle of May. On completion the data will be mapped and analysed for geophysical locations of prospective hydrocarbon anomalies. This data will then be integrated into the Company’s geological models and used to determine the next well locations in the Kenai Loop area. The access to modern 3D seismic will be a significant enhancement to the current available 2D seismic that was acquired in the 1970’s.

“Our contractor, Weems Geophysical, did an excellent job working with the community to acquire this data and we are looking forward to seeing how this data can improve our drilling program this year. Working with the community is very important since our Kenai Loop project is located very close to downtown Kenai and local businesses. Our activities are very visible to everyone in the community” said Director Dean Gallegos.


Contact Tim Granger CEO and Managing Director Molopo Energy Tel: (03) 9618 8722

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

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Jupiter: Apr 24: Trial Production commences from J-50 and J-52 wells KEY POINTS: Trial production from the J-50 and J-52 wells has now

commenced. Jupiter Energy is transporting oil from the field by road-

tanker to a 3rd party storage base. Sales agreements with at least two local traders are expected to be signed shortly.

Trial Production Licence applications for both J-51 and J-53 wells are now progressing and will soon be submitted to Ministry of Oil & Gas for approval.

The Board of Jupiter Energy Limited, the Kazakhstan-focused oil exploration and production company, trading on AIM (“JPRL”) and ASX (“JPR”), is pleased to announce that oil from the J-50 and J-52 wells is now being produced under their respective Trial Production Licences. Aggregated daily production from the J-50 and J-52 wells is initially expected to be ~600 barrels of oil per day (bopd) and the Company is taking responsibility for the transportation of the oil to the nearby 3rd party storage facility and for storage costs associated with the oil. Jupiter is finalizing sales agreements with at least two local traders and expects to announce details of these contracts shortly. Both wells can be produced under Trial Production for a maximum of 3 years and during this time oil is sold into the domestic market. The Company intends to move these wells from trial production to full production (and therefore from domestic to export oil sales) sooner than this maximum 3 year period. More detail on the plans to move to full production will be released later this year. Trial Production Licence applications for the J-51 and J-53 wells are being prepared for submission to the Ministry of Oil & Gas for approval. The approval process is expected to be completed by the end of this year and the Company expects to end 2012 with revenue from four wells on trial production. Operations Update The Company is scheduled to release its Quarterly Report before the end of April 2012 and this will provide a more comprehensive update on in country operations.

Hawkley: Apr 26: Independent Sorochynska Resource Assessment Hawkley Oil & Gas is pleased to announce that it has received an independent Resource assessment of Hawkley’s 100% owned Sorochynska Licence Field in the Dnieper Donets Basin in Ukraine. This Resource assessment, carried out by Moyes & Co, includes the hydrocarbon Resources beyond the Reserves included in the Reserves Report published on 13 January 2012. Appendix 1 sets out an explanation of the Reserves and Resources referred to in this announcement. Highlights: Mean Contingent Resources of 248 Bcf gas and

7.2million barrels condensate in the Visean Sandstones.

Mean Prospective Resources of 168 Bcf and 3.5 million barrels condensate in the carbonate reservoir.

Resources additional to current 2P Reserves in the Visean B18 reservoir of 40.5Bcf (3P 51Bcf).

Estimated value of potential future net revenue to Hawkley from the Sorochynska Licence of US$947million on a mean unrisked NPV10 basis:- $615million for the Contingent Resources and $332million for the Prospective Resources.

Contingent Resources identified in the B-16, B-17, B-18, B-19 and B-22 Reservoirs.

Log analysis of previous wells in the three major fault blocks in the Licence indicate the B-19 Reservoir interval is saturated with hydrocarbons with varying degrees of reservoir thickness.

Apparent additional pay in B-18 Sands in blocks other than the currently producing block

Significant Mean Contingent Resources of 113 Bcf in the B19 sand in the East Block which is to be appraised by the currently drilling Sorochinska-202 well

A full version of Moyes’ Report can be accessed on Hawkley’s website at www.hawkleyoilandgas.com. The report details the economic assumptions utilized by Moyes & Co. to calculate the estimated future net revenue. Commenting on the report, CEO Richard Reavley said: “We are very satisfied with the findings of this independent report. It underpins the fact that there is a lot more upside on our Sorochynska License than previously thought, especially from the B19 sand in the East Block which is what we are intending to appraise with the 202 well. Sorochynska now has 3P recoverable Reserves of 51Bcf from the B18 Sand with significantly more prospectivity in other target reservoirs on the License. It is a quality asset and we look forward to exploiting its full potential through future drilling activity.”


Contact Geoff Gander Chairman and CEO Jupiter Energy Tel: + 44 7974 241 412

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Sorochynska Following the recent award of its 20 year production license Hawkley is delighted to announce the results of the independent Resource assessment for Sorochynska. A petrophysical review of all the wells in the license areas, including core data has identified significant Contingent Resources in the Visean B17, B18, B19 and B22 sands as well as a Prospective Resource in the B24/25 carbonates. Table 1 shows the summary of Moyes & Co.’s assessment of unrisked Resources: The Contingent and Prospective Resources in the report are in addition to current 2P Reserves of 40.5Bcf in the B18 horizon from which the Company is currently producing. Table 2 shows the split of Reserves. Proved Developed Producing is the Sorochynska-201 well, with 6.3Bcf of Reserves remaining after production of 2.1Bcf to date. Ultimate recoverable from the pool is shown as 56Bcf, with 51Bcf remaining to produce.

The Resources identified in the B-17, B-18, B-19 and B-22 Sand intervals meet the test of Contingent Resources because the log responses, core properties, water resistivities, and reservoir characteristics in these sands are similar to the log responses in the Sorochynska 469, 110 and 201 wells that are productive in the B-18 Sand interval. The contingency in preventing the Resources from being considered Reserves is a well to confirm adequate permeability for commercial development.

While the B-24/25 interval has tested gas from three wells at significant, but sub-commercial rates, the Resources are considered prospective Resources because the B-24/25 reservoir interval has not produced commercially within the license and there is no production from a similar reservoir with similar log responses within the license.


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Based upon their assessment of Resources in the license, Moyes have run economics on a notional development plan. Production has been capped at 90mmscfd (million standard cubic feet of gas per day) on the assumption that the gas plant will be expanded to 3x30 mmscfd trains. The Moyes plan the 90MMCFPD plateau rate is maintained for approximately 10 years and provides a long term steady revenue stream.

Figure 3 below sets out the annual and cumulative net present value of cash flows for the combined Contingent and Prospective Resources under the Moyes development scenario.

Titan: Apr 26: TITAN TO INCREASE WORKING INTEREST IN EP-455 TO 18.5% SUBJECT TO APPROVAL OF WORK PROGRAM VARIATION Australian oil and gas exploration company Titan Energy

Limited (ASX: TTE) (“Titan Energy”) is pleased to announce it has reached agreement with the EP455 Joint Venture Operator and the Joint Venture partner AWE Limited (“AWE”), to jointly apply to the Department of Mines and Petroleum (“Department”) for approval to vary the work obligations on the EP-455 permit, located in the Perth Basin, by combining year 5 (year ended 21 June 2012) and year 6 (year ended 21 June 2013) to the intent that the relevant exploration well and the fraccing of it are to be completed by 21 June 2013 (“Variation”). The proposed variation will provide the joint venture with an extra twelve months to fulfil its work commitments by extending the latest timing for the drilling of the commitment exploration well in EP-455 to 21 June 2013.

If the Department approves the Variation, then in consideration for Titan Energy agreeing to the Variation, Titan Energy’s working interest in EP-455 will increase from 10% to 18.5%, and will be subject to the carry provisions outlined in the Sale and Purchase Agreement (“SPA”) dated 25 February 2010 up to a maximum of A$7.5 million. Once the carry provisions of the SPA are discharged, Titan Energy’s 18.5% interest will become a contributing interest.


Contact Richard Reavley Chief Executive Hawkley Oil & Gas Limited Tel: (08) 9429 8803

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Under the terms of the Variation, which remains subject to approval by the Department, AWE is to notify Titan Energy seven months before 21 June 2013 whether or not it will continue as the holder of an interest in the EP-455 and continue as Operator. If AWE does not give Titan Energy such notice on or prior to that date, AWE will be deemed to have agreed to continue to hold its 81.5% interest and to continue as Operator and will no longer have the right to withdraw from that Joint Venture under the terms of the original SPA or at all, until the work obligations are completed. Following acceptance of this offer and approval by the Department of the Variation, AWE will arrange for a new sale and purchase agreement to be prepared to record the sale and purchase of the additional 8.5% interest in the permit. Marion: Apr 26: MARKET UPDATE – CORPORATE RESTRUCTURING The Board of Marion Energy Limited (MAE, MAEOA) provides the following information relating to its corporate restructuring. As advised to the market on 14 October 2011, MAE’s management has continued to pursue appropriate restructuring and capital management initiatives for the Company to develop its assets and operations. MAE management has formulated and embarked on a three point turnaround plan with the assistance of 333 Capital, the Company’s corporate adviser. Step 1: Stabilisation. The Company has sought to focus on cash management initiatives, including procuring additional working capital funding of US$1.65m from a number of sophisticated investors, arranged by its corporate advisers 333 Capital and back-stopped by an affiliate of 333 Capital. This funding takes the form of an increase of the existing senior secured credit facility, in conjunction with which the Company has agreed to issue share options to the investors at an exercise price of A$0.006 per ordinary share (this being the last price at which the Company’s shares traded on ASX). The loan increase may be extinguished by the exercise of the share options. Certain of these arrangements are subject to shareholder approval, which will be sought in due course at a general meeting of shareholders. The Company will shortly dispatch further information to shareholders with the requisition of the general meeting of shareholders. Step 2: Value recognition. The Company has undertaken a number of initiatives to preserve and enhance value for shareholders. As announced on 16 December 2012, the Company obtained an independently assessed updated reserve report which reaffirmed the potential value inherent in the Clear Creek project. This report was prepared by MHA Petroleum Consultants and assesses the 3P reserves at 222 Bcf of gas of which 204 Bcf are in the 1P and 2P categories.The Company is also in the process of completing all steps necessary to apply to the ASX for reinstatement of trading in the Company’s securities. Relisting will be subject to ASX approval. Further details will be released to the market as this process progresses.

Step 3: Commercial development of the assets. The Company has entered into discussions with a number of interested parties regarding the future development of its gas assets at the Clear Creek Federal Unit and this process is currently ongoing. Outcomes being considered include seeking a farm-in partner to form a joint venture with the Company to bring the project into production. This may also involve a change of operatorship, with the incoming party becoming operator of the project. The Company will advise the market of progress as appropriate. New Standard: Apr 26: GOLDWYER PROJECT UPDATE Highlights Phase 1 exploration drilling remains on track to

commence mid 2012 Nicolay #1 prospect on EP456 chosen as first drilling

location Access track and site construction well underway MB Century Rig-14 has been mobilised to port of

Darwin Farm-in agreement amendments agreed with

ConocoPhillips Phase 1 drilling expenditure caps increased to US$13m

per well New Standard Energy Ltd (New Standard) is pleased to provide the following update on the company’s progress towards the commencement of Phase 1 exploration drilling at the Goldwyer Project in the Canning Basin, Western Australia. Planning, procurement, initial access and site construction and necessary approval activities are all progressing well in relation to the Phase 1 exploration program that currently remains on schedule to commence in mid-2012. The Goldwyer Project participants (New Standard and ConocoPhillips) have jointly identified and agreed the three drilling locations for the Phase 1 exploration program with all three wells heavily focused on data acquisition to provide proof of concept for the Goldwyer Project. Data will be acquired through a combination of full coring throughout the Goldwyer formation, sophisticated mud-logging and a comprehensive suite of electric wireline logs. Following data acquisition, a detailed set of scientific studies and analysis will be undertaken in specialised laboratories to more fully assess the Goldwyer formation prospectivity. The Nicolay #1 prospect, located on EP-456, has been selected as the first location for the Phase 1 drilling program. Well design and engineering have been completed and specifically tailored for the early stages of unconventional exploration. Nicolay-1 will be drilled to approximately 3,200m and is aimed at gathering a comprehensive understanding of the Goldwyer play through the intended acquisition and analysis of a substantial section of full core over the entire thickness of the Goldwyer formation.


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

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Contact Peter Collery Chief Executive Officer Marion Energy Tel: (03) 8862 6466

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The MB Century Rig-14, recently contracted by New Standard, has been mobilised from its previous contract location and has arrived at the port of Darwin. The rig will now undergo customs, quarantine and safety compliance inspections and once these inspections are complete it will be released to New Standard to be mobilised to the Nicolay -1 drilling location ahead of an intended July 2012 spud. Construction of the access roads, drill pad, camp site and air strip for Nicolay-1 is well underway and is currently on schedule to be completed before the arrival of the drilling rig on location. As operator of the Goldwyer Project, New Standard has been undertaking regular consultation with government regulators and Indigenous traditional owners to build awareness of the drilling program and communicate its commitment to responsible and safe exploration practices. Similar preparatory work is also underway for the second and third well locations (Gibb Maitland-1 and Blatchford-1 respectively) to ensure these locations are prepared ahead of intended inter-well moves which will occur following the completion of Nicolay #1 drilling operations. New Standard Managing Director Sam Willis said: “We are pleased with the way the planning and execution of the Phase 1 drilling is progressing. This drilling program will represent the first exploration activity in the southern Kidson Basin in more than 30 years so we are truly forging a new energy frontier. The second half of 2012 will provide exciting times for our shareholders as we move ahead with our Goldwyer drilling program and commence the early phases of exploring what could be a world class resource play.” Farm-in Agreement Update New Standard and ConocoPhillips have also agreed to amendments to the farm-in agreement executed in September 2011 that reflect changes to costs associated with Phase 1 activities including (but not limited to) the following: additional mobilisation and operating costs of the bigger

MB Century Rig-14 which has been contracted for the Phase 1 wells;

well design and well engineering that has been specifically tailored for detailed data acquisition during early stage unconventional exploration; and

expedited infrastructure expenditure being incurred during Phase 1 that will also be utilised in future phases of exploration and evaluation work

The agreed amendments include an increase to ConocoPhillips’ 100% funding cap for each of the three Phase 1 wells to US$13m per well (ie total funding cap of US$39m for Phase 1 drilling). New Standard will be required to fund the costs of any overruns in excess of these Phase 1 well caps (as is currently the case) and has also agreed to fund 25% of the scientific studies and formation evaluation work (estimated at a total joint venture cost of approximately US$5m). The increase in funding caps for the Phase 1 wells will not impact ConocoPhillips’ 100% capped expenditure commitments for Phase 2 (US$20m), Phase 3 (US$20m) or Phase 4 (US$40m) programs nor will it result in any adjustment to the project equities under the agreement. All conditions precedent to the farm-in agreement have now been either met or waived and the Phase 1 costs are now being borne in accordance with the revised terms of that agreement as outlined above.

“The amendments to the farm-in agreement reflect optimisation of the exploration program and farm-in terms to ensure comprehensive data sets are obtained during Phase 1 drilling to help establish proof of concept for the Goldwyer Project during these initial phases of exploration,” Mr Willis said. “The agreed amendments minimise New Standard’s potential exposure to Phase 1 drilling costs to amounts in excess of US$13m per well and highlight the strong working relationship between the parties and their commitment to work with each other to achieve the best exploration and evaluation plan for the Goldwyer Project,” Mr Willis said. Oilex’s Investor Presentation can be found here.


Contact Sam Willis Managing Director New Standard Energy Tel: (08) 9481 7477 Email: [email protected]

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http://www.oilex.com.au/


International Drilling Updates

Aloe Vera-3

Location Howard County, Texas

Equity

2029m. Intermediate casing successfully set and cemented.

Antares 100.00

Hunt Halliday 2-15-22H

Location North Dakota, USA

Equity

Drilling operations commenced 17 April 2012.

Emerald 7.50

Back to Index Naga Selatan-1

Location Mahakam Hilir PSC, Indonesia

Equity

234m. Drilling the 17 1/2” section.

SPC Mahakam Hilir 60.00 Cue 40.00

SL-20849-1

Location Louisiana, USA

Equity

TD 1448m. The main objective sand exhibited low permeability. Plugging operations should be completed over the next 24 hours.

Otis Energy 20.00

Shepard’s Channel Prospect

Location Lafourche Parish, Louisiana

Equity

4017m. Recovering assembly and liner.

Target 15.33

R.J. Perrin et al-1

Location Vermilion Parish, Louisiana

Equity

4358m. Set intermediate liner before DA with 8 1/4” bit.

Grand Gulf 7.83

Yucca-2

Location Howard County, Texas

Equity

1347m. Intermediate casing successfully set and cemented.

Antares 100.00


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

05-04-12 Spudded 05-04-12 Drilling 36” hole to first casing point

PTD 5500m

25-04-12 2822m making up 12-1/4” BHA prior to drilling ahead

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 06-04-12 Operations commenced following rig acceptance 26-04-12 Operating on location

KETU-2 PRL-21 Papuan

Horizon Parker Rig-226

06-04-22.66 S 141-51-40.93 E

Horizon 45.00

Talisman 40.00 Kina 15.00

06-03-12 Spudded 06-03-12 Drilling surface hole prior to running and setting 18-5/8” casing

Testing recovered liquids rich gas with no water

PTD 3824m

12-03-12 1256m and DA in 17-1/2” hole after setting 13-3/8”

19-04-12 Continuing after running 9-5/8” casing at 2545m

03-04-12 2550m pressure testing BOPs prior to DA in 8-1/2” hole

casing at 1181m

producer or gas re-injection well 23-04-12 TD 3787m running 7” liner to complete as future gas

DAVENPORT-1 PEL-94 Cooper

Beach Ensign Rig-918

28-47-55.30 S 139-59-17.24 E

Beach 50.00

Strike 35.00 Senex 15.00

18-04-12 Due to spud late Apr

PTD 2458m

MOONTA-1 ST1 PEL-218 Cooper


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

Mud log data indicates well is gas saturated through Permian target zone, from the Toolachee to the base of the Patchawarra formation. Section covers multiple intervals over a target zone of greater than 1km

PTD 3800m

07-03-12 2924m wait on weather to re-establish access to site 22-03-12 Waiting on weather 04-04-12 3456m and DA in Patchawarra formation 13-04-12 Continuing 24-04-12 TD 3810m evaluate and suspend for frac stimulation

MOREYS-1 PEP-169 Otway

Lakes Hunt Rig-2

38-29-00.00 S 142-53-02.00 E

Lakes 49.00

Armour (farm in) 51.00

20-04-12 Spudded 26-04-12 735m and DA through Dilwyn formation

PTD 2000m

Cont’d next page


WELL TICKETS 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

Elevated gas readings encountered in the Toro A sandstone, while initial data interpretation indicates the Koi-Iange sandstone is water wet

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

05-04-12 2479m prepare to run 9-5/8” casing 12-04-12 2479m prepare to cement 9-5/8” casing

TALAQ-1 PEL-516 Cooper Senex MB Century Rig-3 28-16-39.95 S 140-56-12.88 E

Senex 100.00

10-04-12 Spudded 11-04-12 Drilling ahead to surface casing depth at 800m 18-04-12 796m nippling up BOPs after setting 9-5/8” casing

PTD 2947m

SOUTHEND-1 PEL-107 Cooper


28-05-12.60 S 139-42-18.57 E

Beach 40.00

Drillsearch 60.00

17-04-12 Spudded

PTD 2912m

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 Drilled 435m of target carbonate reservoir to date, with gas and con-densate shows observed along entire interval

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

TIGERCAT-2 PEL-104 Cooper

Senex Ensign Rig-948

27-32-36.45 S 139-37-36.44 E

Senex 60.00

Beach 40.00

18-04-12 Due to spud late Apr

PTD 1850m

THISTLE-1 VIC-P-43 Otway Origin Stena Clyde 38-57-59.85 S 142-53-27.74 E

Origin 67.23 Benaris 27.77 Toyota Tsusho 5.00

19-04-12 Spudded

PTD 2559m

26-04-12 Continuing

VUCKO-1 WA-433-P Exmouth Woodside Ocean America 21-10-24.00 S 113-07-24.00 E

Woodside 70.00 Mitsui 30.00

16-04-12 Spudded 26-04-12 Continuing

PTD 3300m

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Pex Publications - oil & gas insider · 2019-03-28 · Pex Publications Pty Ltd. 5/1 Almondbury...

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Transcript of Pex Publications - oil & gas insider · 2019-03-28 · Pex Publications Pty Ltd. 5/1 Almondbury...