29th Mar 2010 07:00
Afren plc
2009 Full Year Results
29 March 2009
100% appraisal drilling success
Significant production growth in 2010
Results summary, 29 March 2010 - The Board of Afren plc ("Afren" or "the Company") announces its results for the year ended 31 December 2009.
The reported financial results for 2009 reflect the group's first full year contribution of production from the Okoro field, Block CI-11 and the Lion Gas Plant.
|
|
US$ mm |
FY 2009 |
FY 2008 |
|
|
|||
|
Turnover |
US$ mm |
335.8 |
42.5 |
|
Gross Profit |
US$ mm |
105.8 |
(28.0) |
|
Net profit (normalised)* |
US$ mm |
50.7 |
(96.0) |
|
Net loss (statutory) |
US$ mm |
(16.8) |
(56.1) |
|
Cashflow from operations |
US$ mm |
278.3 |
(26.8) |
|
Net cash/(debt) |
US$ mm |
54.2 |
(287.4) |
|
Net W.I. production** |
boepd |
22,100 |
3,900 |
|
Realised oil price |
US$/bbl |
59.4 |
42.3 |
|
Realised gas price |
US$/mcf |
5.1 |
4.8 |
* See note 9 of the Preliminary Financial Statements
** Including NGL output
Key highlights
·; 100% appraisal drilling success rate and development underway at the Ebok field in Nigeria• Expected onstream in October 2010 at an initial rate of 15,000 bopd, with 2010 exit production of 35,000 bopd from Ebok
·; Okoro production ahead of pre-drill expectations; infill drilling targets identified
·; Update of independent assessment of reserves by Netherland, Sewell & Associates, Inc., supporting management estimates• Ebok (gross 2P at 31/12/09): 107.5 mmbbls vs 19.1 mmbbls (30/06/2009)• Okoro (gross 2P at 31/12/09): 24.8 mmbbls vs 15.5 mmbbls (30/06/2009)• OPL 310 prospectivity upgraded to 521 mmboe from 329 mmboe
·; Field operating costs successfully cut by 13% following cost reduction initiatives
·; Indigenous Nigerian platform established: First Hydrocarbon Nigeria
·; Admission to the Official List (and FTSE 250 index inclusion effected)
·; Group Finance Director, Darra Comyn, appointed as Executive Director
·; Up to US$450 million Reserve Based Lending facility for Ebok/Okwok/OML 115 area secured
Osman Shahenshah, Chief Executive of Afren, commented:
"In 2009, Afren recorded a 100% appraisal success rate at the Ebok project and realised its first full year contribution from its producing assets. With first oil expected from the Ebok field in October 2010, and an active exploration and appraisal drilling campaign planned over the period, we are well positioned to deliver significant reserves and production growth, realising the full cash flow impact in 2011. With a strengthened balance sheet we have the financial flexibility to deliver long term growth."
Analyst Presentation
There will be a presentation to analysts at 8.30 am BST in The Auditorium, Bank of America Merrill Lynch, 2 King Edward Street, London, EC1A 1HQ.
There will be a dial in facility on: +44 (0)20 8515 2302, conference title: Afren Plc Preliminary Results Conference Call.
The presentation will also be broadcast live at www.afren.com where the accompanying presentation will be available, and on playback from 12:00 pm.
Afren plc Full Year Results 2009
2009 Full Year Results Summary
Results reflect first full year contribution of production operations
In 2009 the Company's financial results were up compared with 2008 as a result of the first full year of production contribution from operations in Nigeria and Côte d'Ivoire. Good progress was also made on cost reduction initiatives which were implemented earlier in the year, enhancing the normalised profitability of the business. With first oil expected from Ebok in October 2010 and an aggressive drilling campaign scheduled for the year ahead, Afren is positioned to deliver large scale production growth that will be fully realised in 2011 and beyond.
Solid platform of producing assets
In Nigeria, an average gross production rate of 18,800 bopd was achieved at the Okoro field with uptime of 99.6%, exceeding pre start-up expectations due to better than forecast reservoir performance and good aquifer support. Two infill drilling opportunities have been identified that are expected to deliver incremental production in 2010. NSAI has increased its 2P reserves estimate for Okoro to 24.8 mmbbls from 15.5 mmbbls. In Côte d'Ivoire, average gross production for the year from upstream operations at CI-11 was 30 mmcfd and 1,230 bopd, whilst midstream NGL output at the Lion Gas Plant was 1,140 boepd.
100% Ebok appraisal drilling success rate
We successfully completed three appraisal wells in 2009. The Ebok-4 well encountered oil within the 'D' series reservoirs, delineating a reserves base well in excess of minimum economic requirements, confirming a commercial development project. The Ebok-5 and Ebok-6 appraisal wells both encountered oil in their target objectives as planned, and in particular established three new oil bearing reservoirs. NSAI has independently confirmed a gross 2P reserves base of 107.5 mmbbls.
Ebok development underway
The first phase development commenced in December 2009 and is expected to deliver production of 15,000 bopd in October 2010. The necessary production and storage infrastructure has been contracted with the selected configuration, comprising a Mobile Offshore Processing Unit (MOPU) and Floating Storage Offloading vessel (FSO), providing an estimated cost saving of US$51 million compared with an alternative Floating Production Storage Offloading vessel (FPSO) development solution.
Acceleration of Ebok West Fault Block
The West Fault Block development has been accelerated in response to the Ebok-5 well proving a materially greater than expected reserves base of good quality 30° API oil, and will incorporate a separate dedicated wellhead platform (WHP) tied back to the central MOPU and FSO. Phase 2 is expected to deliver a further 20,000 bopd by end 2010. The development philosophy at Ebok is one of ongoing development and appraisal, with continued phasing in of additional volumes from other parts of the field in 2011 and beyond, offering progressive and sustainable growth to Afren.
Update of Independent assessment of reserves
NSAI has updated an independent assesment of Afren's reserves and resources, which supports management estimates.
- Ebok gross 2P reserves of 107.5 mmbbls certified (vs Management 116 mmbbls)
- Okoro gross 2P reserves of 24.8 mmbbls certified (vs Management 20.8 mmbbls)
Strengthened balance sheet
The Company strengthened its balance sheet in 2009, ending the year with a net cash position of US$54.2 million. The net cash from operations of US$278 million was supplemented by US$313 million raised in equity funds. Net investment of US$209 million - mostly comprising capital expenditure on Ebok - was accompanied by debt repayments of US$148 million. In March 2010 (post period end), the Company signed a facility agreement for an up to US$450 million reserves based lending facility, secured against the Ebok project reserves. The facility provides added financial flexibility and will be used to fund development activities across the broader Ebok/Okwok/OML 115 area.
Outlook
Under difficult circumstances at the start of the year, the team has delivered excellent operational results, and operating cash flows, and profitability ahead of company expectations and strengthened the balance sheet. Looking ahead, the Company is in a position of strength with the necessary resources in place to deliver the planned 2010 work programme. With the move to the Official List and FTSE 250 inclusion effected, Afren intends to further establish itself as a leading main board listed African independent E&P company and leverage its differentiated strategy to deliver progressive and sustainable growth.
Review of Operations
2009 Results Highlights
|
Average Production |
Total Reserves and Resources |
Sales Revenue |
2009 Investment * |
|
22,100 boepd |
1,120 mmboe |
US$336 m |
198 m |
* Cash investment in oil and gas assets including inventory in the year
• 2009 net working interest production of 22,100 boepd (versus guidance at Interim Results of 22,238 bopd)
• 100% appraisal success drilling success rate achieved at Ebok
• Ebok expected onstream October 2010
• Management reserves independently certified by Netherland,Sewell & Associates, Inc
Production: an established platform in place
Afren produces oil, natural gas and natural gas liquids from its upstream and midstream operations in Nigeria (Okoro) and Côte d'Ivoire (CI-11 and Lion Gas Plant). We have identified infill opportunities at Okoro to deliver additional volumes in 2010, and are focused on defining steps to enhance productivity at CI-11.
|
Asset |
Gross Production |
Reserves* |
Turnover |
|
Okoro |
18,800 bopd |
24.8 mmboe |
U$292.1 m |
|
CI-11 |
6,360 boepd |
9.1 mmboe |
US$27.7 m |
|
Lion Gas Plant |
1,140 boepd |
- |
US$16.0 m |
*Gross remaining 2P reserves at 31 December 2009
Okoro Setu
Strong production performance
By the end of 2009, the Okoro field had produced 8.1 mmbbls of oil. Production averaged 18,800 bopd throughout 2009 with minimal water production. This result was above pre start-up expectations and is due to:
• Water breakthrough from the existing production wells occurring much later than predicted.
• Better reservoir quality than incorporated into the original field simulation model.
• Good aquifer support, evidenced by production history to date.
Improved production outlook and infill targets identified
Using this new information, the field reservoir model has been updated for both producing intervals, as reflected in the NSAI reserves upgrade to 24.8 mmbbls. Production is now expected to decline at a slower rate, and therefore the ultimately recoverable reserves have increased. The updated reservoir model has also allowed us to identify at least two infill drilling locations.
Operational efficiency
The off-take and export of the crude oil produced at Okoro continues to run smoothly and without interruption. This has been helped by a change in our export process implemented in November 2009. We are using a shuttle tanker to transport the processed Okoro crude to the Amni operated Ima terminal. The increased storage capacity at the Ima terminal, of over 1 mmbbls, will allow the benefit of increased parcel sizes and improved shipping and sales economics.
To date, production uptime has been at 99.6% with no incidents or accidents recorded in 2009. There was a brief shutdown in the third quarter when a high level of water (above the allowed 0.5%) was detected in the storage tanks. This impacted the timing of one lifting as a result of having to obtain a temporary permit from the government to offload that cargo. An effective chemical programme to treat the oil-water emulsion was immediately put in place and there were no more delays.
We successfully lowered field operating costs in 2009 by 13% to US$73.4 million. The primary reduction came from savings in the cost of supply vessels, where we renegotiated lower rates early in the year. Further savings will be made through cost sharing initiatives with the Ima field and an additional lowering of supply vessel costs late in 2009.
Okoro Setu continued
2010 work programme
In 2010, the Okoro partners plan to drill two infill wells targeting the identified zones. We expect these wells to restore gross field production rates to more than 21,000 bopd.
We also plan to look at the feasibility of producing oil from the Setu satellite structure, as part of the overall Okoro field production programme.
CI-11
A diversified production base
In 2009 we undertook a major sub surface re-evaluation exercise on the Lion and Panthère fields. This involved integrating all available log, core and seismic data to define the Cretaceous depositional systems active over the fields. The results of this detailed work have been incorporated into reservoir geo models and up-scaled to reservoir simulation models in order to history match production since 1995.
The outcome of this work is that a number of potential new reservoirs have been defined in addition to infill drilling opportunities in existing reservoirs. We are also focused on ways to best address low recovery factors in some field reservoirs via sidetracks of current wells. Furthermore, we are also looking at pressure maintenance via water injection as a means of enhancing the productivity of current production wells. Studies are ongoing in all these areas. This work has not yet been independently assessed by NSAI.
2010 outlook
2010 will see a continuation of the detailed geoscience work undertaken in 2009, which will be combined with reservoir simulation modelling in order to firm-up a work programme that will potentially increase the reserve base and production levels at CI-11.
A wireline programme has been initiated to clear potential wax accumulations within the well bores in preparation for work to optimise the gas lift systems, and potentially perform water shut-offs and perforate bypassed oil and gas pay zones.
Lion Gas Plant
Afren is the sole owner of the Lion Gas Plant, which processes gas from the CI-11 and adjacent CI-26 and CI-40 blocks operated by Canadian Natural Resources. The plant has an inlet capacity of 75 mmscfd and strips gasoline and butane from the rich gas stream it receives. The butane is sold into the local market (meeting approximately 35% of the domestic butane demand) and gasoline is spiked into the CI-11 crude stream and sold on the international market. The plant benefits from tax-exempt status and the average NGL production at the LGP in 2009 was 1,140 boepd. We are also exploring ways to extract propane at the plant, which we would sell locally to industrial customers.
Appraisal and development
We achieved a 100% appraisal drilling success rate at the Ebok field in 2009, successfully proving up incremental reserves in the Central Fault Blocks, West Fault Block and Southern Lobe areas of the field. Development work at Ebok commenced in November 2009, keeping us on track for first oil in October 2010.
Recognising the substantial oil potential that exists in the area surrounding Ebok, we have expanded our regional footprint with the acquisition of interests in the Okwok field (located 16 km east of Ebok) and the surrounding OML 115 acreage. We have now established a sizeable acreage position in this prolific part of the offshore Niger Delta with near-term development, appraisal and exploration upside.
Ebok
Ebok-4 appraisal well results
Drilled by the Transocean Trident IV jack-up drilling unit and completed in February 2009, we achieved positive results with the Ebok-4 well. We recorded net oil pay of 274 ft in high-quality reservoir sands ranging in depth from 2,560 ft to 3,718 ft. Well test analysis and reservoir simulation modelling confirmed that flow rates of around 3,500 bopd per well in a production scenario will be achieved, which is consistent with offset production data from analogous fields in the area.
In August 2009, the Transocean Adriatic IX jack-up drilling unit was secured on a long-term contract to undertake further appraisal and development drilling, at a rate of US$97,000 per day. In March 2010, we announced the signing of a rig contract with Transocean for the GSF High Island VII jack up rig, to carry out planned drilling at the Ebok/Okwok/OML 115 complex and Okoro field. The contract will run for a period of up to 210 days, at an operating rate of US$84,000 per day.
Ebok-5 appraisal well results
Again, we were pleased to report the successful outcome of the Ebok-5 appraisal well. Drilled to a total depth of 3,743 ft on the West Fault Block (FBW), the well encountered a gross oil column of 377 ft in four high-quality sands.
Ebok-6 appraisal well results
The Ebok-6 appraisal well, our third consecutive drilling success, reached a total measured depth of 4,296 ft on the Ebok Southern Lobe. The well encountered gross pay of 107 ft (comprising 82 ft in the D2 and 25 ft in the LD-1A reservoirs).
Delivering significant reserves and production growth
The pre farm-in gross reserve management estimate was 25 mmbbls for the Ebok field. Our appraisal drilling to date has confirmed a gross recoverable resource base of 107.5 mmbbls (source: NSAI), an incremental addition of 82.5 mmbbls. This is a reflection of our detailed regional understanding and validation of our subsurface model.
The correlation of seismic amplitude responses to actual well results from the appraisal wells drilled to date has enabled us to identify further resource potential in the northern area of Ebok, in particular. There is also a read across to the same 'D' series reservoirs in Okwok and OML 115, where comparable seismic amplitudes are exhibited that are consistent with those that have already been drilled and proven to be oil-bearing.
In addition to the 'D' series reservoirs, we are also looking at the potential of deeper intervals that could be oil-bearing. We have undertaken detailed sub surface work to evaluate the Qua Iboe, Biafra and Isongo reservoirs, and plan to test some of this deeper potential with an exploration well during 2010.
Ebok field development - facilities contracted
The initial phases of the Ebok field are being developed using a single Wellhead Support Structure (WSS) tied back to a Mobile Offshore Production Unit (MOPU). The MOPU is a former jack-up drilling rig that has been converted to a production facility by removing the drilling package and replacing it with a processing unit. The facility will have capacity to handle oil production of 50,000 bopd from Phases 1 and 2, and has been designed to allow for onsite expansion and upgrade to accommodate some production from future additional development phases.
The advantages of utilising the converted jack-up is that the installation of the unit does not require a derrick barge, and can be installed whilst drilling operations are in progress, allowing for simultaneous installation and drilling. The MOPU will be tied back to a Floating Storage Offloading (FSO) vessel spread moored nearby. The FSO has been designed to provide a storage volume in excess of 1.2 mmbbls, and will allow for the sale of million barrel cargoes that in turn will enable us to optimise shipping and crude marketing economics. Furthermore opting for the MOPU and FSO development configuration has provided an estimated total cost saving of US$51 million in upfront costs and day rate charges compared to alternative FPSO development solutions that were considered.
It is planned that the MOPU and FSO will become a central facility for the broader Ebok/Okwok/OML 115 area, allowing for the economical and rapid tie-back of production from future developments in the surrounding area.
A phased development approach
Our development strategy is to bring each proven area onstream, and through ongoing drilling continue to increase the reserves base and production from the field. The first development commenced in December 2009. Focused on the Central Fault Blocks, it consists of six horizontal production wells and one water injection well for pressure support. All the wells are being drilled from a single field location using the WSS. We will use any gas produced as fuel to generate the facility's power and as gas lift to increase the well productivity.
Accelerated development of the West Fault Block
Following the successful Ebok-5 well, the decision was taken to bring forward development of the West Fault Block to 2010. The second phase will encompass the installation of a separate dedicated wellhead platform at the West Fault Block location, and the drilling of up to six production wells tied back to the central MOPU and FSO facilities.
Ongoing development and progressive de-risking of upside potential
Once we have completed the first two development phases, 2011 is likely to see additional drilling on the field with efforts focused on remaining proved reservoirs in the Central Fault Blocks and Southern Lobe in particular.
We will also undertake further exploration and appraisal drilling with the objective of testing the 'D' series reservoirs in the northern area of the field and also to test deeper targets in the Qua Iboe, Biafra and Isongo formations.
Establishing a core production hub - bolt on asset acquisitions made
Our acquisition of equity stakes in both Okwok and OML 115 is highly complementary to our regional strategy. We have gained valuable technical insight from drilling the three Ebok appraisal wells. Most importantly, we have been able to calibrate our interpretation of the relationship between seismic amplitude, reservoir quality and hydrocarbon charge. The benefits of this are not just confined to the Ebok field, there being a direct read across to both Okwok and OML 115 that will assist us as we seek to replicate the Ebok success and move towards planned drilling on both blocks in 2010.
With the Ebok production infrastructure nearby, we will be able to quickly tie back future projects as satellite developments. This will allow economies of scale and operational synergies, thereby lowering the economic threshold of further developments.
In August 2009, we extended our partnership in Nigeria with Oriental Energy Resources Ltd. through an agreement to farm-in and jointly develop the Okwok field. Okwok is located in OML 67, 50 km offshore south east Nigeria in 132 ft of water and 15 km east of the Ebok development. The field was discovered by the ExxonMobil / NNPC JV in 1967. Two appraisal wells were drilled in 1968 but not production tested. The wells encountered oil in the LD1 and D2 reservoirs with over 100 ft of oil pay logged in the Okwok-2 well at the D2 level. This is in addition to multiple 50 ft oil bearing sections in the LD1 in the Okwok-1 and Okwok-2 wells.
We have been able to deploy the sub surface knowledge gained from work on the Ebok field to identify Okwok as a high-potential opportunity. The same 'D' series reservoirs are present in both fields, as is the relationship of seismic amplitude to reservoir and hydrocarbon distribution. Consequently, we believe there are larger in-place oil volumes than have been previously and independently quoted. Additionally, we have also identified significant potential in the Qua Iboe formation at Okwok.
Okwok - synergies with Ebok
The development strategy for Okwok will be similar to that used for Ebok. We will benefit from joint storage and export operations as well as shared services. This should result in cost reductions and savings for both fields.
2010 drilling to define next steps
We plan to drill one well on the field during 2010. Detailed seismic interpretation work for this is already under way that will define a well location and trajectory to deliver minimum economic field size volumes so we can commence early development.
OML 115
In January 2010 (post period end), we announced a further joint venture agreement with Oriental to jointly explore, appraise and develop OML 115. OML 115 surrounds the Ebok and Okwok development area, which we also operate with Oriental Energy Resources Limited, and is close to the giant Zafiro Complex in Equatorial Guinea.
This block offers us an attractive opportunity to further capitalise on our extensive knowledge of the area gained to date. The southern portion of the Okwok structure (Okwok South) extends into OML 115 and additional prospectivity has already been defined within the Qua Iboe Formation.
Drilling in 2010
We will drill an exploration well on OML 115 during the second half of 2010. We are currently evaluating the mapped 'D' series reservoirs as well as potential Qua Iboe opportunities, prior to determining the well location and target horizons.
CI-01
Re-mapping and interpretation - applying current understanding of Upper Cretaceous systems
CI-01 has a proven petroleum system in multiple reservoirs within the Cretaceous. Oil and gas has been found and tested in the Ibex and Kudu fields, while only gas has been found in the Eland field. Most of the oil and gas encountered is in reservoirs that are younger than the Albian structural closures originally targeted in the past. There are 3D seismic surveys covering Ibex, Kudu and Eland, and a 2D seismic grid covers the rest of the block.
The block borders the maritime boundary with Ghana, and lies adjacent to the major Jubilee and Tweneboa oil and gas discoveries that have been made in recent years. We have applied the latest understanding of the Cretaceous depositional systems to the existing well and seismic dataset to redefine the distribution of oil and gas in Kudu and Ibex, as well as other accumulations on the block. Consequently, we believe that the discoveries made to date on the block have the potential to be significantly larger than originally mapped.
2010 work programme
We are carrying out detailed sub surface work to establish the optimal location for a well to test the new Cretaceous interpretation. We are also looking at acquiring more 3D seismic over the block. In additon, we are evaluating other techniques such as electromagnetic surveying to aid our understanding of these complex depositional systems.
EXPLORATION
Opportunities for transformational growth
We have assembled a balanced, high-grade portfolio of exploration assets that provide a blended mix of exploration options across multiple play types and basins. In particular, we are continuing to build our presence along the West African Transform margin and Upper Cretaceous fairway, where we have prime acreage positions in the Keta Block offshore Ghana, CI-01 offshore Côte d'Ivoire and OPL 310 offshore south west Nigeria in the Benin Basin.
Keta Block (Ghana)
Prime acreage in an exciting exploration fairway
The Keta Block is in the Volta river basin in Eastern Ghana, next to the boundary with Benin. The block has both Tertiary and Cretaceous prospectivity, with the principal exploration focus being the Cretaceous Albian to Campanian sections. The block offers multiple prospects and leads, with a variety of trapping and depositional settings. A number of these show potential for significant stratigraphic trapping and giant field potential.
Exploration drilling
In 2009 we integrated the drilling results from the Cuda-1x well into the existing data set, updating pore pressure analysis and drilling plans. We purchased additional 2D seismic data and have used it to further define a better understanding of the broader prospectivity on the block. The Keta Block partners have elected to enter the second exploration phase on the licence. This required a mandatory acreage relinquishment, equivalent to 10% of the block area. This was agreed with GNPC, and has no impact on the defined block prospectivity. During 2010, the JV partners will continue to define the block prospectivity and plan to start a process to secure an additional partner on the block ahead of planned drilling operations in early 2011.
OPL 310 (Nigeria)
In August 2009 we announced the farm-in to OPL 310, located offshore Western Nigeria in the Benin Basin, in partnership with indigenous company Optimum Petroleum. The block is next to the Chevron-operated Aje field, which has recently been declared commercial. OPL 310 extends from the shallow water continental shelf to deep water, representing an exploration opportunity in an under explored basin with a proven working hydrocarbon system - in line with our strategy. It is also in close proximity to the recently completed West African Gas Pipeline (WAGP), allowing gas discoveries to be readily developed. There is good seismic coverage of the block in the form of a 1,200 km 2D survey and 400 km2 3D survey.
Prospective acreage with the potential for large discoveries
Encouragingly, OPL 310 contains several identified prospects. These lie in the same Cenonian, Turonian and Albian sandstone intervals that have yielded significant discoveries along the West African Transform Margin in Ghana and Côte d'Ivoire. The trapping configurations are four-way dip closed structures over basement highs. These have the same characteristics as the Seme, Atacora and Alibori discoveries in neighbouring Benin.
So far work has focused on defining the potential of the area covered by 3D seismic data. The key to our understanding of this is the seismic velocity model used to interpret the depth domain. The JV partners are looking to reprocess the seismic data to PSDM format in 2010. We will also carry out an Electro-Magnetic (EM) seabed survey over a number of leads identified during the first phase of interpretation work. If successful, the EM survey could reduce the exploration risk associated with the opportunities we have already defined. This process was successful in the adjacent block over the Aje field and has been used in many other areas in Nigeria. Once we have reprocessed the seismic data and integrated the EM work, the JV will most likely look for an additional partner before commencing drilling.
Resources upgrade
Following our re-mapping of existing prospects, NSAI has increased prospective resources for OPL 310 to 521 mmboe from 329 mmboe.
OPL 907 and OPL 917
During 2009, the OPL 907/917 partners acquired original seismic data tapes for OPL 907 which has been reprocessed. We are carrying out the same process on OPL 917 where the original data is being acquired via the Department of Petroleum Resources (DPR). Once all available data has been reprocessed and interpreted, we will seek to identify areas for future seismic investment. It may also lead to early drilling activity if the original dataset shows sufficiently well-defined opportunities.
La Noumbi (Congo Brazzaville)
The Tie Tie NE exploration well was spudded in December 2009, targeting the Djeno clastics and Toca limestones. The well reached a total depth of 2,550 metres in the Djeno Formation, with hydrocarbon indications recorded between 1,775 and 1,875 metres. Measurements performed on location identified this interval as being composed mainly of gas, which does not suggest viable commercial development due to its distance from potential markets. The well was plugged and abandoned in February 2010. The well data will be used to further our regional understanding, helping us to redefine the prospectivity of the block. We still plan to test a number of other attractive prospects on this block.
JDZ Block 1 (Nigeria - São Tomé & Príncipe JDZ)
The Block 1 participants have agreed to enter the next exploration period. A commitment well on the block will be drilled by end 2014. Sinopec has recently completed a multi-well drilling programme on neighbouring blocks in the JDZ. The results of this drilling campaign, once available, will assist in deciding the next steps in this area.
Finance Review
Financing
Since Afren's inception in late 2004, in acquiring and developing the portfolio, Afren has relied on a combination of equity and debt financing. However, in Afren's first full year of production the Company realised an operating cash flow of US$278 million under a turbulent oil price environment. With forecast 2010 exit production of 35,000 bopd, the Ebok development will add to the existing production base, and will be significantly cash generative for the Company in 2011 and beyond to the point where capital expenditure in subsequent development phases will be financed from a combination of operating cash flow and the financial flexibility afforded by the US$450 million Reserve Based Lending facility recently secured on the Ebok project reserves.
Afren recapitalised the balance sheet in May 2009 raising approximately US$126 million of equity funds (before expenses) and subsequently raised a further US$200 million (before expenses) on the move to the Main Board following the successful appraisal of the Ebok area and the signing of the Okwok agreement with Oriental Energy Resources Ltd.
Cash reserves across the Group at the year end amounted to US$321 million. Following repayments relating to the Okoro and Côte d'Ivoire facilities, gross debt at the year end amounted to US$281 million (2008: US$430 million). These are before deducting unamortised costs of issue of US$14 million and US$25 million respectively. It is expected that circa US$118 million will be repayable during 2010. Overall Afren had net cash of circa US$40 million at 31 December 2009 (US$54 million net of debt issue costs).
Production and revenue
Production at Okoro was ahead of pre-production expectation leading to an average gross production rate for the field of 18,800 bopd. Production from CI-11 in Côte d'Ivoire was stable, with average gross rates of 30 mmscfd and 1,230 bopd. Total revenue after royalties came to US$335.8 million (2008: US$42.5 million). The average sales prices before royalties achieved were US$58.7 per barrel for Okoro and US$65.0 per barrel in CI-11. The total contribution to the revenue from gas sales from CI-11 came to US$19.4 million in the year or around 6% (2008: US$1.6 million and 4%). A further US$4.3 million related to sales of butane from the Lion Gas Plant (2008: US$2.4 million).
Operating costs, depreciation and impairments
Total operating costs for the year were US$90.0 million (2008: US$41.0 million, both excluding any stock adjustments), of which US$73.4 million related to Okoro (2008: US$38.7 million). This followed an opex reduction initiative, against expectations at the start of the year of US$85 million. On a per barrel basis, the rates fell considerably, also due to plateau production from Okoro. Operating costs per barrel averaged US$11.6 for the Group, compared with US$29.7 per barrel in 2008. Total depreciation for the Group in 2009 was US$152.2 million (2008: US$28.7 million restated). Since Afren funds the full field development cost and recovers out of sales revenues, there is a relatively high depreciation rate on a net barrel - US$20.6 per bbl. The total charge relating to Okoro came to US$134.2 million, compared with US$24.7 million in 2008. The increase reflects the significant step up in production (from 1.2 mmbbls in 2008 to 6.9 mmbbls in 2009 gross). CI-11 depreciation came to US$13.6 million at an average rate of US$16.3 per barrel. The Lion Gas Plant is depreciated over its expected life and a charge of US$4.4 million was booked for 2009.
Barrels produced but not sold as at the end of the period are valued at the lower of cost or net realisable value and the cost of sales adjusted accordingly. In December, the Okoro offtake was switched to a terminal on a nearby field. This has the capacity to offload onto much larger vessels, enabling the Okoro crude to be sold in bigger parcels attaining a higher price. With this new system, there is now a longer period between liftings and consequently at the year end there was over 600,000 barrels of oil in storage compared with less than 200,000 barrels at the start of the year. The end of period stock barrels are valued at cost and this amount is deducted from the cost of sales. In total, the cost of sales were reduced by US$12.8 million (2008: US$5.6 million), relating to the difference between the stock value at the start of the year and the much larger stock value at the end of the year.
Gross profit for the year was US$105.8 million, compared with a loss of US$28.0 million for 2008. Total administrative expenses have decreased from US$32.5 million in 2008 to US$27.2 million in 2009. This decrease reflects the cost control initiatives put in place at the start of the year and the benefit from the relatively stronger US dollar as a significant proportion of the administrative costs are denominated in sterling or Nigerian Naira.
In December 2008 Afren announced that the deep offshore Cuda-1x well on the Keta Block in Ghana had been plugged and abandoned after encountering an unexpectedly severe high pressure zone. The costs of the well were written off as it is unlikely that a significant part of the well will be reused. The total cost to Afren, expensed in 2008, was US$23.8 million. This has been subject to an insurance claim which was recently settled. The net effect of the insurance claim is a credit in the 2009 income statement of US$10.1 million. Following a review of the Ogedeh opportunity in Nigeria and given the near-term focus on the enlarged Ebok development, Afren sees limited potential in the project and has formally agreed with its partner Bicta to relinquish its interest. All remaining costs of approximately US$2.5 million relating to the asset have been written off. The Iris Marin licence in Gabon is due for renewal in May 2010. Following the analysis of the well results on the block from 2008, the operator, made a formal recommendation to relinquish the block. Afren reviewed its position in the last quarter of 2009 and expects to formally relinquish its interest in the licence. As the partners are unlikely to go ahead with the Ibekelia TEA if there is no interest in the Iris Marin licence, Afren has written off all costs related to the remaining Gabon licences (US$2.1 million). Following the results of the Tie Tie NE well on the La Noumbi licence in Congo, all costs incurred on the well in 2009 (US$2.1 million) have also been expensed. An additional US$0.6 million of additional costs are expected to be incurred and expensed in 2010 in respect of this well.
Net Income
The group made a pre-tax profit for the first time in 2009, as the benefits of full production and the recovery of the oil price led to a profitable second half of the year. The profit of US$0.5 million compares with a pre-tax loss in 2008 of US$55.6 million. The normalised profit for the year (after excluding unrealised hedge movements, share related costs, exchange movements and the share of loss from associates) was US$50.7 million (2008: loss of US$96.0 million). Note 9 includes a full reconciliation of this figure. The reported loss after tax was US$16.8 million, compared with a loss of US$56.1 million for 2008 and a loss in the first half of 2009 of US$38.5 million, as the Group made a profit in the second half of the year. The loss per share for the year was 2.6c compared with 15.0c in 2008 (restated).
Derivative financial instruments - hedging
In May 2007, as part of the financing arrangements for the Okoro field, Afren entered into a series of swaps and call options to economically protect against exposure to the variability in the price of around 14% of expected Okoro oil production through to the end of 2010. This arrangement partly protects the Group against the risk of a significant fall in the price of crude by establishing a minimum swap price for a proportion of the Okoro crude. However, the Group will receive a set discount from the market price if the oil price is above that minimum. In this way, no up-front costs are payable and the Group enjoys the benefits of the majority of any oil price upside whilst there is only a cost to the Group if the oil price is sufficiently firm. In September 2008, a similar set of instruments was entered into in relation to the oil production from the Côte d'Ivoire assets covering the period from October 2008 to mid-2012. Essentially all the base net CI-11 oil production is hedged in this period (approximately 925,000 barrels) at prices between US$79 and US$85 per barrel. In June 2009 a further set of instruments were entered into related to an additional tranche of Okoro production, covering around a further 10% of production and extending out to the end of 2011.
The value of these derivative instruments are marked to market for each period and the gains and losses arising out of the changes in fair value are accounted for in the income statement. During 2009 the oil price strengthened, reducing the value of these instruments, with Brent moving from circa US$40 per barrel in December 2008 to circa US$80 per barrel in December 2009. The change in fair value of the instruments equates to a loss of US$15.3 million relating to Okoro and a loss of US$18.3 million relating to Côte d'Ivoire net of actual realisations (2008: a gain of US$13.4 million and a gain of US$41.3 million respectively). The actual realisation from these instruments for 2009 was a gain of US$11.4 million, compared with a gain in 2008 of US$3.6 million, as market prices have been consistently below the hedged price for Côte d'Ivoire production and were below the hedged price for Okoro production until the third quarter. These positions are likely to remain volatile as they are marked to market at each balance sheet date and their value will depend on both the spot price and the forward curve.
Net interest and other gains and losses
Net interest, financing costs and other gains and losses for the Group in 2009 amounted to US$45.3 million (2008: US$11.5 million). Total gross interest expense (including facility fees, amortisation of costs and unwinding of discount where applicable) amounted to US$37.7 million (2008: US$33.0 million), of which US$1.8 million was capitalised relating to the Ebok development (2008: US$16.9 million, relating to the Okoro development). 2008 also had a one-off charge relating to the early conversion of a convertible bond (US$9.3 million). The charge relating to the unwinding of discount from the abandonment provisions for the Okoro and CI-11 fields amounted to US$1.1 million (2008: US$0.4 million). Interest income came to US$0.6 million (2008: US$5.3 million), reflecting the significantly lower rates paid on deposits. All Afren's cash is retained in short-term or immediately available deposits with a selected group of banks and financial institutions. Afren made a loss of US$2.8 million (2008: US$15.4 million) due to foreign exchange differences in the year. This mostly related to sterling funds where the exchange rate fell to the year end. The bulk of the sterling funds have since been transferred into US dollars removing any significant risk from the rates going forward, as the Group's costs are largely US dollar denominated. Certain warrants held in Afren shares are not convertible at a fixed price in the Company's functional currency (due to the fluctuation of the exchange rates from sterling to US Dollar) so are marked to market at each balance sheet date and the increase or decrease in the liability is taken to net income. As Afren shares moved significantly between 1 January 2009 and 31 December 2009 (from 26.5 pence to 85 pence), there was a significant increase in the value of the warrants to the warrant holder and hence the deemed liability to Afren. This led to a US$5.0 million charge in the income statement, compared with a US$26.6 million gain made in 2008. The effect of these warrants is likely to remain volatile, with any further increases in value of the share price creating a charge in the financial statements as the value of the warrants to the warrant holder increases. In 2009, Afren invested a further £1.5 million in Gasol and Afren's current interest is 20.9%. Since 11 February 2009 when Afren made the initial increased investment it has accounted for Gasol as an associate. Afren's share of Gasol's losses over the period amount to US$1.3 million.
Tax
The tax charge for the year of US$17.3 million arises from the Group operations in Nigeria and Côte d'Ivoire. The charge reflects the current and deferred tax expense for the Okoro field and the current tax expense for the CI-11 operations. This represents the charge for a full year of operations for both assets and the use of tax losses applicable to the Okoro project.
Reallocation of acquisition costs on Côte d'Ivoire assets
The 2008 annual report reflected our provisional estimates of the fair values of the assets acquired from Devon in September 2008. Following the receipt in March 2009 of the full data set relating to these assets, Afren has been able to reassess the reasonableness of these initial calculations. The technical analysis to date on the full data set has now been reviewed by NSAI, and the analysis indicates that CI-01 has significantly greater reserves potential than originally envisaged but that CI-11 has less. Therefore, in accordance with the one year window allowed by IFRS to finalise fair value estimates, at 30 June 2009 Afren reallocated the value of the assets acquired between CI-11, the Lion Gas Plant and CI-01, resulting in a reclassification between intangible assets and PP&E in the 2008 balance sheet, and a consequent immaterial adjustment to the 2008 full year results in accordance with IFRS 3.
Balance Sheet
Total net assets at 31 December 2009 amounted to US$658.2 million (2008: US$350.9 million) with the increase principally due to the share placings in May and December 2009. Total non-current assets stood at US$684.0 million at the year end compared with US$710.7 million at the end of 2008 (restated). This reflects the expenditure on Ebok where the carried value has grown from US$47.0 million to US$158.6 million offset by depreciation on the producing fields (US$152.2 million). Intangible oil and gas assets have fallen in value from US$213.9 million to US$184.2 million, reflecting the transfer of Ebok from an intangible asset to Property, Plant and Equipment. Following government and partner approval for the Ebok development at the end of August, the balance was transferred to tangible assets. In total around US$16 million was spent in 2009 on exploration and evaluation (excluding Ebok expenditure), spread across Afren's assets. Current assets have grown from US$211.4 million to US$416.0 million in the year. The largest component of this is the cash balance of US$321.3 million (2008: US$117.7 million) referred to above.
Total current liabilities were US$257.6 million at the year end, marginally higher than at the end of 2008 (US$257.0 million). Non-current liabilities stood at US$184.1 million at the year end compared with US$314.2 million at 31 December 2008, the decrease of US$131.8 million in the last 12 months being primarily due to significant repayments of debt made from the Okoro and Côte d'Ivoire cash flows, partially offset by the provision for a deferred tax liability in relation to Okoro of US$12.5 million.
Cash flow
Net cash generated from operating activities totalled US$278.3 million (2008: cash used of US$26.8 million) reflecting a full year of production. Once more there was significant investment in oil and gas assets (US$197.9 million including inventory; 2008: US$289.4 million) as Afren continues to develop its portfolio. Net cash used in investing activities fell from US$459.4 million to US$209.1 million year on year. However, 2009 saw the start of significant repayments of the outstanding loans as the field revenues were received, with a total repayment of US$148.4 million, compared with a draw-down in 2008 of US$321.9 million after costs and repayments later in the year.
Going concern
The Group's business activities, together with the factors likely to affect its future development, performance and position are set out in the Review of Operations. The financial position of the Group at the year end, its cash flows, liquidity position and borrowing facilities are described above.
The Group typically uses its cash resources to fund its exploration and appraisal programme and administrative expenses. Expenditure on developing a field to production is typically also funded by debt facilities. At present the Group is funding the initial development of the Ebok field from its own resources and the Company's assessment is that this can be continued until Ebok produces first oil, after which it will contribute cash to the Group. Additional development of the Ebok field will be funded by cash contributed by the initial development and additional debt from the loan facility announced on 25 March 2010.
The Directors have a reasonable expectation that the Company and Group have adequate resources to continue in operational existence for the foreseeable future. Thus they continue to adopt the going concern basis of accounting in preparing the annual financial statements.
Principal risks to 2010 performance
In common with other companies in the oil and gas sector, Afren is exposed to commodity price risk, the delivery of major projects and ensuring safe operations in all locations. The Board determines key risks for the company and required mitigation plans and reviews delivery on a regular basis. Key specific risks for 2010 include the successful execution of the phased Ebok development.
Outlook
With the first full year of production behind Afren, a recapitalised balance sheet, the financial flexibility from the recently secured US$450 million Reserve Based Lending facility and a significant forecast increase in production from the Ebok field, Afren has an appropriate capital structure to fund its forward growth strategy.
|
Group Income Statement For the year ended 31 December 2009
|
Notes |
2009 US$000's |
Restated* 2008 US$000's |
|
Revenue |
5 |
335,818 |
42,501 |
|
Cost of sales |
|
(230,036) |
(70,537) |
|
Gross profit/(loss) |
|
105,782 |
(28,036) |
|
|
|
|
|
|
Administrative expenses |
|
(27,215) |
(32,491) |
|
Other operating income/(expenses) |
|
|
|
|
- derivative financial instruments |
|
(33,635) |
54,682 |
|
- impairment reversal/(charge) on oil and gas assets |
|
859 |
(38,212) |
|
|
|
|
|
|
Operating profit/(loss) |
5 |
45,791 |
(44,057) |
|
|
|
|
|
|
Investment revenue |
|
626 |
5,286 |
|
Finance costs |
|
(36,950) |
(25,760) |
|
Other gains and (losses) |
|
|
|
|
- foreign currency losses |
|
(2,770) |
(15,382) |
|
- fair value of financial liabilities and financial assets |
|
(5,034) |
26,607 |
|
- impairment reversal/(charge) on available for sale investments |
|
97 |
(2,296) |
|
Share of loss of an associate |
|
(1,277) |
- |
|
|
|
|
|
|
Profit/(loss) before tax |
|
483 |
(55,602) |
|
|
|
|
|
|
Income tax expense |
6 |
(17,261) |
(520) |
|
Loss after tax |
|
(16,778) |
(56,122) |
|
|
|
|
|
|
Loss per share |
|
|
|
|
Basic and diluted |
2 |
2.6c |
15.0c |
* See note 7
|
Group Statement of Comprehensive Income For the year ended 31 December 2009
|
Notes |
2009 US$000's |
Restated* 2008 US$000's |
|
Loss after tax |
|
(16,778) |
(56,122) |
|
Redesignation of warrants as financial liabilities |
|
- |
(27,106) |
|
Revaluation of available for sale investments |
|
- |
(472) |
|
Exchange differences arising on consolidation |
|
- |
2,188 |
|
Total comprehensive loss attributable to equity holders of Afren plc |
|
(16,778) |
(81,512) |
* See note 7
|
|
Group |
Company |
|||
|
Balance Sheets As at 31 December 2009
|
Notes |
2009 US$000's |
Restated* 2008 US$000's |
2009 US$000's |
2008 US$000's |
|
Assets |
|
|
|
|
|
|
Non-current assets |
|
|
|
|
|
|
Intangible oil and gas assets |
|
184,161 |
213,933 |
- |
- |
|
Property, plant and equipment |
|
|
|
|
|
|
- oil and gas assets |
|
486,672 |
465,644 |
- |
- |
|
- other |
|
6,996 |
5,813 |
2,711 |
2,299 |
|
Prepayments |
|
3,383 |
4,783 |
- |
- |
|
Investments in subsidiaries |
|
- |
- |
54,128 |
50,412 |
|
Derivative financial instruments |
|
2,153 |
20,354 |
- |
- |
|
- Available for sale investments |
|
- |
211 |
- |
211 |
|
Investments in associates |
|
604 |
- |
604 |
- |
|
|
5 |
683,969 |
710,738 |
57,443 |
52,922 |
|
|
|
|
|
|
|
|
Current assets |
|
|
|
|
|
|
Inventories |
|
34,564 |
13,276 |
- |
- |
|
Trade and other receivables |
|
55,614 |
51,247 |
478,762 |
330,731 |
|
Derivative financial instruments |
|
4,523 |
29,161 |
- |
- |
|
Cash and cash equivalents |
|
321,312 |
117,719 |
203,117 |
39,106 |
|
|
5 |
416,013 |
211,403 |
681,879 |
369,837 |
|
Total assets |
|
1,099,982 |
922,141 |
739,332 |
422,759 |
|
|
|
|
|
|
|
|
Liabilities |
|
|
|
|
|
|
Current liabilities |
|
|
|
|
|
|
Trade and other payables |
|
(134,739) |
(145,755) |
(61,226) |
(37,749) |
|
Borrowings |
|
(117,634) |
(111,218) |
- |
- |
|
Derivative financial instruments |
|
(5,240) |
- |
- |
- |
|
|
|
(257,613) |
(256,973) |
(61,226) |
(37,749) |
|
Net current assets/(liabilities) |
|
158,400 |
(45,570) |
620,653 |
332,088 |
|
|
|
|
|
|
|
|
Non-current liabilities |
|
|
|
|
|
|
Deferred tax liabilities |
|
(12,460) |
- |
- |
- |
|
Provision for decommissioning |
|
(21,836) |
(20,276) |
- |
- |
|
Borrowings |
|
(149,446) |
(293,946) |
- |
- |
|
Derivative financial instruments |
|
(379) |
- |
- |
- |
|
|
|
(184,121) |
(314,222) |
- |
- |
|
Total liabilities |
5 |
(441,734) |
(571,195) |
(61,226) |
(37,749) |
|
|
|
|
|
|
|
|
Net assets |
|
658,248 |
350,946 |
678,096 |
385,010 |
|
|
|
|
|
|
|
|
Equity |
|
|
|
|
|
|
Share capital |
8 |
15,702 |
8,806 |
15,702 |
8,806 |
|
Share premium |
8 |
755,169 |
446,958 |
755,169 |
446,958 |
|
Other reserves |
|
17,272 |
18,173 |
17,214 |
17,396 |
|
Accumulated losses |
|
(129,895) |
(122,991) |
(109,989) |
(88,150) |
|
Total equity |
|
658,248 |
350,946 |
678,096 |
385,010 |
* See note 7
|
|
Group |
Company |
|||
|
Cash Flow Statements For the year ended 31 December 2009
|
|
2009 US$000's |
Restated• 2008 US$000's |
2009 US$000's |
2008 US$000's |
|
Operating profit/(loss) for the year |
|
45,791 |
(44,057) |
(28,407) |
(45,786) |
|
Depreciation, depletion and amortisation |
|
154,783 |
30,030 |
862 |
632 |
|
Derivative financial instruments |
|
48,458 |
(55,499) |
- |
- |
|
Impairment of oil and gas assets |
|
(859) |
38,212 |
- |
- |
|
Provision for inventories - spare parts |
|
- |
1,206 |
- |
- |
|
Share-based payments charge |
|
9,292 |
10,819 |
6,767 |
6,691 |
|
Operating cash flows before movements in working capital |
|
257,466 |
(19,289) |
(20,778) |
(38,463) |
|
Decrease/increase in trade and other operating receivables |
|
532 |
(25,149) |
(1,416) |
(7,550) |
|
Increase in trade and other operating payables |
|
31,761 |
22,498 |
16,744 |
30,861 |
|
Increase in inventory (crude oil) |
|
(11,588) |
(5,608) |
- |
- |
|
Currency translation adjustments |
|
117 |
737 |
76 |
710 |
|
Net cash generated/(used) in operating activities |
|
278,288 |
(26,811) |
(5,374) |
(14,442) |
|
|
|
|
|
|
|
|
Purchases of property, plant and equipment: |
|
|
|
|
|
|
- oil and gas assets |
|
(97,810) |
(224,297) |
(1,274) |
- |
|
- other |
|
(3,770) |
(5,115) |
- |
(2,051) |
|
Exploration and evaluation expenditure |
|
(90,365) |
(62,396) |
- |
- |
|
Advances to Group undertakings |
|
- |
- |
(133,312) |
(175,788) |
|
Investment in subsidiaries |
|
- |
- |
(4,060) |
(10,761) |
|
Increase in inventories - spare parts |
|
(9,700) |
(2,709) |
- |
- |
|
Purchase of investments |
|
(1,815) |
(1,501) |
(1,815) |
(1,501) |
|
Investment revenue |
|
599 |
5,349 |
521 |
4,529 |
|
Completion payment on 2008 acquired subsidiaries |
|
(6,198) |
- |
- |
- |
|
Acquisition of subsidiaries, net of cash acquired |
|
- |
(168,749) |
- |
- |
|
Net cash used in investing activities |
|
(209,059) |
(459,418) |
(139,940) |
(185,572) |
|
|
|
|
|
|
|
|
Issue of ordinary share capital |
|
326,969 |
238,313 |
326,969 |
238,313 |
|
Costs of share issues |
|
(14,236) |
(7,663) |
(14,236) |
(7,663) |
|
Proceeds from borrowings |
|
- |
362,502 |
- |
- |
|
Borrowing costs |
|
- |
(11,597) |
- |
- |
|
Incentive paid on early conversion of bonds |
|
- |
(9,332) |
- |
(9,332) |
|
Repayment of borrowings |
|
(148,447) |
(29,032) |
- |
- |
|
Interest and financing fees paid |
|
(26,870) |
(16,282) |
(49) |
(7,399) |
|
Net cash provided by financing activities |
|
137,416 |
526,909 |
312,684 |
213,919 |
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents |
|
206,645 |
40,680 |
167,370 |
13,905 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of year |
|
117,719 |
91,783 |
39,106 |
39,937 |
|
Effect of foreign exchange rate changes |
|
(3,052) |
(14,744) |
(3,359) |
(14,736) |
|
Cash and cash equivalents at end of year |
|
321,312 |
117,719 |
203,117 |
39,106 |
* See note 7.
In 2008 a material non-cash transaction occurred, being the early conversion of the Group's convertible bonds.
|
Statements of Changes in Equity For the year ended 31 December 2009
|
Share capital US$000's |
Share premium account US$000's |
Other reserves US$000's |
Accumulated losses US$000's |
Total equity US$000's |
|
Group |
|
|
|
|
|
|
At 1 January 2008 |
5,365 |
146,245 |
16,872 |
(58,666) |
109,816 |
|
Issue of share capital |
2,021 |
238,537 |
- |
- |
240,558 |
|
Issue of loan notes |
- |
- |
7,350 |
- |
7,350 |
|
Deductable costs of share issues |
- |
(7,663) |
- |
- |
(7,663) |
|
Redesignation of warrants as financial liabilities |
- |
- |
(3,395) |
(23,711) |
(27,106) |
|
Conversion of bonds into shares |
1,420 |
69,839 |
(9,500) |
9,500 |
71,259 |
|
Share-based payments for services |
- |
- |
10,701 |
- |
10,701 |
|
Other share-based payments |
- |
- |
118 |
- |
118 |
|
Reserves transfer relating to convertible bonds |
- |
- |
(1,789) |
1,789 |
- |
|
Reserves transfer on exercise of options |
- |
- |
(3,849) |
3,849 |
- |
|
Revaluation of available for sale investments |
- |
- |
(472) |
- |
(472) |
|
Other movements |
- |
- |
(51) |
370 |
319 |
|
Translation differences |
- |
- |
2,188 |
- |
2,188 |
|
Net loss for the year (restated - note 31) |
- |
- |
- |
(56,122) |
(56,122) |
|
Balance at 31 December 2008 |
8,806 |
446,958 |
18,173 |
(122,991) |
350,946 |
|
|
|
|
|
|
|
|
Issue of share capital |
6,896 |
322,447 |
- |
- |
329,343 |
|
Deductible costs of share issues |
- |
(14,236) |
- |
- |
(14,236) |
|
Share-based payments for services |
- |
- |
9,197 |
- |
9,197 |
|
Other share-based payments |
- |
- |
95 |
- |
95 |
|
Reserves transfer relating to loan notes |
- |
- |
(2,312) |
2,312 |
- |
|
Reserves transfer on exercise of options, awards and LTIP |
- |
- |
(4,792) |
4,792 |
- |
|
Reserves transfer on exercise of warrants |
- |
- |
(2,770) |
2,770 |
- |
|
Other movements |
- |
- |
(319) |
- |
(319) |
|
Net loss for the year |
- |
- |
- |
(16,778) |
(16,778) |
|
Balance at 31 December 2009 |
15,702 |
755,169 |
17,272 |
(129,895) |
658,248 |
Notes to the Preliminary Financial Statements
For the year ended 31 December 2009
1. Basis of accounting and presentation of financial information
The financial information set out in these preliminary financial statements does not constitute the company's statutory accounts for the years ended 31 December 2008 or 2009, but is derived from those accounts. Statutory accounts for 2008 have been delivered to the Registrar of Companies and those for 2009 will be delivered following the company's annual general meeting. The auditors have reported on those accounts; their reports were unqualified, did not draw attention to any matters by way of emphasis without qualifying their report and did not contain statements under s498(2) or (3) Companies Act 2006 or equivalent preceding legislation.
Whilst the financial information included in this preliminary announcement has been completed in accordance with International Financial Reporting Standards (IFRS), this announcement does not its self contain sufficient information to comply with IFRS. The Company expects to publish full financial statements that comply with IFRS in its Annual Report and Accounts 2009.
The financial information has been prepared in accordance with the going concern basis of accounting. The use of this basis of accounting takes into consideration the Groups's current and forecast financing position, additional details of which are provided in the Financial Review.
2. Loss per ordinary share
The calculation of basic loss per share is based on the loss for the period after taxation and the weighted average number of shares in issue for the period. As there is a loss in all periods, there is no difference between the basic and diluted earnings per share.
|
|
|
Year ended 31 December |
|
|
|
|
2009 |
2008 |
|
Basic and diluted (cents) |
|
2.6c |
15.0c |
|
Loss for the period after taxation (US$000's) |
|
16,778 |
56,122 |
|
Weighted average number of shares in issue in the period |
|
637,328,455 |
373,370,052 |
3. 2009 Annual Report and Accounts
The Annual Report and Accounts will be mailed on 29 April 2010 only to those shareholders who have elected to receive it. Otherwise, shareholders will be notified that the Annual Report and Accounts is available on the website (www.afren.com). Copies of the Annual Report and Accounts will also be available from the Company's registered office at 3rd Floor, Kinnaird House, 1 Pall Mall East, London ,SW1Y 5AU.
4. Annual General Meeting
The Annual General Meeting is due to be held at the offices of White & Case LLP, 5 Old Broad Street, London, EC2N 1DW on Monday, 7 June 2010 at 11.00 am.
5. Segmental Reporting
Operating segments
For management purposes, the Group currently operates in three geographical markets: Nigeria, Côte d'Ivoire and Other West Africa. Unallocated operating expenses, assets and liabilities relate to the general management, financing and administration of the Group.
|
2009 |
NigeriaUS$000's |
Côte d'Ivoire US$000's |
Other West Africa US$000's |
Unallocated US$000's |
Consolidated US$000's |
|
Sales revenue by origin |
292,111 |
43,707 |
- |
- |
335,818 |
|
|
|
|
|
|
|
|
Operating gain/(loss) before derivative financial instruments |
93,157 |
7,554 |
3,576 |
(24,861) |
79,426 |
|
Derivative financial instruments losses |
(15,346) |
(18,289) |
- |
- |
(33,635) |
|
Segment result |
77,811 |
(10,735) |
3,576 |
(24,861) |
45,791 |
|
Investment revenue |
|
|
|
|
626 |
|
Finance costs |
|
|
|
|
(36,950) |
|
Other gains and losses - Impairment reversal on available for sale investment |
|
|
|
|
97 |
|
Other gains and losses- fair value of financial assets & liabilities |
|
|
|
|
(5,034) |
|
Other gains and losses - foreign currency losses |
|
|
|
|
(2,770) |
|
Share of loss of an associate |
|
|
|
|
(1,277) |
|
Profit before tax |
|
|
|
|
483 |
|
Income tax expense |
|
|
|
|
(17,261) |
|
Profit after tax |
|
|
|
|
(16,778) |
|
Segment assets - non-current |
448,785 |
168,796 |
62,884 |
3,504 |
683,969 |
|
Segment assets - current |
158,764 |
27,940 |
21,373 |
207,936 |
416,013 |
|
Segment liabilities |
(233,027) |
(139,795) |
(8,824) |
(60,088) |
(441,734) |
|
Capital additions - oil and gas assets |
76,502 |
6,406 |
- |
- |
82,908 |
|
Capital additions - exploration and evaluation |
59,135 |
1,447 |
6,683 |
- |
67,265 |
|
Capital additions - other |
2,352 |
123 |
- |
1,333 |
3,808 |
|
Depletion, depreciation and amortisation |
(135,595) |
(18,226) |
- |
(962) |
(154,783) |
|
Impairment reversal/(charge) on oil and gas assets |
(2,705) |
- |
3,564 |
- |
859 |
|
Impairment reversal of available for sale investments |
- |
- |
- |
97 |
97 |
5. Segmental Reporting continued
|
2008 |
NigeriaUS$000's |
Côte d'IvoireUS$000's |
Other West Africa US$000's |
Unallocated US$000's |
Consolidated US$000's |
|
Sales revenue by origin |
37,117 |
5,384 |
- |
- |
42,501 |
|
|
|
|
|
|
|
|
Operating loss before derivative financial instruments |
(33,458) |
(7,445) |
(29,013) |
(28,823) |
(98,739) |
|
Derivative financial instruments gains |
13,338 |
41,344 |
- |
- |
54,682 |
|
Segment result |
(20,120) |
33,899 |
(29,013) |
(28,823) |
(44,057) |
|
Impairment charge on available for sale investment |
|
|
|
|
(2,296) |
|
Investment revenue |
|
|
|
|
5,286 |
|
Finance costs |
|
|
|
|
(25,760) |
|
Other gains and losses - fair value of financial liabilities |
|
|
|
|
26,607) |
|
Other gains and losses - foreign currency losses |
|
|
|
|
(15,382) |
|
Loss before tax |
|
|
|
|
(55,602) |
|
Income tax expense |
|
|
|
|
(520) |
|
Loss after tax |
|
|
|
|
(56,122) |
|
Segment assets - non-current |
451,955 |
195,469 |
60,576 |
2,738 |
710,738 |
|
Segment assets - current |
87,208 |
42,242 |
20,323 |
61,630 |
211,403 |
|
Segment liabilities |
(351,655) |
(160,628) |
(18,008) |
(40,904) |
(571,195) |
|
Capital additions - oil and gas assets |
280,076 |
107 |
- |
- |
280,183 |
|
Capital additions - oil and gas assets (acquisition of subsidiaries) |
- |
79,304 |
- |
- |
79,304 |
|
Capital additions - exploration and evaluation |
51,866 |
387 |
43,566 |
- |
95,819 |
|
Capital additions exploration and evaluation (acquisition of subsidiaries) |
- |
100,626 |
- |
- |
100,626 |
|
Capital additions - other |
2,703 |
561 |
- |
2,293 |
5,557 |
|
Depletion, depreciation and amortisation |
(25,295) |
(4,092) |
- |
(643) |
(30,030) |
|
Impairment on oil and gas assets |
(9,222) |
- |
(28,990) |
- |
(38,212) |
|
Impairment of available for sale investments |
- |
- |
- |
(2,296) |
(2,296) |
Included in revenues for Nigeria for the year ended 31 December 2009 are US$292.1 million (2008: US$37.2 million) which arose from the Group's largest customer.
Non current assets held in UK at 31 December 2009 totalled US$3.3 million (2008: US$2.3 million). Non current assets held in Other West Africa at 31 December 2009 included US$16.0 million (2008: US$13.2) relating to Keta Block, Ghana, US$29.2 million (2008: US$28.9 million) relating to La Noumbi permit in Congo (Brazzaville) and US$17.6 million (2008: US$17.2 million) relating to JDZ Block One in São Tomé & Princìpe.
6. Taxation
|
|
|
|
2009 US$000's |
2008 US$000's |
|
UK corporation tax |
|
|
- |
- |
|
Overseas corporation tax |
|
|
4,801 |
520 |
|
|
|
|
4,801 |
520 |
|
Deferred tax charge (note 25) |
|
|
12,460 |
- |
|
|
|
|
17,261 |
520 |
The overall tax charge can be reconciled to the profit for the year as follows:
|
|
|
|
2009 US$000's |
2008 US$000's |
|
Pre-tax profit/(loss) |
|
|
483 |
(55,602) |
|
Tax at the UK corporate tax rate of 28% (2008: 28.5%) |
|
|
135 |
(15,847) |
|
Tax effect of items which are not deductible for tax |
|
|
9,149 |
12,927 |
|
Temporary differences not recognised |
|
|
13,348 |
9,045 |
|
Items not subject to tax |
|
|
(16,436) |
(25,474) |
|
Tax effect of share of associate results |
|
|
357 |
- |
|
Effect of different tax rates |
|
|
534 |
19 |
|
Loss not recognised |
|
|
10,174 |
19,850 |
|
Tax charge for the year |
|
|
17,261 |
520 |
The Group's tax charge for the year includes current and deferred tax in Nigeria of US$0.8 million and US$12.5 million respectively. The detailed mechanics of the Group's tax filing arrangements in Nigeria are subject to agreement with the local tax authorities and while the Group is satisfied that the 2009 charge is its best estimate of its tax position, adjustments may be required once these discussions have been finalised.
7. Acquisition of subsidiaries
On 25 September 2008, Afren announced that it had completed the acquisition of Devon Energy Corporation's interests in Côte d'Ivoire, comprising a 47.96% working interest and operatorship of the producing Block CI-11, a direct participating 65% interest (with rights over an additional 15% interest) and operatorship in the undeveloped Block CI-01 and a 100% interest in the onshore Lion Gas Plant, effective 30 June 2007. The adjusted consideration for the acquisition, including transaction costs and working capital adjustments, was US$184.3 million funded through a financing package arranged by BNP Paribas. The transaction took the form of an acquisition of 100% of the ordinary shares of Devon Côte d'Ivoire Ltd (CI-11), Devon CI One Corporation (CI-01) and Lion G.P.L., S.A. (Lion GPL).
The fair value of net assets acquired was as follows (as restated):
|
|
CI-11US$000's |
CI-01US$000's |
Lion GPLUS$000's |
TotalUS$000's |
|
Oil and gas assets |
51,534 |
100,626 |
27,770 |
179,930 |
|
Other property, plant and equipment |
399 |
- |
162 |
561 |
|
Inventories |
7,093 |
- |
1,591 |
8,684 |
|
Trade and other receivables |
8,077 |
- |
1,929 |
10,006 |
|
Cash and cash equivalents |
285 |
- |
238 |
523 |
|
Trade and other payables |
(5,275) |
- |
(344) |
(5,619) |
|
Provision for decommissioning |
(9,831) |
- |
- |
(9,831) |
|
|
52,282 |
100,626 |
31,346 |
184,254 |
|
|
|
|
|
|
|
Total consideration |
|
|
|
184,254 |
|
|
|
|
|
|
|
Total consideration |
|
|
|
184,254 |
|
Less cash and cash equivalents acquired |
|
|
|
(523) |
|
Less accrued consideration |
|
|
|
(12,735) |
|
Less non-cash costs of acquisition* |
|
|
|
(2,247) |
|
Cash outflow on acquisition |
|
|
|
168,749 |
*Non-cash costs of acquisition relates to shares issued to satisfy professional fees payable in respect of the acquisition.
REALLOCATION OF PROVISIONAL FAIR VALUE ALLOCATION
The provisional fair values of oil and gas assets acquired were finalised during 2009, to reflect additional information which became available concerning conditions that existed at the date of acquisition, in accordance with the provisions of IFRS3-Business Combinations. The resulting changes to the 2008 financial statements are set out in the following table:
|
Oil and gas assets* |
Provisional fair value as previously reported US$000's |
Fair value adjustments US$000's |
Fair value as restated US$000's |
|
CI-01 |
35,502 |
65,124 |
100,626 |
|
CI-11 |
89,850 |
(38,316) |
51,534 |
|
Lion GPL |
54,578 |
(26,808) |
27,770 |
|
|
179,930 |
- |
179,930 |
* CI-01 is recorded within intangible assets; CI-11 and Lion GPL are within property, plant and equipment.
The changes in fair values of CI-01 have arisen following completion of an independent review of pre-acquisition data. The review by Netherlands Sewell and Associates (NSAI) indicated existence of higher commercial reserves than previously thought. In respect of CI-11 the changes have arisen following adoption of a recently completed NSAI reserves case. The changes in fair value of Lion GPL arose following adjustment to internal pricing of fuel gas purchased from CI-11 and the reduction in expected throughput upon adoption of NSAI case for CI-11. A reduction in depreciation, depletion and amortisation of $0.4 million charged in second half 2008 has arisen following the above fair value changes and has also been reflected in the restated 2008 comparative financial statements.
8. Share capital and share premium
|
|
|
|
2009 US$000's |
2008 US$000's |
|
(i) Authorised |
|
|
|
|
|
1,200 million ordinary shares of 1p each (equivalent to approx 1.59 cents) (2008:800 million) |
|
|
19,111 |
11,600 |
|
|
|
Equity share capital allotted and fully paid |
Share premium |
|
|
|
|
Number |
US$000's |
US$000's |
|
(ii) Allotted equity share capital and share premium |
|
|
|
|
|
As at 1 January |
|
446,991,859 |
8,806 |
446,958 |
|
Issued during the year for cash (i) |
|
438,722,357 |
6,843 |
305,890 |
|
Non-cash shares issued (ii) |
|
3,351,138 |
53 |
2,321 |
|
As at 31 December |
|
889,065,354 |
15,702 |
755,169 |
(i) Share premium figure is shown net of issue costs of US$14.2 million (2008:US$7.7 million).
(ii) Non-cash shares issued were primarily in respect of the contractual arrangements of the Ebok field.
9. Reconciliation of normalised profit/(loss) after tax to the loss after tax
|
|
2009 |
2008 |
|
Loss after tax |
(16,778) |
(56,122) |
|
Unrealised losses/(gains) on derivative financial instruments |
45,080 |
(51,095) |
|
Cost of move to the main market of The London Stock Exchange |
4,073 |
- |
|
Share based payment charge |
9,292 |
10,819 |
|
Foreign exchange losses |
2,770 |
15,382 |
|
Fair value financial liabilities |
5,034 |
(26,607) |
|
Incentive on early conversion of bonds |
- |
9,332 |
|
Share of loss of an associate |
1,180 |
2,296 |
|
|
|
|
|
Normalised profit/(loss) after tax |
50,651 |
(95,995) |
10. Post balance sheet events
On 4 January 2010, 187,500 shares were awarded to a Director of the Company in respect of the 2008 share awards scheme.
On 28 January 2010, Afren announced that it had entered into a joint venture agreement with Oriental Energy Resources Limited and Energy Equity Resources (EER) for the acquisition of 32.5% interest in OML 115 offshore Nigeria. US$6 million will be paid including signature bonuses and license extension fees in addition to the requirement to drill one firm exploration well at an estimated cost of US$30 million.
On 28 January 2010, Afren provided an operational update and announced that production, processing and storage facilities for the Ebok field, offshore Nigeria had been contracted. The Group signed a contract for a seven-year lease of a Mobile Offshore Production Unit (MOPU) and a Floating Storage Offloading vessel (FSO) unit for the Ebok field, which commits the Group to a US$98,750 day rate exclusive of VAT and withholding tax, over the term of the lease.
On 1 March 2010, Afren noted an announcement by Maurel et Prom, operator of the La Noumbi exploration licence in Congo Brazzaville. The Tie Tie NE well had reached its final depth but although it had shown hydrocarbon indications these were not considered commercial. The well was plugged and abandoned resulting in a 2009 write-off of US$2.1 million, being costs incurred up to the balance sheet date.
On 17 March 2010, Afren announced the signing of an additional drilling contract with Transocean for a drilling rig to carry out planned drilling at the Ebok/Okwok/OML 115 complex and Okoro field offshore south east Nigeria. The contract will run for a period of up to 210 days and has been secured at an operating rate of US$84,000 per day.
On 25 March 2010, Afren announced that it had finalised arrangements for an up to US$450 million reserves based lending ("RBL") debt facility. The up to US$450 million of debt, secured against the Ebok field reserves has a maturity of a maximum of five years and is repayable semi-annually.
Oil and Gas reserves (Net unaudited)
at 31 December 2009
|
|
|
Nigeria(5) |
|
Côte d'Ivoire |
|
Offshore Nigeria & São Tomé and Príncipe |
|
Total Group |
||||||||
|
|
|
Oil (mmbbl) |
Gas(bcf) |
Oil Equivalent(i) (mmbbl) |
|
Oil (mmbbl) |
Gas(bcf) |
Oil Equivalent(i) (mmbbl) |
|
Oil (mmbbl) |
Gas(bcf) |
Oil Equivalent(i) (mmbbl) |
|
Oil (mmbbl) |
Gas(bcf) |
Oil Equivalent-(i) (mmbbl) |
|
Group Proved and Probable Reserves(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At 30 June 2009 |
|
26.9 |
- |
26.9 |
|
0.9 |
22.0 |
4.7 |
|
- |
- |
- |
|
27.7 |
22.0 |
31.5 |
|
Revisions of previous estimates |
|
38.6 |
- |
38.6 |
|
0.1 |
0.7 |
0.2 |
|
- |
- |
- |
|
38.6 |
0.7 |
38.8 |
|
Discoveries and extensions |
|
19.2 |
- |
19.2 |
|
- |
- |
- |
|
- |
- |
- |
|
19.2 |
- |
19.2 |
|
Acquisitions |
|
- |
- |
- |
|
- |
- |
- |
|
- |
- |
- |
|
- |
- |
- |
|
Divestments |
|
- |
- |
- |
|
- |
- |
- |
|
- |
- |
- |
|
- |
- |
- |
|
Production(3) |
|
(3.2) |
- |
(3.2) |
|
(0.1) |
(2.5) |
(0.5) |
|
- |
- |
- |
|
(3.3) |
(2.5) |
(3.7) |
|
At 31 December 2009 |
|
81.4 |
- |
81.4 |
|
0.9 |
20.2 |
4.4 |
|
- |
- |
- |
|
82.3 |
20.2 |
85.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contingent Resources(4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At 30 June 2009 |
|
15.9 |
- |
15.9 |
|
12.9 |
66.0 |
24.2 |
|
1.9 |
- |
1.9 |
|
30.6 |
66.0 |
42.0 |
|
Revisions of previous estimates |
|
(15.2) |
- |
(15.2) |
|
- |
- |
- |
|
- |
- |
- |
|
(15.2) |
- |
(15.2) |
|
Discoveries and extensions |
|
- |
- |
- |
|
- |
- |
- |
|
- |
- |
- |
|
- |
- |
- |
|
Acquisitions |
|
- |
- |
- |
|
- |
- |
- |
|
- |
- |
- |
|
- |
- |
- |
|
Divestments |
|
- |
- |
- |
|
- |
- |
- |
|
- |
- |
- |
|
- |
- |
- |
|
At 31 December 2009 |
|
0.8 |
- |
0.8 |
|
12.9 |
66.0 |
24.2 |
|
1.9 |
- |
1.9 |
|
15.5 |
66.0 |
26.9 |
|
Total Group Proved and Probable Reserves and Contingent Resources at 31 December 2009 |
|
82.2 |
- |
82.2 |
|
13.8 |
86.2 |
28.6 |
|
1.9 |
- |
1.9 |
|
97.8 |
86.2 |
112.7 |
Source: Netherland, Sewell & Associates, Inc.
(1) Quantities of oil equivalent are calculated using a gas-to-oil conversion factor of 5,800 scf of gas per barrel of oil equivalent.
(2) Proved plus probable (2P) reserves have been prepared in accordance with the definitions and guidelines set forth in the 2007 PRMS approved by the SPE.
(3) Working interest production estimates provided by Afren plc.
(4) Contingent resources are those quantities of petroleum that are estimated to be potentially recoverable from known accumulations but for which the projects are not yet considered mature enough for commercial development due to one or more contingencies.
(5) Excludes Okwok and OPL 907/917 not yet evaluated by NSAI.
The Group provides for depletion and amortisation of tangible fixed assets on a net entitlement basis, which reflects the terms of the licenses and agreements related to each field. Total net entitlement reserves were 72.5 mmboe at 31 December 2009.
Glossary of Terms
AGM
Annual General Meeting
appraisal well
A well drilled to follow up a discovery and evaluate its commercial potential
bbls
barrels of oil
bcf
billion cubic feet of gas
boe
barrels of oil equivalent
boepd
barrels of oil equivalent per day
bopd
barrels of oil per day
capital employed
equity plus interest-bearing debt
CR
Corporate Responsibility
deg API
a measure of how heavy or light a petroleum liquid is compared with water
dwt
dead weight tonnage
EHSS
environment, health, safety and security
farm-in
to acquire an interest in a licence from another party
farm-out
to assign an interest in a licence to another party
FPSO
Floating Production Storage and Offloading vessel
ft
feet
GOR
Gas Oil Ratio
H1
first half
H2
second half
Hydrocarbons
compounds containing only the elements hydrogen and carbon; they may exist as solids, liquids or gases
JDZ
Joint Development Zone
joint venture or JV
a group of companies who share the cost and rewards of exploring for and producing oil or gas from a permit or licence
km2
square kilometres
licence or permit
area of specified size, which is licensed to a company by the government for production of oil and gas
LSE
London Stock Exchange
Major
Major international oil company
m
metres
mmbbl, mmbbls
million barrels
mmboe
millions of barrels of oil equivalent
mmcf/d
million cubic feet of gas per day
MOPP
Mobile Offshore Production Platform
MOU
Memorandum of Understanding
OML
Oil Mining Licence
operator
a company which organises the exploration and production programmes in a permit or licence on behalf of all the interest holders in the permit or licence
OPL
Oil Prospecting Licence
Q1
first quarter
Q2
second quarter
Q3
third quarter
Q4
fourth quarter
spud
to commence drilling a well
STOIIP
Stock Tank Oil Initially In Place
tcf
trillion cubic feet of gas
WI
working interest
1P
proven
2P
proven and probable
3P
proven, probable and possible
3D
three-dimensional
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