SOCO International plc ("SOCO" or the "Company")

 

HALF YEAR RESULTS

SOCO International plc, an international oil and gas exploration and production company with interests in Vietnam, the Republic of Congo (Brazzaville), the Democratic Republic of Congo (Kinshasa) and Angola, announces its Half Year Results for the period ended 30 June 2011.

 

HIGHLIGHTS

  • Te Giac Trang (“TGT”) produced First Oil at 06:55h local time on 22 August; plateau production during Phase I is expected to be approximately 55,000 barrels of oil per day (“BOPD”)
  • The TGT Full Development Plan has been approved by PetroVietnam;  including preparations for Phase II development drilling in the second half of 2011 which should add approximately 40,000 BOPD to TGT plateau production when it comes on stream in August 2012
  • The Te Giac Den licence extension has been granted by the Government of Vietnam; seismic acquisition will commence later this month
  • A three well exploration campaign is due to commence offshore Congo (Brazzaville) in early September 2011
  • SOCO’s cash and cash equivalents at 30 June 2011 were $213.1 million

 

ENQUIRIES:

SOCO International plc
Roger Cagle, Deputy Chief Executive and Chief Financial Officer
Tel: 020 7747 2000

Pelham Bell Pottinger
James Henderson
Victoria Geoghegan
Tel: 020 7861 3232


CHAIRMAN AND CHIEF EXECUTIVE’S STATEMENT

The primary focus for the first half of 2011 was preparation for the start up of production at the Te Giac Trang (“TGT”) field, offshore Vietnam.  TGT is by far the largest production project that the Company has ever been involved in and no small project by any metric.  The fact that initial production began on 22 August 2011, just days from the targeted date set two years ago is a testament to the hard work invested in the project by SOCO, its partners and the staff of the Hoang Long Joint Operating Company, which is operator of the project.

The TGT field development and product characteristics differ considerably from the Ca Ngu Vang field (“CNV”), also offshore Vietnam, which has been producing for the past two years.  CNV produces a highly volatile oil from Basement with a high gas to oil ratio (“GOR”) via the facilities at the Bach Ho oilfield.  Field exploitation depends on fracture interconnectivity to efficiently deplete the reservoir.  TGT by contrast has a significantly lower GOR and produces from a much shallower Clastics sandstone reservoir, with a series of sand/shale intervals.  Oil is produced into a dedicated Floating Production Storage and Offloading Vessel (“FPSO”).  Gas will be sold via the same Bach Ho interconnection as that which handles gas from CNV.

TGT is currently producing at approximately 16,000 barrels of oil per day (“BOPD”).   Production is expected to ramp up to test the name plate capacity, 55,000 BOPD, of the FPSO by year end.  A sales contract has been signed for the first two cargoes of TGT pre-assay crude to be sold to Vitol at a modest premium to Brent.  After assay results are confirmed, expectations are that the crude would fetch a higher premium.

Elsewhere in Vietnam, we were granted an extension to the appraisal period for Te Giac Den (“TGD”) where exploration drilling has thus far produced mixed signals.  A focused 3D seismic acquisition programme will be conducted over the area in the second half of this year.  Should the seismic offer encouragement, we would expect to drill another well before the extension expires at the end of October 2012.

The first well of up to a three well exploration programme offshore Congo (Brazzaville) is expected to spud in early September and drill a pre-salt target on the Marine XI Block with estimated pre-drill unrisked mean recoverable resources of 165 million barrels.  The rig is currently under tow, following a refurbishment in South Africa.  A 2D seismic acquisition programme on the Nganzi Block, onshore the Democratic Republic of Congo, is planned for the fourth quarter 2011, focusing on the Chela formation.  Should we get encouragement from the seismic interpretation, we anticipate phase II drilling to commence in the summer of 2012.

First half 2011 after tax profit from continuing operations was $6.8 million. This compares to $3.7 million after tax profit from continuing operations for the same period last year.  Capital expenditures were $65.0 million for the first half of 2011 ($51.6 million in the first half of 2010).

As we are in the early stages of production from TGT with work just starting on Phase II development and beginning another extensive exploration cycle, the Directors do not recommend a dividend.


OPERATIONS

VIETNAM
Block 16-1, Te Giac Trang (“TGT”)

Activity in the Cuu Long Basin, offshore Vietnam, during the first half of 2011 was primarily directed towards bringing the TGT field onstream culminating in the first flow of crude oil and wet gas on 22 August 2011. The field is currently producing at 16,000 BOPD with plateau production anticipated to be c.55,000 BOPD and gas production approximately 30 million cubic feet per day.

During the first half of 2011, in the lead up to First Oil, Phase I development drilling continued on TGT and was concluded with the completion of the four “batch” drilled development wells, TGT-4P to -7P, and the start and completion of the eighth development well, TGT-8P. The resulting petrophysical analysis has indicated that the wells confirm the reservoir model. 

The final stages of preparation for First Oil included the installation of the topsides on the jacket on the wellhead platform on TGT’s H1 area and the deployment of the FPSO, the Armada TGT 1, which arrived on location in July.  The vessel has undergone 22 months of conversion work by BAB-VSP, a joint venture between BAB Armada and Vietsovpetro, in the Keppell Shipyard in Singapore.  At name plate capacity, the FPSO is capable of processing 55,000 BOPD and 45,000 barrels of water per day and storing 620,000 barrels.

TGT’s Full Development Plan was approved by the Government of Vietnam in May 2011 and incorporates the accelerated Phase II development with installation of a second unmanned production platform on the H4 fault block. The installation of the H4 jacket is now complete and the drilling deck installed. The topsides are being constructed in Vietnam for installation in early 2012. Phase II development drilling is expected to commence in September 2011 and production in the summer of 2012.

Block 16-1, Te Giac Den (“TGD”)

The Government of Vietnam’s agreement to the extension period for the TGD Appraisal area was also received in May 2011. The initial extension period is from 1 January 2011 to 30 April 2012.  An additional six months extension will be automatic (through 31 October 2012) in the event that the Company elects to drill a well. A seismic vessel has been identified and will commence acquisition later this month.

Block 9-2, Ca Ngu Vang (“CNV”)

At the CNV producing field in Block 9-2 offshore Vietnam, operated by the Hoan Vu Joint Operating Company, Vietsovpetro, the operator of the Bach Ho processing facilities, will install additional dedicated test separation facilities on the Bach Ho central processing platform complex in order to more accurately measure liquid and gas production from the CNV production stream entering the Bach Ho facilities.  The benefit to the Company will be a more accurate allocation of CNV oil, gas and gas liquids production within the Bach Ho production system. During the first half of 2011, CNV production net to the Company’s interest has averaged 2,339 barrels of oil equivalent per day (“BOEPD”). 

 

AFRICA

REPUBLIC OF CONGO (BRAZZAVILLE)
Marine XI and Marine XIV

Preparations continued during the first half of 2011 to drill up to three exploration wells offshore Congo (Brazzaville), with the first well due to spud in early September.  The ENSCO 5003 rig has been contracted and refurbished and is currently en route to the Lower Congo Basin. The initial well will drill a pre-salt target on the Marine XI Block with estimated pre-drill unrisked mean recoverable resources of 165 million barrels and should take approximately 45 days to drill. The second well will target the Miocene interval above the salt layer on the Marine XIV Block.  With pre-drill unrisked mean recoverable resources of 40 million barrels, the well should take approximately 30 days to drill.

If the first well is successful, an appraisal well is expected to be drilled on the pre-salt target.  If not, the final well in this exploration programme will be drilled on a Miocene target in the Marine XI Block with 70 million barrels of pre-drill mean unrisked recoverable resources.

 

DEMOCRATIC REPUBLIC OF CONGO (KINSHASA) (“DRC”)
Nganzi

Further evaluation of the Nganzi Block, onshore the DRC, incorporating information gathered in the 2010 drilling programme has been completed and indicates remaining prospectivity in the Chela formation. A second 2D seismic acquisition programme is planned for the fourth quarter of 2011, with possible drilling in 2012 prior to the end of the initial exploration period.

Block V

The security review over Block V in the Albertine Rift in the DRC is ongoing.  The Company’s initial environmental and social impact assessment (“ESIA”) was submitted to the Groupe d’Etudes Environnementales du Congo in March 2011 and following a period of review and consultation with stakeholders, including various departments within the Government of DRC, a final ESIA was submitted in May and was later approved.  An aeromagnetic and aerogravity survey will be conducted later this year and a seismic programme over Lake Edward is planned for early 2012.

 

ANGOLA
Cabinda
North

The seismic acquisition programme that recommenced in May 2010 was completed towards the end of the first half of 2011. Processing of the data has commenced. No drilling is anticipated in Cabinda during the remainder of 2011.

 

FINANCIAL RESULTS

 Ahead of the commencement of production from the TGT field the financial results for the six months ended 30 June 2011 reveal a Company poised to dramatically change its scale of operations in the second half of the year.  Capital expenditure during the period has been focused on the TGT development, which came onstream on 22 August 2011.  The income statement, which, in the first half of 2011 comprises continuing operations from the CNV field, will see a major step-change with the TGT field production expected to to reach 55,000 BOPD by year end.  Despite this capital intensive period the Group continues to hold significant cash balances to enable it to continue its exploration activities elsewhere, especially in its Africa region.  Operating inflows from the TGT field will further add to the Group’s capacity to explore in new areas.

 

INCOME STATEMENT
Operating results

In the first half of 2011, SOCO’s oil and gas revenues from continuing operations, which are all derived from the Group’s CNV field were higher than the equivalent period last year at $26.4 million (six months to 30 June 2010 - $19.4 million).  During the first six months of 2011, the Group realised an average price, on continuing operations, of $118.09 per barrel of oil sold compared with $82.71 per barrel in the first half of 2010 and an average price of $0.74 per million BTU ($0.96 per thousand standard cubic feet) of gas sold, down from the contractual price of $0.93 per million BTU due to a high hydrogen sulphide content which was rectified in August.  The Group’s working interest share of production during the period was 2,339 BOEPD up from 2,200 BOEPD in the first half of 2010 due primarily to both planned and unplanned repair work which led to shutdowns on CNV during the prior period.

Cost of sales on continuing operations in the period was $11.6 million for the six month period to 30 June 2011 up from $4.4 million in the first half of 2010.  This increase is mainly associated with a net reduction in oil inventory in the current period of $3.0 million, valued at market price, compared to an increase in oil inventory of $2.7 million in the first half of 2010 and also includes the impacts from the shutdowns mentioned above. The reduction of $3.0 million is the net of a reduction in opening oil inventory entitlement since inception of production of $10.3 million and an increase in oil inventory of $7.3 million during the period, which includes the effects of increased oil prices.  On a per barrel basis, excluding inventory movements, depreciation, depletion and decommissioning costs (DD&A) and royalties, continuing operating costs were approximately $10.00 per barrel compared with $7.20 per barrel in the first half of 2010.  This increase on a per barrel basis is mainly due to higher non-volume related production costs in particular well intervention costs.

DD&A included in cost of sales was $3.0 million for the current reporting period being the same as in the first half of 2010 consistent with similar entitlement production. On a per barrel basis, DD&A decreased slightly from approximately $7.40 per barrel in the first half of 2010 to approximately $7.00 per barrel in the six months ended June 2011.

Administrative costs relating to continuing operations for the first six months decreased from $4.2 million in 2010 to $3.6 million in 2011.  The decrease is primarily attributable to higher direct employee costs incurred in the first half of 2010. 

Operating profit from continuing operations for the period was $11.3 million arising from the Group’s production operations in Vietnam, compared to $10.8 million for the first half of 2010.

Non-operating results

Other gains and losses increased from $0.4 million in the first half of 2010 to $2.8 million in the current reporting period mainly due to a higher gain in the fair value associated with the subsequent payment amount tied to future oil production from the Group’s divested Mongolia interest.

Tax

The tax expense decreased slightly from $7.9 million in the six month period ending 30 June 2010 to $7.7 million in the current reporting period.  Although current taxation has increased consistent with the higher profit in the period, the reduction in deferred tax, arising from timing differences associated with cost recovery, has more than offset the higher current tax charge.

 

BALANCE SHEET

Intangible assets increased by $18.3 million since year end 2010 and by $36.0 million since 30 June 2010 reflecting the exploration activity in the Group’s Africa region, in particular drilling activity in the Nganzi Block and seismic acquisition in the Cabinda North Block.  Property, plant and equipment increased by $53.4 million since the 2010 year end and by $122.1 million over the last 12 months almost entirely due to the TGT field development.

SOCO’s cash and cash equivalents at 30 June 2011 were $213.1 million (31 December 2010 - $260.4 million and 30 June 2010 - $258.1 million).  This reduction is a result of the Group’s TGT development programme and exploration activity in Africa, as described above, offset by cash inflows from production operations in Vietnam.    

As at 30 June 2011, the Group’s only debt was the convertible bonds with a par value of $84.0 million, following the redemption at the option of each bondholder in May 2010 of bonds with a par value of $166.0 million. Further details of the bonds, which were originally issued in 2006 at a par value of $250 million, are in Note 23 to the 2010 Annual Report and Accounts.  If the bonds have not been previously purchased and cancelled, redeemed or converted, the remaining bonds will be redeemed at par value on 16 May 2013.

Long term provisions comprise the Group’s decommissioning obligations in South East Asia which have increased to $22.6 million from $11.2 million at 30 June 2010 and from $13.1 million at year end 2010. This reflects the installation of facilities and development well drilling activity at the TGT field prior to commencement of production operations. Further, the balance at 30 June 2010 included a provision for decommissioning the Group’s Thailand asset, the sale of which completed in September 2010.

 

CASH FLOW

Net cash flows from operating activities for the first six months of 2011 comprise the Group’s continuing Vietnam operations and amounted to $13.2 million compared to $5.7 million (from continuing operations) in the first half of 2010.  This increase is mainly due to working capital movements, in particular inventory movements as described above.  Capital expenditure for the period ending 30 June 2011 was $65.0 million compared with $51.6 million in the equivalent period last year (which included $9.9 million relating to the Group’s disposed of Thailand asset).  The increase reflects the continuing TGT field development programme.  There were no cash flows arising from financing activities in the current period.

Production

During the first half of 2011 the Group’s production, net to the Group’s working interest, of 2,339 BOEPD was sourced entirely from its CNV field compared to the first half of 2010 when total production was 5,191 BOEPD sourced from its CNV field (2,200 BOEPD) and its now discontinued Bualuang field in Thailand (2,991 BOPD). The CNV field production was also higher than its full year 2010 volume of 2,257 BOEPD, mainly due to reduced 2010 production due to a stuck pipeline inspection gauge.

Related party transactions

There have been no material related party transactions in the period and there have been no material changes to the related party transactions described in Note 31 to the Consolidated Financial Statements contained in the 2010 Annual Report and Accounts. 

Risks and Uncertainties

There are a number of potential risks and uncertainties which could have a material impact on the Group’s performance over the remaining six months of 2011 and could cause actual results to differ materially from expected and historical results.  Risks and uncertainties that remain unchanged from those published, along with their mitigation, in the 2010 Annual Report and Accounts are summarised below:

  • Credit risk – in respect of the Group’s financial asset at fair value through profit or loss arising on the Group’s disposal of its Mongolia interest and short term financial assets.
  • Foreign currency risk – associated with cash balances held in non-US dollar denominations.
  • Liquidity risk – associated with meeting the Group’s cash requirements.
  • Interest rate risk – applicable to the Group’s cash balances, debt and financial asset.
  • Commodity price risk – associated with the Group’s sales of oil and gas.
  • Regulatory risk - arising in countries where the Group has an interest, including compliance with and interpretation of taxation and other regulations.
  • Contractual risk – in relation to contractual terms that may be subject to further negotiation at a later date.
  • Capital risk management – in relation to Group financing.
  • Reserves risk – associated with inherent uncertainties in the application of standard recognised evaluation techniques to estimate proven and probable reserves.
  • Exploration risk – as exploration for, and development of, hydrocarbons is speculative and involves a significant degree of risk, the Group’s future value is materially dependent on the success or otherwise of its activities which are directed towards the search, evaluation and development of new oil and gas resources.
  • Partnership risk – associated with the requirement to delegate a degree of decision taking to partners, contractors and local personnel, in particular where SOCO is not the operator.
  • Reputational risk – associated with the conduct of oil and gas activity in locations where social and environmental matters may be highly sensitive both on the ground and as perceived globally. 
  • Political risk – due to location of the Group’s projects, often in developing countries or countries with emerging free market systems.
  • Health, safety, environment and social risks – arising due to the nature and location of the Group’s activities.

Further information on the above principal risks and uncertainties of the Group is included in the Financial Review section of the 2010 Annual Report and Accounts and in Notes 3 and 4 to the Consolidated Financial Statements in that report.

In addition, the Company recognises its responsibilities in relation to the UK Bribery Act 2010 which came into force on 1 July 2011 and introduces a new corporate offence for acts of bribery orchestrated by its employees, agents and other associated persons.  The Group seeks to mitigate the associated risks by ensuring it has appropriate procedures in place to prevent bribery and that all employees, agents and other associated persons are made fully aware of the Group’s policies and procedures.

 

GOING CONCERN

The Group has a strong financial position and, after making enquiries, the Directors have a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future. Consequently the Directors believe that the Group is able to manage its financial and operating risks and, accordingly, they continue to adopt the going concern basis in preparing the Half Year Report.

 

CORPORATE

Board

In June, the Company announced that Mr Peter Kingston and Mr Martin Roberts retired from the Board as Non-Executive Directors of the Company following the Annual General Meeting.  Mr Kingston served as Chairman of the Audit Committee, Chairman of the Remuneration Committee and as the Company’s Senior Independent Director.  Mr Roberts served as a member of the Audit and Remuneration Committees.  The Board thanks Mr Kingston and Mr Roberts for their significant contributions to SOCO.  Mr John Norton has succeeded Mr Kingston as Chairman of the Audit Committee.

Further to the above retirement, Mr Michael Johns was appointed as a Non-Executive Director. Mr Johns serves as the Senior Independent Director, the Chairman of the Remuneration Committee and a member of the Audit Committee.  Mr Johns has had a distinguished career in legal practice with two international law firms and has extensive experience in a broad range of practice areas, including commercial, corporate, corporate finance and energy law. Mr Johns graduated from Oxford University in 1969 and qualified as a solicitor in 1972.  He was a partner at Withers (as it then was) from 1974 until 1987 and joined Ashurst LLP (“Ashurst”) as a partner in 1987 where he was the Head of the Energy, Transport & Infrastructure Department from 2001 until 2005.  Mr Johns retired from Ashurst in April 2009 and remained as a consultant to Ashurst until April 2010.  From August 2006 until February 2011, Mr Johns served as a Non-Executive Director of Aer Lingus Group plc.

 

OUTLOOK

TGT production has just begun and the ramp up to plateau production is expected to take a number of weeks.  During this period, it would not be unusual to experience some unexpected issues that would normally be associated with any start-up of a project of this size.

However, the Company’s transition from one of limited production to expectations of substantial production bodes well for the future to support its exploration led strategy.  Whilst the upcoming exploration programme offshore Congo (Brazzaville) offers significant upside potential, it will be modest in terms of overall capital expenditure and activity when compared with past exploration programmes and those expected in the future. 

We expect to commence drilling TGT Phase II development wells in September, with planned production to commence in the summer of 2012.  Once there is a reasonable history of production performance on Phase I and some subsurface confirmation from Phase II, we anticipate revisiting the reserve numbers.

In the meantime, the Company looks to increase its exploration portfolio by focusing on expanding its footprint in areas where it can apply its significant technical experience and knowledge.

 

Rui de Sousa
Chairman

Ed Story
President and Chief Executive Officer

 

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