Preliminary Results Mar 2012

SOCO, an international oil and gas exploration and production company, today announces its preliminary results for the year ended 31 December 2011.

HIGHLIGHTS

Financial Highlights 

• Record after tax profit from continuing operations of $88.6 million (2010: $12.3 million
• Record revenues of $234.2million (2010: $48.4 million) and operating cash flows of $90.2 million (2010: $12.4 million) from continuing operations
• Strong balance sheet with net cash at 31 December 2011 of $113.5 million (2010: $182.5 million)
  
  

Operational Highlights

•  Te Giac Trang (TGT) field, offshore Vietnam brought into production in August 2011 - on schedule and on budget. Achieved approximately 40,000 barrels of oil per day (BOPD) and preparing for staged production increase
• Total production net to the Group's working interest from continuing operations during 2011 was 5,437 barrels of oil equivalent per day (BOEPD) (2010: 2,257 BOEPD)
• Current net entitlements production at approximately 17,300 BOEPD
• Phase II development drilling at TGT commenced in October 2011. Production start up anticipated for August 2012
  
  

Outlook

• Exploration to remain core to the Company's growth strategy with plans to add several high potential projects

 

 Ed Story, President and Chief Executive Officer of SOCO, commented:

 "The past year has been a transformational period for SOCO with production commencing from what is clearly a world class field in TGT. In turn, the cash flow generated has led to record levels of revenue and profits. With this increased financial flexibility, Phase II development at TGT and continued exploration activities ahead, 2012 sees SOCO in a stronger position than ever to deliver value to shareholders."

ENQUIRIES:

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

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

NOTES TO EDITORS:

SOCO is an international oil and gas exploration and production company, headquartered in London, traded on the London Stock Exchange and a constituent of the FTSE 250 Index. The Company has interests in Vietnam, the Republic of Congo (Brazzaville), the Democratic Republic of Congo (Kinshasa) and Angola, with production operations in Vietnam.

SOCO holds its interests in Vietnam, all in the Cuu Long Basin offshore, through its 80% owned subsidiary SOCO Vietnam Ltd. and through its 100% ownership of OPECO Vietnam Limited. SOCO Vietnam Ltd. holds a 25% working interest in Block 9-2, which is operated by the Hoan Vu Joint Operating Company and holds a 28.5% working interest in Block 16-1, which is operated by the Hoang Long Joint Operating Company. OPECO Vietnam Limited holds a 2% interest in Block 16-1.

SOCO holds its interests in the Republic of Congo (Brazzaville), all offshore in the shallow water Lower Congo Basin, through its 85% owned subsidiary, SOCO Exploration and Production Congo SA (SOCO EPC). SOCO EPC holds a 29% participating interest in the Marine XI Block and a 29.4% participating interest in the Marine XIV Block and is designated operator of the two Blocks.

SOCO holds its interests in the Democratic Republic of Congo (Kinshasa) though its 85% owned subsidiary, SOCO Exploration and Production DRC Sprl (SOCO E&P DRC). SOCO E&P DRC holds a 65% participating interest in the Nganzi Block, situated in the North Congo Basin onshore western DRC, and a 38.25% participating interest in Block V, in the southern Albertine Graben onshore eastern DRC. SOCO E&P DRC is designated operator of both Blocks.

SOCO holds its interests in the Angolan enclave of Cabinda through its 80% owned subsidiary, SOCO Cabinda Limited, which holds a non-operated 17% participating interest in the Cabinda Onshore North Block located onshore in the North Congo Basin.

 

In August of 2011 we reached another significant milestone in adding value to our portfolio as we brought the Te Giac Trang (TGT) field, offshore Vietnam, into production.  Revenues, operating cash flow and net profit from ongoing operations have all reached record levels, providing the Group with the financial capability to continue to self fund foreseeable development expenditures as well as to progress and further enhance its current portfolio. 

Delivering a project as complex as TGT on time and on budget is a credit to our team, the Hoang Long Joint Operating Company (HLJOC), the project operator, and to our industry partners.  This accomplishment enabled the partnership to agree to accelerate the next phase of the development of the field and Phase II development drilling on TGT got underway from the H4 platform in the third quarter of last year.  It continues on track with a further five development wells due on production during the third quarter of 2012.

While the focus for 2011 was clearly on TGT, we also continued with the primarily pre-salt focused exploration programme offshore the Republic of Congo (Brazzaville), onshore the Democratic Republic of Congo (Kinshasa) and in Cabinda.

Financial and Operating Results

Revenue earned by the Group in 2011 set a record at $234.2 million compared to revenue from continuing operations in 2010 of $48.4 million.  After tax profit from continuing operations was also at record levels with a dramatic increase from $12.3 million in 2010 to $88.6 million in 2011.  These historic figures reflect the onset of production from the Group's TGT field which produced first oil in August 2011.  The Group saw 2011 out with net entitlement volumes of approximately 14,700 barrels of oil equivalent per day (BOEPD) compared with approximately 2,600 BOEPD at the end of 2010.  Working interest production net to SOCO averaged 5,437 BOEPD during 2011 compared with 2,257 BOEPD from continuing operations in 2010.  Additionally, the Company was able to benefit from the record high average oil price during 2011 realising nearly $113 per barrel of oil sold compared with approximately $84 per barrel in 2010.

Cash flows from operating activities were up from $12.4 million on continuing operations in 2010 to $90.2 million reflecting the increased oil production and realised oil prices.  Capital expenditures remained near 2010 levels at $152.2 million in 2011 comprising the ongoing work offshore Vietnam, where the second phase of the TGT development continues into 2012, and the exploration programme in the Group's Africa region where two wells were drilled offshore Congo (Brazzaville).  The Company took advantage of its significant cash balances by buying 1.5 million of its own shares into treasury at a cost of $6.8 million and repurchasing convertible bonds at a cost of $35.6 million.

Due to the following factors: the early stages of production from TGT Phase I, continuing work on the Phase II development and another extensive exploitation cycle, extensive pre-drill expenditures associated with continued exploration activities along with the expectation of adding several new ventures during the year, the Board of Directors are not recommending the payment of a dividend. 

2011 Operations Review

SOUTH EAST ASIA

Vietnam - Block 16-1

Our largest exploration and development project evolved into a successful cash generating asset almost exactly according to plan. The field has now demonstrated performance in excess of 40,000 barrels of oil per day (BOPD) with no significant impact on the main reservoir performance parameters. Although there remain alignment issues with Petrovietnam over the rapidity of raising production levels, the evidence from the field is compelling in support of that agreed by all partners in the Government approved Field Development Plan. Accordingly, we are confident that full Partner concurrence of a field production rate of at least 55,000 BOPD will be achieved by Q3 2012.

TGT is a highly complex field with three main reservoir horizons-the upper and lower Miocene 5.2 and the Oligocene "C"-with approximately 55 individual producing intervals. Well performance to-date has demonstrated the ability of all wells to produce oil at high rates with minimal drawdown and field productivity from the reservoir intervals perforated to date has met or exceeded pre-development model prognoses. Stable flowing pressures of the initial producers indicate a strong level of aquifer pressure support, importantly deferring the need for water injection.  Similarly, initial interference tests confirm a high degree of connectivity within the main sands.  Clearly we need information from more than the seven intervals that have been perforated to date in the eight producing wells in order to obtain the information necessary to establish the most efficient and effective way to fully exploit the field.  Thus, 2012 will be about accelerating the programme in step changes in order to establish the most efficient rates at which to drain the field.

The Company's net entitlements production from TGT averaged approximately 12,300 BOPD since it came on production on 22 August 2011.  Entitlements production was over 40% higher than working interest production as the contracting partners recovered those pre-field certification costs carried on behalf of Petrovietnam.

Phase II wells, being drilled from the H4 platform in the southern part of the field, began in the third quarter of 2011 and continues as at this date.  Production from the H4 platform is projected to commence in July or August of 2012.   The additional capacity provides further confidence of maintaining the plateau rate well into the future.

Over the longer term, significant additional potential remains yet to be confirmed in undrilled and un-appraised fault blocks.  We are seeking to accelerate the drilling of these areas.

Vietnam - Block 9-2

Production net to the Company's working interest from the Ca Ngu Vang (CNV) field averaged approximately 2,283 BOEPD during the year.  SOCO continues to champion the drilling of an additional producing well in CNV in order to efficiently drain the main producing area of the field.

To date sales from the CNV field have included approximately 24,000 million standard cubic feet of gas, which is sold to PV Gas at effectively a dry gas sales price for use at the Phu My power plant onshore.  However, the gas stream from CNV is rich in natural gas liquids which presents an opportunity to improve field revenues through the installation of offshore separation facilities.

Work is underway to install a separator and attendant metering facilities on the Bach Ho CPP-3 platform.  The project is estimated to be complete by the end of May 2012 and will improve allocation of CNV hydrocarbons within the complex Bach Ho production facilities.  At that time, the CNV partners will not only enhance their income stream, but also have evidence to support attainment of fair value for the gas liquids in the production stream.   

AFRICA

Although we established a large exploration footprint in the Congo Basin in order to exploit what we felt was a lack of exploration below the salt layer in the region as evidenced by the lack of modern seismic, the results to date have not supported this premise.  It appears that although imaging below the salt layer was limited, in this area the pre-salt geology is more complex than originally thought.

Republic of Congo (Brazzaville)

Two exploration wells were drilled offshore during 2011, one targeting the pre-salt on Block Marine XI and the other a commitment well with a post-salt target on Block Marine XIV.  Although neither was successful, with the pre-salt well not encountering suitable reservoir sands and the post-salt well intersecting sub-commercial accumulations of hydrocarbons, evaluation of the results is ongoing. 

A third, post-salt well was postponed so results from this drilling campaign could be factored into the well plan.  It is expected that the third exploration well, a post-salt target on Block Marine XI will be drilled at some future date as an add-on to other exploration drilling programmes planned in the region.

Democratic Republic of Congo (Kinshasa) (DRC)

The final sub-salt well, one of three drilled in the Nganzi concession onshore in the DRC, was plugged and abandoned during the first quarter of 2011.  Although encountering good reservoir and mature source rocks, none of the wells had sufficient seal.

Additional 2D seismic is being acquired over several post-salt prospects in the Nganzi concession, including some of those prospects previously drilled to test the sub-salt play.  The seismic programme should be complete by the middle of the second quarter of 2012.  Based on the interpretation of the seismic data, the partners will decide whether or not to engage on a multi-well post-salt exploration drilling campaign, which could commence as early as the fourth quarter of 2012.

Angola

Acquisition of the extensive 2D seismic acquisition programme over the Cabinda North Block A concession was concluded in 2011.  Interpretation of the data is underway, with the expectation that a drilling campaign could begin by the end of this year.

CORPORATE

Bond Repurchase

During 2011 the Company bought back convertible bonds with a par value of $35.4 million representing 14.2% of the $250 million convertible bonds that were issued in 2006.  Previously, the Company redeemed $165.9 million (66.4%) following the exercise of bond put options on 16 May 2010. The remaining $48.7 million of bonds mature in May 2013. 

 

The Board of Directors

As stated in the Annual Report of the Directors Mr Peter Kingston and Mr Martin Roberts retired from the Board as Non-Executive Directors of the Company following the Annual General Meeting in June. 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.

Mr Michael Johns was appointed as a Non-Executive Director in June 2011.  Mr Johns serves as the Senior Independent Director, the Chairman of the Remuneration Committee and is a member of the Audit and Nominations Committees.  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 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

Commencement of production at TGT means that we have more opportunity to enhance shareholder value than we have ever had before. We are confident that TGT is a world class field.  There is no doubt that it will be a significant contributor to operating cash flow.  Whilst geologically complex and a multi-horizon reservoir, the field is demonstrating excellent performance and recovery characteristics. We are in discussions with our partners over how best to further develop the field.  We are and will continue to take a very methodical approach to determining the most efficient way to exploit the TGT field.

Having significant cashflow does not mean that we will abandon applying the methodology that got us to this point-fiscal discipline in a self-funded, predominantly in-house generated exploration led strategy that results in a steadily increasing valuation of the asset portfolio. 

We will continue to be an exploration led company.  Our 2012 exploration drilling programme is light in relation to our historic standards simply because projects mature at different times.  Our exploration portfolio contains several high potential projects and it is our intent to continue to add to this.

We have delivered the most significant project that this Company has ever been involved in both on time and in budget.  We have a strong balance sheet and strong forward financial position. We will continue to execute the strategy that made this possible. 

Rui de Sousa
Chairman

Ed Story
President and Chief Executive Officer

 

First oil from the Te Giac Trang (TGT) field was the event of 2011 that changed the operational and financial profile of the Company.  TGT's Phase I production began on schedule and on budget on 22 August 2011.  Current 2012 year-to-date average production is 30,424 barrels of oil per day (BOPD).

Total production net to the Group's working interest from continuing operations during 2011 was 5,437 barrels of oil equivalent per day (BOEPD) compared with 2,257 BOEPD produced in 2010.

SOUTH EAST ASIA

Vietnam

SOCO's Block 16-1 and Block 9-2 projects in Vietnam are located offshore in the oil rich Cuu Long Basin, which is a shallow water, near shore area defined by several high profile producing oil fields, the largest of which, Bach Ho, is located between the two Blocks and has produced more than one billion barrels of oil to date.  The projects are operated through non-profit Joint Operating Companies (JOCs) wherein each participating party owns shares equivalent to its respective interests in the Petroleum Contracts governing the projects.

The Group's interests are held through its 80% owned subsidiary SOCO Vietnam Ltd and through its 100% ownership of OPECO, Inc. SOCO Vietnam Ltd holds a 25% working interest in Block 9-2, which is operated by the Hoan Vu JOC (HVJOC) and a 28.5% working interest in Block 16-1, which is operated by the Hoang Long JOC (HLJOC). OPECO, Inc. holds a 2% working interest in Block 16-1. SOCO's partners on both Blocks are Petrovietnam, the national oil company of Vietnam, and PTTEP, the national oil company of Thailand.

Production

Te Giac Trang (TGT), Block 16-1

The TGT field extends over 15 kilometres along the north-eastern part of Block 16-1.  The Block was awarded to SOCO in December 1999 and the first discovery on TGT was made in 2005.

Phase I

Preparation for first production was the primary focus for the first half of 2011. The project was, by far, the largest development and production project that the Company has ever been involved in.  First oil was achieved on 22 August 2011, just days from the targeted date set two years previously; a clear testament to the hard work invested in the project by SOCO, its partners and the staff of the HLJOC.

The first phase of the H1 platform development drilling programme, which began in 2010, was concluded in 2011 with the completion of five remaining development wells, TGT-4P to -8P. The TGT-4P well, drilled in the southwest area of the northern fault block encountered the top of the target reservoir horizon lower than expected but encountered previously unmapped hydrocarbons in the Oligocene "C" reservoir. The TGT-5P well, drilled to the northern part of the field encountered the main reservoir as expected, while the TGT-6P, drilled to the southern part of the northern fault block, encountered the main reservoir high to prognosis. The TGT-7P well, drilled to the central area, also encountered the main reservoir horizon as predicted although it encountered a thicker pay section than expected. The TGT-8P well, targeting the central area of the H1.2 fault block, near the TGT-1X discovery well, was close to pre-drill prognosis.

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 Armada TGT 1, the floating production storage and offloading vessel (FPSO), which arrived on location in July 2011.  The vessel had 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 double-hulled 274 metre vessel is capable of processing 55,000 BOPD and 75,000 barrels of water per day and storing 620,000 barrels of oil.

The TGT field is a complex, stacked sand reservoir system that is vertically extensive with up to 55 reservoir subzones, each requiring individual reservoir management to ensure that recovery from the field is optimised. Prior to the start of production, reservoir management plans were agreed involving a sequence, over two to three years, of selected perforation programmes of specific limited subzones within each well. To date, only the initial programme has been undertaken.  Baseline reservoir management information continues to be gathered from these limited reservoir intervals.  Technical meetings, held at the end of October with the Block 16-1 partners, resulted in the decision to update and modify the initial reservoir management plan following the review of the well results and the initial performance of the wells. 

Initial production from wells with perforated Miocene sands was as expected, as was production from two of the three wells with perforations in the Oligocene reservoir. However, to evaluate the reservoir sweep within the Oligocene reservoir more thoroughly, additional perforations within the shallow, more productive Miocene reservoir were not added immediately, which was a deviation from the original agreed plan. A revised reservoir management plan, including reviewing amendments to the current 2012 development drilling programme, which includes four wells from the H1 well head platform, and individual well management plans to achieve plateau production of 55,000 BOPD is under review.

Well performance to-date in the H1 Fault Block area has demonstrated the ability of all wells to produce oil at high rates with minimal drawdown and, with the exception of wells perforated at or close to the oil water contracts, without significant water production. It has confirmed the presence of a local, strong aquifer that provides support to the main Miocene ILBH5.2 reservoir and the secondary objective of the Oligocene "C".  Well flowing pressures are very stable, indicating the strong level of pressure support and the high degree of connectivity within the main producing reservoirs.

Gas export, through a pipeline to the nearby Bach Ho facilities for processing and transportation to shore via the existing pipeline infrastructure for further distribution, also commenced while the gas-related process systems are fully tested and commissioned. Peak gas production will be approximately 30 million standard cubic feet per day.

Phase II

The Field Development Plan for TGT was approved by the Government of Vietnam on 30 March 2011 and incorporated the accelerated Phase II development programme. Development drilling operations for Phase II commenced in October with the spudding of the first well at the H4 wellhead platform by the Petrovietnam Drilling PVD-1 jack up drilling rig. Batch drilling of the five wells is ongoing. The wells are expected to be completed ahead of the installation of the production deck and ready for production start up in August 2012.

The TGT-9P well, drilled to the east of the TGT-6X well, was planned to penetrate the main reservoir horizons in the western part of the H4 fault block. The TGT-10P well was planned to be drilled to the H3N fault block north of the TGT-7X well and was designed to also penetrate across a fault to the southern part of the H2 fault block to establish the existence of hydrocarbons in an area not currently mapped as oil bearing in the mid-case. The third well, TGT-11P, was the second well in the H4 fault block and was to the southern part of the Block. TGT-12P was drilled to the middle part of the H3N fault block.

The Block 16-1 partners have recently agreed the location of the fifth well, TGT-14P, which will be drilled prior to releasing the rig to allow the installation of the production deck, and final hook up and completion prior to production start. The well will be targeted to the southwest part of the H4 fault block.

Ca Ngu Vang (CNV), Block 9-2

The CNV field is located in the western part of Block 9-2, offshore Vietnam and is operated by the HVJOC. First oil was in 2008 and the field is currently producing at approximately 9,800 BOEPD, comprising approximately 6,800 BOPD and 18.3 million standard cubic feet of gas and gas liquids per day.  During 2011, CNV production net to the Company's working interest has averaged approximately 2,283 BOEPD.

 In contrast to TGT, the CNV field produces highly volatile oil from fractured Basement reservoir with a high gas to oil ratio and exploitation is dependent on the fracture interconnectivity to efficiently deplete the reservoir.  Hydrocarbons produced from CNV are transported via subsea pipeline to the Bach Ho central processing platform where the wet gas is separated from crude oil and transported via pipeline to an onshore gas facility for further distribution. The crude oil is stored on a floating storage and offloading vessel prior to sale.

During 2011, work commenced to design, construct and install additional dedicated test separation and metering facilities on the processing platform in order to more accurately measure liquid and gas production entering the Bach Ho facilities from the CNV production stream. The separator was installed in the fourth quarter with the metering equipment expected to be installed in the first quarter of 2012 with commissioning expected to be completed by May 2012. 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, which is expected to add up to approximately 2,000 BOEPD to the liquids stream.

Appraisal

Te Giac Den (TGD), Block 16-1

The TGD Appraisal Area encompasses 150 square kilometres and includes the high pressure, high temperature discovery well, TGD-1X-ST1, on the previously designated Prospect "E", and the analogous "E" South Prospect. This area borders the southern boundary of the TGT field.

An extension period for the TGD Appraisal Area was approved by the Government of Vietnam in May 2011. During the third quarter, approximately 140 km² of full fold 3D seismic data was acquired over the TGD Appraisal Area. The data has been sent out for processing and interpretation is ongoing to deliver prospectivity maps. While the new seismic has improved the image across the area, the reservoir risk is higher and may preclude drilling.  A decision to drill a well must be made by the end of the initial extension period, which runs from 1 January 2011 to 30 April 2012. An additional six months extension will be in effect (through 31 October 2012) in the event that the Company elects to drill a well.

AFRICA

Congo (Brazzaville)

SOCO holds its interests in the Republic of Congo (Brazzaville), all offshore in the shallow water Lower Congo Basin, through its 85% owned subsidiary, SOCO Exploration and Production Congo SA (SOCO EPC). SOCO EPC holds a 29% participating interest in the Marine XI Block and a 29.4% participating interest in the Marine XIV Block and is designated operator of the two Blocks.

Exploration

Marine XI

The ENSCO 5003 rig was contracted and refurbished during the first half of 2011 before being towed to the Lower Congo Basin  to drill the Mindou Marine 1 (MIM-1) exploration well which spudded on 5 September.

The MIM-1 well reached a total measured depth of approximately 3,515 metres on 31 October without encountering hydrocarbon bearing reservoir. The target reservoirs were carbonates and sandstone of the pre-salt TOCA and Djeno formations. Palaeontology results from the well, however, suggest that older-than-anticipated sediments were below the salt. Thus, the basal Vandji sand, producing elsewhere in the area but previously thought to be too deep to be considered, has become a viable reservoir target.  A third, post-salt well was postponed so results from this drilling campaign could be factored into the well plan.  It is expected that the third exploration well, a post-salt target on Block Marine XI will be drilled as an add-on to other exploration drilling programmes planned in the region.

Marine XIV

The Makouala Marine 1 (MKM-1) exploration well spudded on 19 November 2011 in the Marine XIV Block.  The well encountered hydrocarbons in the Chela, and in the Upper and Lower Sendji formation horizons.

The MKM-1 well targeted the post-salt Sendji Formation reservoir within a four-way dip closed structure. The well encountered hydrocarbons in both the primary and secondary reservoir targets. However, analysis of the wireline logs indicated that the reservoir sands at the location were not as well developed as predicted and there was insufficient overall pay thickness for commercial flow rates. The well was subsequently plugged and abandoned and the rig released.  Information from this drilling campaign will be factored into further drilling decisions to be taken later this year.

Democratic Republic of Congo (Kinshasa) (DRC)

SOCO holds its interests in the Democratic Republic of Congo (Kinshasa) though its 85% owned subsidiary, SOCO Exploration and Production DRC Sprl (SOCO E&P DRC). SOCO E&P DRC holds a 65% participating interest in the Nganzi Block, situated in the North Congo Basin onshore western DRC, and a 38.25% participating interest in Block V, in the southern Albertine Graben onshore eastern DRC. SOCO E&P DRC is designated operator of both Blocks.

Exploration

Nganzi Block

The wildcat exploration well, Bayingu-1 (BYU-1), spudded in December 2010 on the prospect previously designated as Prospect "H", located in the southern portion of the Nganzi Block. The well encountered oil and gas shows in both the primary and secondary reservoir targets. The reservoir sands at the primary Lower Bucomazi target, however, were poorly developed, whilst the residual nature of the oil shows in the secondary Chela formation indicates lack of closure at this location. The well was plugged and abandoned in January 2011.

Further evaluation of the Nganzi Block incorporating information gathered in the 2010/11 drilling programme has been completed and indicates remaining prospectivity in the Chela formation.  A follow-up  2D seismic acquisition programme commenced in the first quarter of 2012.  Should seismic interpretation warrant, a second round of exploration  drilling could begin in late 2012 prior to the end of the initial exploration period.

Block Evaluation

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 is planned for 2012 with a seismic programme over Lake Edward to follow. The exploration licence was granted by a decree signed by the Hydrocarbons Minister on 26 October 2011.

Angola

Block Evaluation and Exploration

Cabinda Onshore North Block

SOCO Cabinda Limited, the Company's 80% owned subsidiary, holds a 17% participating interest in the Production Sharing Agreement for the Cabinda Onshore North Block in the Angolan enclave of Cabinda.  The Block, which is operated by Sonangol, covers 1,400 square kilometres and is bordered in the north by Congo (Brazzaville) and in the south and east by the DRC.

The seismic acquisition programme that recommenced in May 2010 was completed towards the end of the first half of 2011. Processing of the data is complete and a full interpretation has commenced, with the expectation that a drilling campaign could begin by the end of this year.