Proactiveinvestors Australia

Sun Resources NL (SUR) is an ASX-listed oil and gas company with exploration properties onshore East Texas and producing properties onshore South Texas, USA, plus a 42.5% interest in Block L20/50, onshore in Thailand.  Sun Resources NL’s primary asset and future focus is its Delta Oil Project, with up to 10,000 acres of oil and gas leases in Leon County.  Sun has a 100% working interest in all leases, delivering a 75% net royalty interest.  Sun is targeting the Eaglebine oil production, the oil-rich fairway of the Eagle Ford Shale trend where it transitions to the Woodbine sand play.

The Board and Management of Sun Resources NL (“Sun Resources”, “Sun” or “The Company”) focused its efforts on maintaining and funding its material interest in the Thailand L20/50 exploration block during the reporting period.  That effort delivered a 42.5% working interest in a multi-well exploration drilling program with two significant prospects being tested during the March quarter of 2011.  This level of activity was polarised against an ongoing, perhaps endemic, lack of farm-in interest in conventional oil and gas prospects in the onshore Gulf of Mexico in the United States of America.  With interest so heavily focused on the perceived lower risk, unconventional shale oil and gas plays, there is little likelihood that interest in more risky conventional prospects will climb back to pre-2008 levels in the near term, and not before domestic gas prices in the USA recover from the low range experienced in the last three years.

In the international arena, there has been a lack of new licensing round activity in Thailand, and adjacent countries, thereby limiting the potential for acquiring high impact exploration opportunities in SE Asia.  The growth strategy of Sun Resources has therefore shifted toward those same unconventional resource plays of the USA and to higher potential, conventional exploration plays in Europe and Africa.  In this reporting period, several high quality opportunities have been reviewed in detail, with the NW Europe prospect and the Eaglebine play being the two high-graded and approved.  The Board and management remain committed to building a portfolio of high quality international exploration opportunities like those presented in these pages,  with the focus continuing to be oil and/or high rate gas prospects in strong markets, close to infrastructure.

Delta Oil Project

The Board of Sun Resources announced on 26 August 2011 that it had entered into a binding Term Sheet with a Houston based, private oil and gas company (“Vendor”), to acquire up to 10,000 net acres of oil and gas leases (Delta Oil Project), all located within the oil zone of the Eagle Ford Shale trend in Texas, USA. Sun Resources will acquire 100% working interests in all of the leases, each with a minimum 75% net revenue interest, a three year lease term and in most instances, also have a two year option to extend the lease term.  Sun Resources will work with the Vendor to acquire up to 10,000 acres however, less than 10,000 acres may ultimately be acquired.  The numbers used throughout this section of the Annual Report are based on the acquisition of the full 10,000 acres.

The Delta Oil Project leases are located in the rapidly expanding new ‘Eaglebine’ play within the overall Eagle Ford Shale trend in Houston, Madison, Leon and Robertson Counties, Texas. In this new resource play, horizontal, fracced wells have obtained significant oil production from brittle, sandy units (Woodbine Sands) near the base of the Eagle Ford Shale at relatively shallow depths.  Recent horizontal wells within 35 miles of the Delta Oil Project have obtained initial flow rates of 900 to 1,200 barrels of oil per day from multi-staged fracced laterals of 6,000 to 7,000 feet in sandstone units and operators are reporting Estimated Ultimate Recoveries (EUR) of 300,000 to 600,000 barrels of oil per well. These results are comparable to wells in the Eagle Ford Shale oil zone in the well known producing areas. In addition, the Eaglebine target reservoir depths of 5,000 to 8,000 feet are shallower than typical Eagle Ford Shale wells resulting in materially lower well costs which should significantly improve the net present value (NPV) of individual wells. 

Early recognition of the potential of the emerging Eaglebine play by the Vendor has enabled Sun Resources to acquire a substantial lease holding at lease costs significantly lower than those in the well known areas of the Eagle Ford Shale oil trend. Utilising information from old vertical wells situated within the boundaries of the leases and recent horizontal well production history from nearby Eaglebine producing wells, independent Houston based petroleum engineering and geological consultants, Ralph E Davis Associates Inc. (Ralph E. Davis) has estimated unrisked net Prospective Resources within the Delta Oil Project of 10 million barrels of oil from one sand unit and potential upside of a further unrisked 10 to 20 million barrels of oil from other sand units within the 450 feet thick target zone.  The Ralph E. Davis net Prospective Resource estimate uses the following assumptions:

• a total of 30 wells spaced at 320 acres (i.e. 30 wells across 10,000 acres);
• each well with an Initial Production (IP) rate of 700 barrels of oil per day (Bopd);
• each well with an EUR of 452,000 barrels of oil (bo) per well from one 20 feet thick sand unit located over all of the Delta Oil Project area;
• oil at US$90 per barrel and gas at US$4 per thousand cubic feet (Mcf) held flat for the well life of 30 years; each well has a productive life of 30 years;
• capital cost of US$6 million per well; and operating costs of US$10,000 per month per well.

Assuming production of the 10 million barrels of Prospective Resources, Ralph E. Davis estimated the NPV of the Delta Oil Project of US$310 million which equates to:

• NPV of US$10,333,333 per well; and
• NPV of US$31 per barrel of oil for 10 million barrels of oil from one 20 feet thick sand unit.
• Based on 10% discount rate, net of royalties, operating costs but excluding corporate taxes

Thailand

The L20/50 permit lies in the onshore Phitsanulok Basin, located between Thailand’s two largest producing onshore field complexes, being the basin immediately west from Carnarvon Petroleum Limited’s Phetchabun Basin Oil Fields (producing up to 15,000 bopd with >60 mmboe estimated ultimate recovery) and 20 kilometres south, in the same basin as the prolific Sirikit Oil Field (producing ~20,000 bopd with >200 mmboe estimated ultimate recovery).  The L20/50 Joint Venture exploration program is targeting a resource of similar size to that of Carnarvon and Pan Orient who are producing up to 15,000 bopd (with >60 mmboe estimated gross ultimate recovery) from a number of oil pools in both the “new volcanic play” and in traditional sandstone reservoirs, in the adjacent Phetchabun Basin, 50 kilometres to the east.  The primary reservoir target within L20/50 and in the prospects tested with the two wells of the exploration drilling program is the traditional sandstone reservoirs that produces most of the oil from the prolific Sirikit Oil Field and is present in multiple levels in the Nong Bua #1 well within L20/50.

As a precursor to the 2009 2D seismic survey, Carnarvon Petroleum Limited (Carnarvon), the Operator of L20/50, evaluated the petroleum system within the L20/50 Block by utilising digitised 2D seismic data.  This work resulted in the delineation of 13 significant structural leads.  The mapped leads vary in size, but preliminary calculations by Sun Resources indicate the largest of the leads could contain a gross, speculative resource potential in excess of 150 million barrels of oil in place.  These structural leads were the focus of the [2009] Year two seismic survey which was aimed at better defining the size and potential oil resources contained within each lead.  After acquisition and interpretation of the new 550km of 2D data, Carnarvon had identified 23 leads and prospects within five different play types over an area of 548km2 covered by the seismic survey.  Good quality seismic data was the key to Carnarvon unlocking the potential of its adjacent Phetchabun Basin Oil Fields in the fractured “volcanic play”.

The three highest-ranked prospects were selected for drilling; with the potential to test in excess of 90 mmbo of gross, recoverable speculative potential, if all three wells are drilled, in three different structural trap styles. Each well was expected to take approximately two to three weeks to drill and complete, with each well testing multiple reservoir horizons where the potential for stacked oil pools exists.  During the third quarter of 2010, Carnarvon received environmental approval for up to nine well locations and Sun Resources  agreed with the Operator, Carnarvon, to increase the number of firm wells drilled in the maiden drilling programme to two, with one additional well to be considered based on the results of the first two firm wells.  Site construction of the three well locations commenced during the fourth quarter of 2010 and was largely complete early in the first quarter of 2011.

Subsequent to the end of the 2010 calendar year, the Asian Drilling Co. Rig #1 was mobilized to the first well site (Tapao Kaew #1), with the well spudded on 31 January 2011.  The Tapao Kaew #1 well was drilled to test the Tapao Kaew Prospect, a 4-way-dip anticlinal structure with stacked targets on the western edge of the basin, immediately adjacent to the interpreted hydrocarbon kitchen.  The Joint Venture estimated the Tapao Kaew Prospect to have a gross speculative potential resource of 21 million barrels. The Tapao Kaew #1 well tested three separate mapped horizons between 700 metres and total depth of 1,792 metres.  The well has been plugged and abandoned by the Operator, after 22 days on location, as it failed to encounter hydrocarbon-bearing reservoirs.  The second well drilled in the multi-well drilling program was the Krai Thong #1 well, on the Krai Thong Prospect, a faulted anticlinal structure with multiple stacked targets.  The Joint Venture estimated the Krai Thong Prospect to have a gross speculative potential resource of 37 million barrels.  The Krai Thong #1 well targeted two separate mapped horizons between 600 metres and total depth at 1,294 metres and, despite recording some minor oil shows while drilling, wireline testing of several zones of potential hydrocarbon bearing intervals proved water as the mobile fluid phase.  The well was plugged and abandoned after 20 days on location and the drilling rig was released on 21 March 2011.  The lack of commercial success led the Joint Venture to the decision to release the rig and defer the drilling of Chalawan #1 to a later date.  The Joint Venture estimates the Chalawan Prospect to have a gross speculative potential resource of 32 million barrels.

Good quality sandstone reservoirs and thick, competent shale seals were identified from both of the exploration wells, as was a fracture network in apparent basement at the Krai Thong #1 well location.  The information acquired from the drilling of these two wells is being incorporated with previous drilling data into a revised seismic interpretation in order to determine the next phase of exploration for the block.  The completed well sites, including the unused well site at Chalawan #1, will be retained by the Joint Venture for possible future use.  The post-well evaluation work flow was continuing at the end of the reporting period.

Sun Resources executed a binding Participation Agreement with Peak Oil & Gas Ltd (“Peak”) on 21 December 2010 to allow Peak to earn a 7.5% working interest only in the first exploration well, Tapao Kaew #1 in L20/50, onshore Thailand.  Peak ‘free-carried’ Sun Resources for up to US$1.3 million of Sun Resources’ share of well costs in the drilling of the first exploration well, Tapao Kaew #1.  This allowed Sun Resources to commit to the multi-well drilling program and retain a material working interest in the exploration block.  Sun Resources retains a significant 42.5% interest in L20/50, providing maximum leverage to its shareholders in the ongoing exploration efforts for oil in Thailand.

The Joint Venture is now in Year 4 of the initial 6-year term and the work program for this permit year is ‘studies’.  Those studies will involve integrating the results of the two exploration wells to determine the next exploration activity, likely to be planning for the Year-5 exploration commitment; 100 sq.km of 3D seismic data acquisition.  At the time of writing this report, Carnarvon was continuing with its data integration studies.  The last outstanding obligation is the Year-6 commitment of two exploration wells.  As two wells were drilled at the end of Year 3, the Joint Venture is in credit so only one exploration well remains to be drilled to meet all commitments.

NW Europe

Sun Resources noted in its 2010 Annual Report that it was working to add new international exploration ventures beyond SE Asia and in particular in Africa and Europe.  The Board has reviewed a large number of opportunities over the ensuing 6-12 months and that review culminated in the announcement of a new exploration deal in onshore Europe.  Sun Resources announced on 10 November 2010 that a non-binding Term Sheet with an as yet undisclosed party (due to commercial sensitivities) had been executed for Sun Resources to participate in the drilling of a high impact well onshore North-West Europe which will test a 720 billion cubic feet (bcf)conventional gas exploration target.  Sun Resources will fund €1.645m (A$2.3m) of past and future drilling costs to earn a 15% working interest in the farm-in concession.  The principle terms of the farm-in are:

Sun Resources will pay €1.51m (approximately $2.1m) of the dry hole costs based on a €5.33m estimate (A$7.48m);

Sun Resources will pay 15% of total past auditable costs estimated at up to €900,000 (i.e. Sun Resources will pay approximately €135,000 (A$190,000));

Sun Resources will execute, subject to due diligence, a Definitive Farm-in Agreement by 30 November 2011, or if a rig contract is to be executed prior to that date, immediately prior to execution of the rig contract.

Sun Resources will then maintain its interest in the project on a heads-up (15%) basis.  Drilling is expected to commence late in the second quarter of 2012.  The primary play is Triassic sandstone reservoirs charged with gas (and/or oil) from older Permian-Carboniferous shales and coal, which is the principal play in the offshore Southern Gas Basin of the North Sea.  Geological modeling, based on 2D seismic and recent interpretation, indicates that gas (with gas liquids) is the most likely hydrocarbon to be found within the prospect, which has a gross target of 720 bcf of gas (Operator’s estimate), with upside in excess of 1 trillion cubic feed (tcf).  The prospect lies on trend with oil and gas fields and adjacent to old wells with oil and gas shows, around oil seeps.

In Europe, the gas market is robust due to the lack of alternative supplies, and as a result, the strong gas prices (US$7-9/mcf compared with US$4/mcf in the USA) are expected to continue into the foreseeable future.  This significant price advantage is one of the key reasons why Sun Resources has targeted this concession in North-West Europe that is prospective for hosting large gas accumulations.  The farm-in concession is also considered to have potential to offer an unconventional gas play within the older Permian-Carboniferous source rocks.  Permitting of the well began in early 2011 and at the time of writing, the permitting process is expected to be completed in Q3 2011. It is anticipated the well would be drilled in late Q2 2012, subject to government approvals.  The non-binding Term Sheet is subject to the completion of due diligence, the execution of a Definitive Farm-in Agreement, and receipt of relevant statutory approvals and governmental consents.

Negotiations between the Operator and the local government on the approval process of the well were continuing at the end of the reporting period.  Further details relating to this farm-in will be announced to the market following the receipt of necessary local government approvals.  A further extension to the end of November 2011 has been agreed between Sun Resources and the Operator to allow the Operator time to complete the well approval process with the local authorities.  This is an important condition precedent in the executed Term Sheet.

Australia

Sun Resources NL retains a 9.25% working interest in the WA-254-P, Block 2 Location that contains the Sage-1 oil discovery, in the Dampier Sub-basin of the offshore Northern Carnarvon Basin.  The Operator, Apache Northwest Limited (“Apache”), has applied for a retention licence over the single graticular block that covers the structure tested successfully by the Sage-1 exploration well.  At the time of writing this report, the designated authority was continuing with its assessment of the Joint Venture’s application for a retention license.  Apache continues to review development options, including tie-back potential to the nearby Wandoo field, in an effort to monetize the accumulation.  Sun Resources continues to market the combined interests of Sun Resources, FAR Limited and Senex Energy Limited with a view to selling their collective interests.

Malta

Sun Resources retains a 20% working interest in the offshore Malta Exploration Services Agreement (“ESA”) with Operator Pancontinental Oil & Gas NL (“Pancontinental”).  The permit is currently under “Force Majeure” while the border issues with Tunisia and Libya are resolved.  During the reporting period, Pancontinental met with the Malta Resources Authority (“MRA”) on two separate occasions to progress matters in relation to refreshing the title.  Pancontinental remains hopeful that the MRA will re-affirm title over the original area so that the Joint Venture can move forward with exploration activities.  Notwithstanding this, the Joint Venture continues to reserve its rights and potential remedies under the ESA.

Production Review

Sun Resources cumulative production from gas fields in Louisiana and Texas declined during the 2010-2011 financial year when compared with previous financial years.  All fields demonstrated decline due to natural pressure depletion.  Month-on-month production levels fluctuated as a result of intermittent shut-ins of the Jones Stewart Gas Unit #1 well in Texas, due to excessive levels of H2S.  The SL328 #9 well in Louisiana (“Lake Long #9”) performed profitably until it was shut in due to a leak in casing in February 2011.  A subsequent work over discovered the casing leak had been caused by high pressure water moving behind casing and into the producing gas reservoir.  The work over successfully shut off the water flow but it was deemed uneconomic to attempt a re-completion.  The well was subsequently plugged and abandoned on 22 August 2011.  The Flour Bluff field continued to produce, but high operating costs and low gas prices made production unprofitable for much of the reporting period.

Gross daily production from the three fields that Sun Resources holds varying working interest levels averaged 2.4 million cubic feet per day of gas (“mmcfg/d”) and 15 barrels of oil/liquids per day (bopd).  Sun Resources’ working interest share of production delivered an average of 0.35 mmcfg/d and 3.1 bopd net over the twelve month reporting period.  Net revenue for the six months to 31 December 2010 was positive US$42,191 but the net revenue for the six months to 30 June 2011 was negative US$35,836.  Production from the remaining US production assets is likely to remain unprofitable until new discoveries are made or domestic gas prices recover to sustained levels above US$5.00 per thousand cubic feet (“mcf”).  The Flour Bluff field still contains up to 21 billion cubic feet of 3P gas reserves and up to 345,000 barrels of oil reserves, net to Sun Resources and yet to be developed, but this requires further investment in 3D seismic and wells to move these to 1P reserves.  Furthermore, interest in shale gas development in Texas is likely to continue to subdue conventional exploration efforts such that it is unlikely that new activity will be undertaken in these mature production areas in the near term. 

Sun Resources will be working diligently to monetise the potential within the Delta Oil Project and bring on new and highly profitable oil production as quickly as possible.  The incentives offered to the Vendors of the Delta Oil Project include a milestone of 10 million barrels net oil reserves and 1,000 bopd net oil production within five years.  While this is a speculative forecast, it would deliver significant cash flow and enterprise value to Sun Resources, if achieved.  There is also scope for conventional gas exploration within deep, highly pressured reservoirs within the Delta Oil Project area which, if successful, would add additional profitable cash flow to Sun Resources.

Dr Wolf Martinick
Non Executive Chairman
B.Sc, Ph.D., FAIMM.

Dr Martinick was appointed to the Board on 19 February 1996 and became Chairman of the Board on 1 March 2011. Dr Martinick is an environmental scientist with extensive experience in the resource industry. For over 33 years he has been associated with the exploration and mining industry in Australasia, especially with respect to environmental, water, land access and Native Title issues. He is a Fellow and Chartered Professional of the Australian Institute of Mining and Metallurgy and a past Vice President of the Association of Mining and Exploration Companies.

In 2003, he became Executive Chairman of ASX listed Ezenet Limited, in 2005 Non-Executive Chairman and Director of AIM listed Weatherly International PLC and in 2006 Director of ASX listed Uran Limited and Azure Minerals Limited. He is also Chairman of MBS Environmental Pty Ltd, a company that provides environmental consultancy services to the resource industry.

Dr Govert van Ek

Managing Director

B.Eng (HONS), Ph.D, C.Eng, AIPN, SPE, SEAPEX 

Govert van Ek joined as Managing Director of Sun Resources NL in March 2013. He has 17 years of upstream oil and gas and related finance experience and has worked at upstream oil and gas companies and investment banks focusing on upstream oil and gas transactions and lending. He has worked on numerous upstream transactions in Europe, Asia and Australia. He was formerly CEO at Spyker Energy and Business Development Executive at Genting Oil and has gained a broad depth of experience with managing and financing junior oil companies. He also formerly worked at ANZ Investment Bank in London and Sydney and was head of upstream oil and as lending at BNP Paribas in Singapore, where he focussed on lending and corporate finance for junior oil companies in the Asia Pacific region. He started his career in 1996 at Shell International E&P as an operations engineer and also worked at Shell on oil and gas field development planning and economics. Govert graduated with a Doctorate from The University of Manchester, U.K, in Total Technology, has a degree in Mechanical Engineering and is a member of the American Institute of Petroleum Negotiators (AIPN), Society of Petroleum Engineers (SPE) and South East Asia Exploration Society (SEAPEX).

Mr Matthew Battrick

Executive Director, Technical

B.Sc. (Geol), MPESA, MPESGB, MAAPG, GAIDC.

Mr Battrick was appointed as Executive Director, Technical on 20 March 2013 and originally appointed to the Board on 15 January 2008 as Managing Director.  He obtained a Bachelor degree in Geology from the Royal Melbourne University of Technology (RMIT) in 1981. He has had a long, international career with both major and large independent oil and gas companies (LASMO, Ampolex, ExxonMobil, Eni) before joining ASX-listed Pancontinental Oil & Gas NL in 2004 as Exploration Manager, then General Manager. He is a Member of the Petroleum Exploration Societies of Australia and Great Britain, and a member of the American Association of Petroleum Geologists. He is also a member of the Australian Institute of Company Directors (AICD) and a graduate of their Company Directors Course (CDC). Matthew was a director of the Activ Foundation (Inc.), a Western Australian-based, non-government organisation for people with intellectual disabilities from 2001 to 2010.

Dr Philip Linsley

Non Executive Director

B.Sc. (Hons Geol) (London), Ph.D. (London), MBA (Kingston).

Dr Linsley is a well known United Kingdom based consultant who has had some twenty eight years experience in oil exploration and production in many parts of the world (Australia, South East Asia, Africa, America, Kazakhstan, Europe and the Middle East) initially in employment with Texaco and Mesa and later as a consultant to companies that include Occidental, Tricentrol, Ashland, Ranger, Svenska and Chase Manhattan Bank. Dr Linsley is a Non Executive Director whose primary role is to assist the Board in the acquisition of oil production and to investigate exploration opportunities outside Australia and Oceania.

Mr Damian Kestel

Non Executive Director

Mr Kestel was appointed to the board on 1 February 2012 as Non Executive Director. Mr Kestel has over 15 years research, sales and management experience in Asian equity capital markets, most recently with CLSA Asia-Pacific Markets for ten years, to whom he remains a consultant. He holds a Bachelor of Law degree with Honours from the University of Adelaide, a Bachelor of Commerce degree from the University of Western Australia and a Graduate Diploma in Securities and Investment from the Australian Securities Institute.

Mr John Kenny

Non Executive Director

B.Comm. (Hons), LLB.

Mr Kenny is a lawyer by profession. He holds a Bachelor of Commerce (Hons) and Bachelor of Laws from the University of Western Australia. Through his practise of corporate and mining law and investment banking, he has advised many ASX listed public companies in the areas of equity and debt finance. Mr Kenny has been a venture capital investor in several ASX mining floats. He also has experience in a number of sectors of Australian agribusiness with involvement both as a director and as an investor. He has been a director of a number of ASX listed public companies and is currently on the board of ASX listed public resource company Gippsland Limited (ASX Code: GIP).

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