afren 1h11 financials

Afren plc | 2011 Half-yearly Results 1

Strong production growth outlook; active E&A drilling campaign; significant low cost barrels acquired

Afren plc (“Afren” or the “Company”) (LSE: AFR), the independent oil and gas exploration and production Group, announces its Half-

yearly Results for the six months ended 30 June 2011.

2011 Half-yearly Results Summary The financial results for the first half of the year reflect a lower net production rate compared to the same period in 2010, due

primarily to cost recovery being achieved at the Okoro field and longer than expected periods of facilities related down time at the

Ebok field. This has been partially offset by significantly higher price realisations and lower cost of sales.

Financial highlights 1H 2011 1H 2010 Change

Turnover (US$mm) 161.0 214.8 (25.0)%

Gross Profit (US$mm) 79.2 97.0 (18.4)%

Profit/(Loss) Before Tax (US$mm) 43.7 75.4 (42.0)%

Normalised Profit/(Loss) After Tax (US$mm)* 26.1 54.5 (52.1)%

Net W.I. production (boepd)** 13,000 20,400 (36.3)%

Realised oil price (US$/bbl) 110.4 77.8 41.9%

Realised gas price (US$/mcf) 8.0 5.2 53.8%

*See note 3 of the interim financial statements

**Working interest, including natural gas liquids

Key highlights

• Company well positioned with major asset base in high potential basins

• Reservoir performance at Ebok at upper end of expectations

• Okoro reservoir performance continues at upper end of expectations; infill wells onstream and elective

de-bottlenecking of FPSO undertaken to increase gross liquids capacity

• Full year net working interest production guidance 25,000 boepd, with an exit rate of 50,000 boepd

• Forward exploration programme targeting 930 mmboe of net prospective resources

• Low cost reserves acquisition of two contiguous PSCs (post period end) – Barda Rash (60 per cent. operated) and Ain Sifni (20 per cent. non-operated) in the Kurdistan region of Iraq (expected to complete in September)

• 890 mmbbls net working interest 2C resources • Low acquisition cost of US$0.66 per 2C bbl • Five year line of sight on 75,000 bopd net from Barda Rash PSC alone • Substantial low risk exploration upside

• Strong financial position; cash at bank US$320.9 million; net debt US$343.0 million – gearing 37.5%


Osman Shahenshah, Chief Executive of Afren plc, commented:

“Afren continues to make good operational progress, with reservoir performance and

drilling results at our Ebok and Okoro fields at the upper end of expectations. Whilst

first half production volumes were impacted by periods of non-reservoir related

facilities down time, we are now ramping up production towards our targeted 50,000

boepd exit rate. We are delighted to have acquired, post the period end, a high

quality portfolio of assets in, and gain entry into the Kurdistan region of Iraq. The

acquisition is consistent with our strategy of acquiring low cost barrels, increases our

2P and 2C recoverable reserves and resources base by over 700 per cent. at a cost

of under US$1 per barrel and means that Afren is now strategically positioned in two

of the world‟s most prolific oil producing countries in Nigeria and Iraq. Our planned

exploration campaign is due to commence shortly with the drilling of key wells in

each of our core regions that, if successful, could materially increase the Company‟s

reserves base. Financially we are in a strong position with low gearing and

substantial resources available to execute our planned work programme and pursue

further inorganic growth opportunities that are available to us”.

26 August 2011

Analyst Presentation There will be a presentation to analysts at 09:00 BST in The Auditorium, Bank of America Merrill Lynch,

2 King Edward Street, London EC1A 1HQ.

The presentation will also be broadcast live at www.afren.com where the accompanying presentation will be

available, and on playback from 12:00 BST.

Operations review


The first half of 2011 was another period of significant progress across all areas of Afren‟s activities. Operationally, reservoir

performance at the Okoro and Ebok fields has been at the upper end or ahead of expectations. Net production during the period

averaged 13,000 boepd, reflecting the delayed start up of the Ebok field and longer than expected periods of facilities downtime at

the field. The Company expects production over the second half of the year to increase sharply now that full facilities uptime has

been restored and that net working interest production over the full year will average approximately 25,000 boepd, with an exit rate

of approximately 50,000 boepd net to Afren. Financially, the Company has maintained a conservative capital structure. During the

period, Afren became the first UK listed independent E&P company to access the bond market with a US$500 million high yield

offering. Afren has continued to expand its portfolio and selectively add high potential opportunities with the acquisition of the Tanga

Block in Tanzania and Block 2B in South Africa. Post period end, Afren announced the acquisition of a 60 per cent. interest in the

Barda Rash PSC and 20 per cent. interest in the Ain Sifni PSC, in the Kurdistan region of Iraq. The acquisition is consistent with

Afren‟s strategy of acquiring low cost barrels in areas with strategic advantage and increases the Company‟s current 2P and 2C

recoverable reserves and resources base by over 700 per cent. at a cost of under US$1.0/bbl.

Sub Saharan Africa

Production and development operations update

Nigeria

Ebok

Production experience to date from development Phase 1 has confirmed that reservoir properties and productivity of the D2

reservoir wells are at the upper end of expectations. In December 2010, three out of the five D2 reservoir production wells were

tested at an aggregate rate of 12,500 bopd. Following the full commissioning and production start up of Phase 1, production

increased to a rate of 17,000 bopd from all five wells.

Post period end, the Company has also completed and brought onstream a production well targeting the D1 reservoir, also in the

Central Fault Block area. The well has produced significantly ahead of expectations, delivering a rate of 4,000 bopd with a down-

hole pump installed. As a consequence, the partners have elected to prioritise additional development of the D1 reservoir at this

location.

Production during the period was, however, impacted by non-reservoir related periods of facilities down time. This was due to a

longer than anticipated commissioning period for the Mobile Offshore Production Unit (MOPU), necessary suspension of production

during simultaneous drilling and production operations, fine tuning of the process facilities and commissioning of the gas turbines

and related systems to deliver the water injection capability. As a consequence, production at the field during the first half of the

year was 3,300 bopd. This work has now been completed, and production from Phase 1 is being ramped up to a rate of 15,000

bopd to 17,000 bopd.

Development drilling at Phase 2, targeting the West Fault Block area of the field, is underway with the GSF High Island Vll drilling

rig, and comprises of five horizontal production wells and up to two water injection wells. Drilling results to date have been better

than pre drill expectations, giving longer oil bearing sections and better reservoir properties in the LD-1E reservoir in particular.

Three wells will be bought onstream shortly, with Phase 2 expected to add 20,000 bopd to gross field output once all five wells are

onstream.

Ongoing work programme

Post completion of Phase 2, the GSF High Island Vll rig will proceed with the drilling of additional production wells targeting the

South West area of the field. These will be drilled from its current location at the West Fault Block wellhead platform. The Adriatic

lX rig is next scheduled to commence the drilling of three D1 production wells from the Phase 1 wellhead platform location, followed

by an exploration well to test the 35 million barrel resource Ebok North prospect.

Okoro

During the period the Company and its partner Amni successfully completed a two well infill drilling campaign, bringing the Okoro-11

and Okoro-12 horizontal production wells onstream. The resultant production impact was to increase gross output at the field to

21,000 bopd. Elective de-bottlenecking work at the Floating Production Storage Offloading vessel (FPSO) has been undertaken to

increase gross liquids handling capacity from the initial 27,000 bpd. The increased total fluid handling capacity will allow for oil

production to be maintained at higher levels for longer. As a result of this work and the necessary period of production suspension,

gross output at the field over the first half of the year averaged 14,600 bopd. Gross production at the field is currently between

Operations review


18,000 to 19,000 bopd. Ongoing studies of the field and immediate surrounding area have identified additional future drilling targets.

In particular, the Okoro East prospect has similar sub surface characteristics to the main Okoro field, and is estimated to have

similar resource potential. The partners are exploring options that could potentially result in the accelerated drilling of this attractive

near field target.

OML 26 – First Hydrocarbon Nigeria

Post completion of the acquisition of a 45 per cent. interest in OML 26, Afren and First Hydrocarbon Nigeria (“FHN”) will seek to

implement together with NNPC a three phase development plan for the Ogini and Isoko fields, with the goal of ultimately increasing

gross production to a rate of 50,000 bopd. Under the proposed development plan, initial work will be focused on certain “quick-win”

opportunities including low-cost workovers of existing wells and re-activation of gas lift. Once implemented, these measures are

expected to increase gross field production by around 50 per cent. over and above current levels (approximately 5,000 to 6,000

bopd). The partners will then seek to mobilise a land rig to the field location and commence the drilling of an initial six horizontal

production wells.

Afren and FHN will continue to seek out further opportunities to expand the partnership through the acquisition of other substantial

oil and gas assets in Nigeria including those that are currently held between the Nigerian government and major international oil

companies, assets that could be diversified in connection with indigenous licensing rounds and assets of other Nigerian companies

if appropriate.

Côte d’Ivoire

CI-11 and Lion gas Plant

Average production during the period at CI-11 was 16.3 mmcfd and 900 bopd, with 600 boepd of NGL production at the Lion Gas

Plant. Production levels were below expectation during the period due to the impact of political and social unrest delaying the import

of necessary equipment and resources required to conduct routine maintenance of the compressor unit during the first quarter of

2011.

Exploration and appraisal operations update

Nigeria

Okwok

Having established the Okwok field as a future commercial development, with NSAI ascribing 51.8 mmbbls of gross recoverable

resources following completion of the Okwok-9 appraisal well in November 2010, an extensive multi component Ocean Bottom

Cable (OBC) 3D seismic survey is now underway across the broader Okwok area that will provide important additional data to assist

with further appraisal and development planning. The Company expects seismic acquisition to conclude in September, and

following a period of interpretation and integration with existing data intends to spud an appraisal well in 1H 2012 with formal

submission of a Field Development Plan (FDP) anticipated in mid 2012. Given the scale of recoverable resources already proved, it

is considered most likely that Okwok will require a stand-alone development solution, but potentially sharing existing storage and

offtake facilities that have been installed at the Ebok field.

OML 115

Following completion and interpretation of the seismic programme currently underway across the Ebok/Okwok/OML 115 area, an

exploration well is now planned on OML 115 with expected spudding in mid 2012. The Ufon prospect is a 60 mmbbls target that is

interpreted to have oil prospectivity in the same D Series reservoirs that have been proven to be oil bearing at the nearby Ebok and

Okwok fields.

OPL 310

OPL 310 extends from the shallow water continental shelf to deep water offshore south west Nigeria, and represents a high potential

exploration opportunity in an under explored basin with a proven working hydrocarbon system. Afren has identified several

prospects that lie in the same Cenonian, Turonian and Albian sandstone intervals that have yielded significant discoveries along

with West African Transform Margin in Ghana and Côte d‟Ivoire. The Company has a formal farm down process underway to attract

an industry partner to participate in future exploration of this high potential block. Plans are also in place to acquire additional

seismic on the block.

Operations review


OPL 907/917

OPL 907 and 917 contain potentially attractive Cretaceous opportunities. The main hydrocarbon plays consist of late Cretaceous

deltaic to shallow marine clastics in fault related traps. Having acquired the original seismic tapes and reprocessed the data, Afren

continues to evaluate the potential of the blocks in order to identify areas for future seismic acquisition that could ultimately lead to

future exploration drilling.

Côte d’Ivoire

CI-01

The block has a proven petroleum system in multiple Cretaceous reservoirs. Oil and gas has been found in the Ibex and Kudu

fields, while only gas has been found in the Eland field. A full technical evaluation of the Kudu field has now been completed,

following on from previous work undertaken at the Ibex field. Afren and its partners on the block intend to acquire new block wide

3D seismic in order to provide a greatly expanded contiguous data set with a view to ultimately defining optimal appraisal dr illing

locations for the existing discoveries on the acreage.

Ghana

Keta Block

In March 2011, Afren announced the farm down of a 35 per cent. interest in the Keta block and transfer of operatorship to ENI (Afren

retains a 35 per cent. interest). All approvals for the assignment of this interest to ENI have been received from the Government of

Ghana. Under the terms of the farm down Afren will receive a carry through the drilling of one exploration well, back costs and carry

through future seismic acquisition and a milestone bonus payable upon the achievement of first oil on the block. The partners plan

to drill an exploration well targeting the 325 mmbbls Cuda prospect this year. The well was provisionally scheduled, at the time of

farm down, to spud during the third quarter with the Marianas semi-submersible drilling unit. However the rig was damaged whilst

under mobilisation in July, which is likely to have an impact on the expected spud date, presently anticipated to occur by year end.

In its most recent independent assessment NSAI more than doubled its view of gross unrisked prospective resources on the block to

1,412 mmbbls.

Nigeria – São Tomé & Príncipe JDZ

The new operator on Block 1, Total, is seeking to reprocess existing seismic data and has proposed the drilling of one appraisal well

on the Obo discovery in 2011 and one exploration well in 2012. Afren has a 4.41 per cent. interest. The first well is expected to

spud in the fourth quarter of 2011 with the Pacific Scirocco drilling rig.

Congo Brazzaville

The La Noumbi permit is located onshore Congo Brazzaville, to the North and on trend with the large producing M‟Boundi oil field.

The partners are currently defining a forward work programme have recently entered the next exploration phase on the block.

South Africa

Block 2B

During the period, Afren completed the acquisition of Block 2B, located in offshore shallow water in the Orange River Basin, lying

between the Ibhubesi gas field and the Namaqualand coast. The block covers an area of approximately 5,000 km2 with water

depths ranging from shore line to 250 metres. The partners near term work programme involves the acquisition of 600 km2 of new

3D seismic data, with reprocessing of existing 2D seismic and ongoing seismic inversion and regional biostratigraphy studies ahead

of expected exploration drilling in 2012.

Operations review


East Africa

Exploration and appraisal operations update

Kenya

Block L17/18

Following completion of a 400 km 2D seismic acquisition programme in 2010, a number of newly defined prospects and leads have

been identified on the acreage. The Company intends to acquire additional 2D seismic in the fourth quarter of 2011.

Block 10A

The Tullow Oil operated joint venture acquired 750 km of 2D seismic over the block during the first quarter of 2011 to supplement

the existing 2D coverage of 2,631 km. Integration of the new data and interpretation is underway. This work satisfies all seismic

obligations for the current exploration period. The operator has proposed the drilling of one exploration well during the fourth quarter

of 2011/first quarter of 2012 depending on the timing of rig arrival.

Block 1

The partners on Block 1 plan to acquire 1,200 km of 2D seismic data commencing in the third quarter of 2011. Airborne gravity and

magnetic data was acquired in the first half of 2011, the results of which are very encouraging and are being used to target the

planned 1,200 km seismic. Several major structures have already been mapped on the block that currently has 850 km of 2D

seismic coverage.

Tanzania

Tanga Block

On 24 March 2011, Afren announced the acquisition of a 74 per cent. operated working interest in the Tanga Block, located offshore

Tanzania. The block is well located in that it lies across a deep basin with a very thick sedimentary section that has the potential of

hosting several source rock intervals and multiple reservoir/seal pairings. The block is covered by 200 km of legacy 2D seismic

data, and 1,200 km of good quality new 2D seismic data. Immediately post completion, Afren undertook and completed a 751 km

shallow water 2D seismic programme. Early results are encouraging, and provide excellent definition of several large scale

prospects and leads that have been identified to date, together with new zones of additional potential. Additional deep water

seismic will be acquired on the block during 2H 2011.

Ethiopia

Blocks 2,6,7,8

During 2010 a 2D seismic acquisition programme was completed across the onshore Blocks 2, 6, 7 and 8. Within the current

exploration period, the partners have obtained 15,000 km of airborne gravity and magnetic data, 551 km of 2D seismic data and are

required to drill one exploration well. The partners have opted to focus future exploration efforts on Blocks 7 and 8 that hold the El-

Kuran oil discovery, and have indicated to the Ethiopian authorities the intention to relinquish Blocks 2 and 6. Work is ongoing to

further interpret the prospectivity of Blocks 7 and 8 ahead of expected drilling in 2012.

Madagascar

Block 1101

In July the Company announced that Government approvals had been received for Afren to assume operatorship and increase its

interest in Block 1101 to 90 per cent. and that a revised work programme had also been agreed with OMNIS, the state oil and gas

agency. Under the agreed terms of reassignment, Afren has increased its overall participation in Block 1101 to a 90 per cent.

operated interest through the reassignment of a 50 per cent. interest previously held by Candax Energy, who remain partners on the

block with a 10 per cent. interest. The expanded work programme combines the first two exploration phases on the block and

requires the drilling of one exploration well to a minimum depth of 1,600 metres. The partners have also agreed to acquire an

additional 150 km of new 2D seismic and airborne gravity and magnetics. Under the revised ownership structure and work

programme, it is expected that drilling will now commence in late 2012.

Operations review


Seychelles

Blocks A,B,C

Seismic data acquired to date by the partners has revealed the presence of several large scale structures in all three license areas,

in addition to new basins that could also contain significant Jurassic and Cretaceous sedimentary sections. The partners have a

tender process underway as a precursor to acquiring new seismic data during the second half of 2011 over Blocks A,B and C,

ahead of expected exploration drilling.

Kurdistan region of Iraq

Strategic entry into a prolific oil and gas producing region (post period end)

On 27 July 2011 (post period end), Afren announced the acquisition of a 60 per cent. operated interest in the Barda Rash PSC and

20 per cent. non-operated interest in the Ain Sifni PSC, both of which are located in the Kurdistan region of Iraq, from Komet Group

and the Kurdistan Regional Government respectively. The acquisition represents a highly complementary extension of the

Company‟s existing portfolio, and offers a combination of near term development upside and substantial low risk exploration

potential. Independently certified net 2C resources at Barda Rash and Ain Sifni are 890 mmbbls with total net unrisked resources

estimated to be 1,074 mmbbls.

The total amount payable for the acquisition is US$588.25 million (US$0.66 per 2C barrel) inclusive of approximately US$81 million

back costs and US$14 million 2011 capex related to Ain Sifni, of which US$388.25 million will be due on closing and US$200

million six months from closing. On 28 July, Afren completed the placing of 83,679,544 new ordinary shares at a price of 135 pence

per share, raising a total of US$184.5 million before fees, the proceeds of which will be used to part-fund the acquisition

consideration. The Company has also agreed terms and conditions and mandated BNP Paribas and VTB Capital to arrange an up

to US$200 million corporate credit facility.

Barda Rash PSC

The Barda Rash PSC is located 55 km North West of Erbil, and holds the 14,174 mmbbls STOIIP/1,470 mmbbls gross recoverable

resources Barda Rash oil field (split 506 mmbbls light oil and 964 mmbbls heavy oil). The field is defined as an elongated anticline

with surface expression of 20 km length and up to 7 km width. The reservoirs are principally fractured carbonates of various

depositional settings. Three wells have been drilled on the field to date, BR-1, BR-2 and BR-3, all of which have encountered oil.

The main reservoir targets are the Cretaceous, Jurassic and Triassic sequences. The field is defined by 330 km of good quality 2D

seismic data. The Company plans to undertake a phased development of the field with production start-up scheduled for early

2012. Initial work will focus on developing 506 mmbbls recoverable light oil resource that is anticipated to deliver gross production

of 125,000 bopd by 2017 (giving five year line of sight on 75,000 bopd net to Afren). Production will initially be trucked to nearby

export pipeline entry points, and ultimately exported via the planned Taq Taq to Ceyhan pipeline. Ongoing development would then

focus on the development and production of 964 mmbbls of recoverable heavier oil resource, offering further large scale production

growth potential over the medium to longer term. In order to facilitate the execution of the work programme, the Company has put in

place a team of regional experts with an extensive experience of working on fracture carbonate reservoirs characteristic of those

present in the Kurdistan region of Iraq.

Ain Sifni PSC

The Ain Sifni PSC is located 70 km North West of Erbil, and is operated by Hunt Oil Middle East. Drilled on the crest of the Jebel

Simrit anticline in 2010, the JS-1 discovery well logged continuous oil pay from 1,110 m to 3,070 m in Cretaceous and Jurassic

reservoirs. Triassic reservoir targets were not penetrated by the well and no oil water contact was established. Independently

certified gross 2C STOIIP and recoverable resources associated with the well are 391 mmbbls and 42 mmbbls respectively. The

PSC has substantial upside over and above the volumes of 2C resources established to date, with prospective resources

independently estimated at 7,493 mmbbls STOIIP and 917 mmbbls recoverable on a gross un-risked basis. This is primarily

attributed to as yet un-drilled parts of the Jebel Simrit structure and the Maqlub prospect that is interpreted to be the Westerly

extension of the proven Barda Rash anticline. An exploration well, Jebel Simrit-2, is planned to spud early fourth quarter 2011 to

appraise and production test the western extent of the Jebel Simrit structure. Exploration wells are also scheduled to test the low

risk Maqlub, Betnaar and East Simrit structures.

Finance review


1. Result for the period

Afren‟s results for the first six months of 2011 reflect the reduction during 2010 of the Company‟s economic interest in the Okoro

field to 50 per cent. (from 95 per cent.) following cost recovery, and the slower than expected ramp up of production at the Ebok field

due to longer than planned periods of non-reservoir related facilities downtime. Working interest production during the period

averaged 13,000 boepd (20,400 boepd in 1H 2010). Revenue during the period was US$161.0 million (1H 2010: US$214.8 million),

with higher price realisations partially offsetting the reduced production share year-on-year. The Company realised an average oil

price of US$110.4/bbl in 1H 2011 and an average gas price of US$8.0/mcf (1H 2010: US$77.8/bbl and US$5.2/mcf). The average

price for Brent in the period was US$111/bbl.

Gross profit

Gross profit for the period was US$79.2 million, a decrease of 18% on the prior period (1H 2010: US$97.0 million) driven largely by

the lower revenue in the period. The DD&A charge for oil and gas assets in 1H 2011 was US$53.2 million, a reduction of 16% on

the prior year (1H 2010: US$63.0 million), also due to our lower economic interest production.

Profit for the period

Profit after tax on continuing activities for the six months ended 30 June 2011 was US$22.8 million (1H 2010: US$50.7 million).

Normalised profit after tax, which excludes the effect of unrealised hedge movements, share related charges and other items, was

US$26.1 million, see note 3 to the interim report for a full reconciliation of this figure (1H 2010: US$54.5 million).

Administrative expenses increased from US$14.9 million in 1H 2010 to US$19.2 million for the six months ended 30 June 2011

reflecting the increasing scale of Afren‟s business. The impairment charge on oil and gas assets was US$0.2 million (2010: US$1.1

million).

Finance costs for 1H 2011 were US$22.6 million (1H 2010: US$6.2 million). Additional financing costs of US$24.6 million were

capitalised as part of the Ebok project prior to first production and the Okoro infill well programme (1H 2010: US$1.8 million).

Overall charges were increased due to the High Yield Bond issued in January 2011, a one-off charge of $7.4m relating to the early

repayment of pre-existing facilities and also the higher debt in the period, arising from the ongoing development of the Ebok field.

During the period we recognised a loss from derivative financial instruments of US$12.0 million (1H 2010: US$0.2 million gain)

relating to crude oil hedging contracts. This reflects a realised loss of US$3.4 million (1H 2010: US$0.9 million) as the oi l price

realised averaged above the hedged price during the period. There was a further mark-to-market loss of US$8.6 million (1H 2010:

US$1.1 million gain) on the unrealised positions due to further strengthening in the oil price from around US$94 per barrel at the

start of the year to over US$111 per barrel at 30 June 2011. The contracts in place are predominately put options priced between

US$80-90/bbl at an average cost of US$4/bbl over the contract length. Although these instruments have been designated as cash

flow hedges, because the oil price during the period was above the hedged price a loss is recognised for accounting purposes which

represents the expected future cost of these hedges. This loss is limited to the total cost of the put option contracts over the

remaining contract period.

The policy of the Company is to protect its minimum cashflow requirement in the context of a sustained downturn in oil prices. As

such the maximum amount of our working interest we would seek to protect with these arrangements is between 20-30% of

estimated production for a rolling period of 24 months forward.

The share of gain of an associate of US$18.3 million (1H 2010: US$0.6 million loss) relates to our interest in FHN and represents

Afren‟s 45% share of the result for the period plus Afren‟s proportionate share of the net asset value of the underlying enti ties

balance sheet. The gain principally reflects new equity funding raised by FHN, attributable to our 45% interest.

The income tax charge for the period is US$20.9 million (1H 2010: US$24.7 million).

2. Financing the Company’s activities

Net cash generated from operating activities in 1H 2011 was US$16.6 million (1H 2010: US$91.4 million), and this cash has been

used alongside financing cashflows primarily to fund the Company‟s development, appraisal and exploration activities. The

decrease in net cash generated from operations is due to the lower operating profit and an increase in working capital as inventory

levels and receivables were higher as at 30 June 2011 due to the ongoing development and production activities.

Finance review


In early 2011, the Company completed a Bond issue, raising US$500 million before issue costs. The coupon on the bonds is 11.5%

and they are listed on the Luxembourg Stock Exchange. The Company used part of the funds to repay borrowings amounting to

US$171 million of certain pre-existing facilities.

Gross debt before unamortised issue costs as at 30 June 2011 was US$691.3 million (1H 2010: US$218.6 million), comprising

US$500 million and US$191 million in respect of the High Yield Bond and the Ebok facility respectively. Loan repayments

in the period were US$183.8 million reflecting repayment in full of the Okoro facility and the facilities used to finance the

Côte d‟Ivoire acquisition and periodic payments due under other facilities. Cash at bank at 30 June 2011 was US$320.9 million

(1H 2010: US$194.0 million), resulting in net debt after issue costs and excluding finance leases of US$343.0 million (1H 2010:

US$12.2 million).

3. Development, appraisal and exploration activities

The Company‟s investment in appraisal and exploration activities has continued during 2011, with expenditure of approximately

US$23 million (1H 2010: US$25 million). The main areas of expenditure were on OML115 (US$5.1 million), the acquisition of a 74%

interest in the Tanga block in Tanzania and seismic on the area (US$4.2 million) and expenditure, largely seismic and G&G studies,

on the newly acquired East African exploration assets (US$6.6 million).

Development expenditure was US$212 million, comprising US$172 million on the Ebok field and US$40 million on the Okoro infi ll

programme.

4. Ebok finance lease

In 1H 2011 the Group recognised a finance lease in respect of the arrangements with Mercator Offshore Nigeria (Pte) Limited for the

production facilities on the Ebok field. This resulted in a finance lease liability at 30 June 2011 of US$162.5 million to be settled in

monthly payments of US$2.4 million (including interest) over a seven year period.

5. 2H 2011 Acquisition & equity placement

In July 2011 (post period end), the Company announced the acquisition of interests in two contiguous PSCs located in the Kurdistan

region of Iraq. The total amount payable for the acquisition is approximately US$588.3 million. In parallel the Company announced

the successful placement of 83,679,544 ordinary shares, raising a total of £113.0 million (US$184.5 million) before fees which will be

used, together with cash and debt resources, to fund the acquisition.

6. Related party transactions

Related party transactions are disclosed in note 9 to the condensed set of financial statements. There have been no material

changes in the related party transactions described in the last annual report.

7. Principal risks to 2011 performance

There are a number of potential risks and uncertainties which could have a material impact on the Group‟s performance over the

remaining six months of the financial year and could cause actual results to differ materially from expected and historical results.

The Directors do not consider that the principal risks and uncertainties have changed since the publication of Annual Report and

Accounts for the year ended 31 December 2010. The principal risks faced by Afren relate to operational risks involving the delivery

of the Ebok, Okoro and CI-11 production targets, political risks in Nigeria, Côte d‟Ivoire and Kurdistan and strategic risks associated

with the growth of the organisation and the economic climate. A detailed explanation of these risks can be found on pages 42 to 43

of the 2010 Annual Report and Accounts which is available at www.afren.com.

8. Going concern

As stated in note 1 to the condensed financial statements, the Directors are satisfied that the Group has sufficient resources to

continue in operation for the foreseeable future, being a period of not less than 12 months from the date of this report. Accordingly,

they continue to adopt the going concern basis in preparing the condensed financial statements.

The outlook for the remainder of 2011 is positive. We continue to make good operational progress, with reservoir performance and

drilling results at our Ebok and Okoro fields at the upper end of expectations and we are ramping up production towards our targeted

50,000 boepd exit rate. Our planned exploration campaign is due to commence shortly with the drilling of key wells in each of our

core regions that, if successful, could materially increase the Company‟s reserves base. Financially we are in a strong position with

low gearing and substantial resources available to execute our planned work programme and pursue further inorganic growth

opportunities that are available to us.

Responsibility statement


The Directors confirm that to the best of their knowledge:

a) the condensed set of financial statements has been prepared in accordance with lAS 34 'Interim Financial Reporting';

b) the Half-yearly management report includes a fair review of the information required by DTR 4.2.7R (indication of important

events during the first six months and description of principal risks and uncertainties for the remaining six months of the year); and

c) the Half-yearly management report includes a fair review of the information required by DTR 4.2.8R (disclosure of related parties'

transactions and changes therein).

By order of the Board,

Osman Shahenshah Darra Comyn

Chief Executive Group Finance Director

26 August 2011 26 August 2011

Disclaimer

This statement contains certain forward-looking statements. These statements are made by the Directors in good faith based on

the information available to them up to the time of their approval of this report but such statements should be treated with caution

due to the inherent uncertainties, including both economic and business risk factors, underlying any such forward-looking

information. This interim management report has been prepared solely to provide additional information to shareholders to assess

the Group‟s strategies and the potential for those strategies to succeed. The report should not be relied on by any other party or for

any other purpose.

Independent review report to Afren plc


We have been engaged by the Company to review the condensed set of financial statements in the Half-yearly financial report for

the six months ended 30 June 2011 which comprises the condensed group income statement, the condensed group balance sheet,

the condensed group statement of changes in equity, the condensed group cash flow statement, and related notes 1 to 11. We

have read the other information contained in the Half-yearly financial report and considered whether it contains any apparent

misstatements or material inconsistencies with the information in the condensed set of financial statements.

This report is made solely to the Company in accordance with International Standard on Review Engagements (UK and Ireland)

2410 “Review of Interim Financial Information Performed by the Independent Auditor of the Entity” issued by the Auditing Practices

Board. Our work has been undertaken so that we might state to the Company those matters we are required to state to it in an

independent review report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume

responsibility to anyone other than the Company, for our review work, for this report, or for the conclusions we have formed.

Directors' responsibilities

The Half-yearly financial report is the responsibility of, and has been approved by, the Directors. The Directors are responsible for

preparing the Half-yearly financial report in accordance with the Disclosure and Transparency Rules of the United Kingdom‟s

Financial Services Authority.

As disclosed in note 1, the annual financial statements of the Group are prepared in accordance with IFRS as adopted by the

European Union. The condensed set of financial statements included in this Half-yearly financial report has been prepared in

accordance with International Accounting Standard 34, “Interim Financial Reporting,” as adopted by the European Union.

Our responsibility

Our responsibility is to express to the Company a conclusion on the condensed set of financial statements in the Half-yearly

financial report based on our review.

Scope of Review

We conducted our review in accordance with International Standard on Review Engagements (UK and Ireland) 2410 “Review of

Interim Financial Information Performed by the Independent Auditor of the Entity” issued by the Auditing Practices Board for use in

the United Kingdom. A review of interim financial information consists of making inquiries, primarily of persons responsible for

financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than

an audit conducted in accordance with International Standards on Auditing (UK and Ireland) and consequently does not enable us to

obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not

express an audit opinion.

Conclusion

Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in

the Half-yearly financial report for the six months ended 30 June 2011 is not prepared, in all material respects, in accordance with

International Accounting Standard 34 as adopted by the European Union and the Disclosure and Transparency Rules of the United

Kingdom's Financial Services Authority.

Deloitte LLP

Chartered Accountants and Statutory Auditor

London, United Kingdom

26 August 2011


Condensed Group Income Statement for the six months to 30 June 2011

Notes

6 months to

30 June

2011

Unaudited

US$000’s

6 months to

30 June

2010

Unaudited

US$000‟s

Year to

31 December 2010

Audited

US$000‟s

Revenue 161,005 214,750 319,447

Cost of sales (81,838) (117,755) (190,451)

Gross profit 79,167 96,995 128,996

Administrative expenses (19,178) (14,871) (29,500)

Other operating (expenses)/ income

– impairment of oil and gas assets (171) (1,143) (1,614)

– derivative financial instruments (12,029) 153 (8,894)

Operating profit 47,789 81,134 88,988

Investment revenue 160 237 298

Finance costs (22,615) (6,185) (11,320)

Other gains and (losses)

– foreign currency gains 372 524 305

– fair value of financial liabilities and

financial assets (232) 280 (8,100)

Share of gain/(loss) of an associate 18,274 (604) 8,625

Profit from continuing activities before tax 43,748 75,386 78,796

Income tax expense (20,947) (24,662) (32,923)

Profit from continuing activities after tax 3 22,801 50,724 45,873

Discontinued operations

Loss for the period from discontinued operations (2,137) – (614)

Profit for the period 20,664 50,724 45,259

Profit per share from continuing operations

Basic 2 2.3c 5.7c 5.1c

Diluted 2 2.2c 5.2c 4.9c

Profit per share from continuing and discontinued

operations

Basic 2 2.1c 5.7c 5.0c

Diluted 2 2.0c 5.2c 4.8c

There are no items of comprehensive income not included in the income statement.


Condensed Group Balance Sheet as at 30 June 2011

30 June 2011

Unaudited

US$000’s

30 June 2010

Unaudited

US$000‟s

31 December 2010

Audited

US$000‟s

Assets

Non-current assets

Intangible oil and gas assets 467,171 209,409 443,761

Property, plant and equipment

– Oil and gas assets 1,120,879 568,423 759,167

– Other 10,581 6,764 6,919

Prepayments 1,283 2,683 1,983

Derivative financial instruments 13,758 1,818 –

Investment in associates 32,501 – 11,227

1,646,173 789,097 1,223,057

Current assets

Inventories 70,503 46,020 39,055

Trade and other receivables 114,873 103,934 41,343

Derivative financial instruments – 3,733 –

Cash and cash equivalents 320,904 194,019 140,221

506,280 347,706 220,619

Assets held for sale – – 2,812

Total assets 2,152,453 1,136,803 1,446,488

Liabilities

Current liabilities

Derivative financial instruments (10,919) (3,277) (4,927)

Borrowings (86,000) (72,000) (89,254)

Obligations under finance lease 6 (21,222) – –

Trade and other payables (286,797) (148,562) (216,037)

(404,938) (223,839) (310,218)

Net current assets/(liabilities) 101,342 123,867 (86,787)

Non-current liabilities

Deferred tax liabilities (59,721) (34,430) (63,470)

Provision for decommissioning (37,428) (30,341) (35,119)

Borrowings (577,881) (134,238) (178,467)

Obligations under finance lease 6 (141,232) – –

Derivative financial instruments (16,849) (135) (499)

(833,111) (199,144) (277,555)

Total liabilities (1,238,049) (422,983) (587,773)

Net assets 914,404 713,820 858,715

Equity

Share capital 17,248 15,734 17,007

Share premium 913,951 756,469 896,812

Other reserves 20,102 17,674 22,764

Accumulated losses (36,897) (76,057) (77,868)

Total equity 914,404 713,820 858,715


Condensed Group Cash Flow Statement for the six months to 30 June 2011

6 months to

30 June 2011

Unaudited

US$000’s

6 months to

30 June 2010

Unaudited

US$000‟s

Year to

31 December 2010

Audited

US$000‟s

Operating profit for the year/period 47,789 81,134 88,988

Depreciation, depletion and amortisation 54,835 64,736 93,979

Derivative financial instruments losses/(gains) 8,584 (1,082) 6,482

Impairment of oil and gas assets 171 1,143 1,614

Share based payments charge 5,711 3,125 8,333

Operating cashflows before movements in working capital 117,090 149,056 199,396

Cash used by discontinued operating activities (2,163) – (28)

(Increase)/decrease in trade and other operating receivables (76,711) (53,665) 16,046

Increase/(decrease) in trade and other operating payables 3,724 (2,770) (11,793)

(Increase)/decrease in inventory - crude oil (25,509) (1,061) 5,895

Currency translation adjustments 183 (200) (199)

Net cash generated in operating activities 16,614 91,360 209,317

Purchases of property, plant and equipment

– Other (2,470) (1,477) (3,209)

– Oil and gas assets (190,881) (110,802) (295,443)

Exploration and evaluation expenditure (27,952) (23,292) (59,739)

Increase in inventories – spare parts (5,939) (10,394) (10,386)

Purchase of investments (750) – (1,998)

Investment revenue 160 237 298

Acquisition of subsidiaries in 2010, net of cash acquired – – 2,289

Net cash used in investing activities (227,832) (145,728) (368,188)

Issue of ordinary share capital 17,360 1,332 5,191

Costs of share issues – – (2,381)

Net proceeds from borrowings 564,647 18,970 100,217

Repayment of borrowings (183,845) (83,711) (110,970)

Interest and financing fees paid (6,630) (9,906) (14,493)

Net cash provided/(used) infinancing activities 391,532 (73,315) (22,436)

Net increase/(decrease) in cash and cash equivalents 180,314 (127,683) (181,307)

Cash and cash equivalents at beginning of year/period 140,221 321,312 321,312

Effect of foreign exchange rate changes 369 390 216

Cash and cash equivalents at end of year/period 320,904 194,019 140,221


Condensed Group Statement of Changes in Equity for the six months ended 30 June 2011 (unaudited)

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 2010 15,702 755,169 17,272 (129,895) 658,248

Issue of share capital 32 1,300 – – 1,332

Deductible costs of share issues – – (1,000) – (1,000)

Share based payments for services – – 4,464 – 4,464

Other share based payments – – 52 – 52

Reserves transfer relating to loan notes – – (1,216) 1,216 –

Reserves transfer on exercise of options,

awards and LTIP – – (1,898) 1,898 –

Net profit for the period – – – 50,724 50,724

Balance at 30 June 2010 15,734 756,469 17,674 (76,057) 713,820

Issue of share capital 1,273 142,724 – – 143,997

Shares to be issued – – 500 – 500

Deductible costs of share issues – (2,381) 1,000 – (1,381)





awards and LTIP – – (308) 308 –

Exercise of warrants designated as

financial liabilities – – – 2,088 2,088

Net loss for the period – – – (5,465) (5,465)

Balance at 1 January 2011 17,007 896,812 22,764 (77,868) 858,715

Issue of share capital 241 17,139 – – 17,380





awards and LTIP – – (6,459) 6,459 –

Exercise of warrants designated as

financial liabilities – – – 11,654 11,654

Net profit for the period – – – 20,664 20,664

Balance at 30 June 2011 17,248 913,951 20,102 (36,897) 914,404

Notes to the Interim Financial Statements (unaudited)


1. Basis of accounting and presentation of financial information

The annual financial statements of Afren plc are prepared in accordance with IFRS as adopted by the European Union. The

condensed set of financial statements included in this half-yearly financial report has been prepared in accordance with International

Accounting Standard („„IAS‟‟) 34, „Interim Financial Reporting‟, as adopted by European Union. The information for the year ended

31 December 2010 does not constitute statutory accounts as defined in section 434 of the Companies Act 2006. Statutory accounts

for the year ended 31 December 2010 were published and copies of which have been delivered to the Companies House. The

auditors reported on those accounts: their report was unqualified, did draw attention to any matters by way of emphasis and did not

contain any statement under sections 498(2) or (3) of the Companies Act 2006.

Changes in accounting policy

With the exception of the additional policy in relation to finance leases below, the same accounting policies, presentation and

methods of computation have been followed in the condensed set of financial statements as applied in the preparation of the

Group's latest audited financial statements.

Leasing

Leases are classified as finance leases whenever the terms of the lease transfer substantially all the risks and rewards of ownership

to the lessee. All other leases are classified as operating leases.

Assets held under finance leases are recognised as assets of the Group at their fair value or, if lower, at the present value of the

minimum lease payments, each determined at the inception of the lease. The corresponding liability to the lessor is included in the

balance sheet as a finance lease obligation.

Lease payments are apportioned between finance expenses and reduction of the lease obligation so as to achieve a constant rate

of interest on the remaining balance of the liability. Finance expenses are recognised immediately in profit or loss, unless they are

directly attributable to qualifying assets, in which case they are capitalised in accordance with the Group‟s general policy on

borrowing costs. Contingent rentals are recognised as expenses in the period in which they are incurred.

Rentals payable under operating leases are charged to income on a straight-line basis over the term of the relevant lease except

where another more systematic basis is more representative of the time pattern in which economic benefits from the lease asset are

consumed. Contingent rentals arising under operating leases are recognised as an expense in the period in which they are

incurred. In the event that lease incentives are received to enter into operating leases, such incentives are recognised as a liability.

The aggregate benefit of incentives is recognised as a reduction of rental expense on a straight-line basis, except where another

systematic basis is more representative of the time pattern in which economic benefits from the leased asset are consumed.

Going concern

The Directors are satisfied that the Group has sufficient resources to continue in operation for the foreseeable future, a period of not

less than 12 months from the date of this report. Accordingly, they continue to adopt the going concern basis in preparing the

condensed Group interim financial statements.



2. Profit per ordinary share

Period ended 30 June

2011 2010

From continuing and discontinued operations

Basic 2.1c 5.7c

Diluted 2.0c 5.2c

From continuing operations

Basic 2.3c 5.7c

Diluted 2.2c 5.2c

The profit and weighted average number of ordinary shares used in the calculation of the profit per share are as follows:

Profit for the period used in the calculation of the basic profit per share from continuing and

discontinued operations (US$000's) 20,664 50,724

Effect of dilutive potential ordinary shares – –

Profit for the period used in the calculation of the diluted profit per share from continuing and

discontinued operations (US$000's) 20,664 50,724

Loss for the period from discontinued operations (2,137) –

Profit used in the calculation of the basic and diluted profit per share from continuing

activities (US$000's) 22,801 50,724

The weighted average number of ordinary shares for the purposes of diluted profit per share reconciles to the weighted average number of

ordinary shares used in the calculation of basic profit per share as follows:

Weighted average number of ordinary shares used in the calculation of basic

profit per share 977,413,016 890,227,484

Effect of dilutive potential ordinary shares:

Share scheme awards 51,534,223 73,218,456

Warrants 1,627,761 14,548,316

Weighted average number of ordinary shares used in the calculation of diluted

profit per share 1,030,575,000 977,994,256

In 2010, 12 million potential ordinary shares were anti-dilutive and therefore excluded from the weighted average number of ordinary

shares for the purposes of diluted earnings per share. There were no excluded potential ordinary shares as at 30 June 2011.



3. Reconciliation of profit after tax to normalised profit after tax

2011

US$000's

2010

US$000's

Profit after tax 22,801 50,724

Unrealised losses/(gains) on derivative financial instruments* 8,584 (1,082)

Cost of acquisition of Black Marlin – 1,929

Finance costs on settlement of borrowings 7,431 –

Share based payment charge 5,711 3,125

Foreign exchange gains (372) (524)

Fair value financial liabilities 232 (280)

Share of (gain)/loss of associate (18,274) 604

Normalised profit after tax 26,113 54,496

*Excludes realised losses on derivative financial instruments of US$3.4 million (1H 2010: US$0.9 million).

Normalised profit after tax is a non-IFRS measure of financial performance of the Group, which in management‟s view more

accurately reflects the Group‟s underlying financial performance. This may not be comparable to similar titled measures reported by

other companies.



4. Operating Segments

For management purposes, the Group currently operates in four geographical markets: Nigeria, Côte d‟Ivoire, Other West Africa and

Eastern Africa. Unallocated operating expenses, assets and liabilities relate to the general management, financing and

administration of the Group.

Nigeria

US$000‟s

Côte d‟Ivoire

US$000‟s

Other West

Africa

US$000‟s

Eastern Africa

US$000‟s

Unallocated

US$000‟s

Consolidated

US$000‟s

Six months to June 2011

Sales revenue by origin 130,980 30,025 – – – 161,005

Operating profit/(loss) before derivative

financial instruments 60,933 15,366 (23) (475) (15,983) 59,818

Derivative financial instruments (losses)/gains (10,758) (1,271) – – – (12,029)

Segment result 50,175 14,095 (23) (475) (15,983) 47,789

Investment revenue 160

Finance costs (22,615)

Other gains and losses – fair value of financial assets & liabilities (232)

Other gains and losses – foreign currency gains 372

Share of loss of an associate 18,274

Profit from continuing operations before tax 43,748

Income tax expense (20,947)

Profit from continuing operations after tax 22,801

Loss from discontinued operations (2,137)

Profit for the period 20,664

Segment assets – non-current 1,217,897 146,559 75,160 201,844 4,713 1,646,173

Segment assets – current 193,082 58,696 7,515 696 246,291 506,280

Segment liabilities (614,982) (55,223) (5,013) (39,985) (522,846) (1,238,049)

Capital additions – oil and gas assets 414,885 43 – – – 414,928

Capital additions – exploration and evaluation 9,591 561 6,718 6,711 – 23,581

Capital additions – other 598 1 – 2,813 1,998 5,410

Capital disposal – other – – – (68) (52) (120)

Depletion, depreciation and amortisation (46,614) (7,316) – (1) (904) (54,835)

Exploration costs write-off – – (17) (154) – (171)



4. Operating Segments continued

Nigeria

US$000‟s

Côte

d‟Ivoire

US$000‟s

Other

West

Africa

US$000‟s

Eastern

Africa

US$000‟s

Unallocated

US$000‟s Consolidated

US$000‟s

Year to December 2010

Sales revenue by origin 286,546 32,568 – 131 202 319,447

Operating gain/(loss) before derivative financial

instruments 128,053 (2,583) (2,051)

(248)

(25,289) 97,882

Derivative financial instruments gains (3,270) (5,624) – – – (8,894)

Segment result 124,783 (8,207) (2,051) (248) (25,289) 88,988



Other gains and losses – fair value of financial liabilities (8,100)

Other gains and losses – foreign currency losses 305

Share of loss of an associate 8,625

Profit from continuing operations before tax 78,796


Profit from continuing operations after tax 45,873

Loss from discontinued operations (614)

Profit for the period 45,259

Segment assets – non-current 805,105 153,270 68,459 192,548 3,675 1,223,057

Segment assets – current 172,251 15,818 6,107 2,046 24,397 220,619

Assets held for sale – – – 2,812 2,812

Segment liabilities (352,857) (110,545) (5,090) (47,967) (71,314) (587,773)

Capital additions – oil and gas assets 362,879 119 – – – 362,998

Capital additions – exploration and evaluation 59,462 1,723 7,559 192,470 – 261,214

Capital additions – other 488 453 – 270 2,188 3,399

Capital disposal – other (815) – – – – (815)

Depletion, depreciation and amortisation (76,708) (15,668) – (3) (1,600) (93,979)

Exploration costs write back/(write-off) 370 – (1,984) – – (1,614)



4. Operating Segments continued

Nigeria

US$000‟s

Côte d‟Ivoire

US$000‟s

Other West

Africa

US$000‟s

Unallocated

US$000‟s

Consolidated

US$000‟s

Six months to June 2010

Sales revenue by origin 197,100 17,650 – – 214,750

Operating loss before derivative

financial instruments 93,394 (107) (1,214) (11,092) 80,981

Derivative financial instruments losses (1,538) 1,691 – – 153

Segment result 91,856 1,584 (1,214) (11,092) 81,134



Other gains and losses – fair value of financial assets & liabilities 280

Other gains and losses – foreign currency gains 524

Share of loss of an associate (604)

Profit before tax 75,386


Profit after tax 50,724

Segment assets – non-current 557,003 161,277 67,614 3,203 789,097

Segment assets – current 201,155 26,826 8,546 111,179 347,706

Segment liabilities (244,598) (119,623) (5,293) (53,469) (422,983)

Capital additions – oil and gas assets 144,602 191 – – 144,793

Capital additions – exploration

and evaluation 19,734 785 4,729 – 25,248

Capital additions – other – 22 – 305 327

Capital disposal – other (559) – – – (559)

Depletion, depreciation and

amortisation (55,672) (8,325) – (740) (64,737)

Impairment reversal/(change) on oil

and gas assets 25 – (1,168) – (1,143)



5. Senior secured loan notes

On 27 January 2011, Afren offered US$450 million aggregate principal amount of its 11.5% senior secured notes due 2016

(the Notes) and on 11 February 2011, Afren announced an offering of an additional US$50 million of its 11.5% senior secured notes

due 2016. Part of the proceeds of the offering were used to settle borrowings amounting to US$175.6 million (net of issue costs)

and accrued interest of US$1.3 million. Also payable was an early redemption fee on the previously existing Sojitz notes, amounting

to US$2.5 million.

Interest amounting to US$23.4 million (before capitalisation of some of the interest to oil and gas assets under development) has

been charged to the Income statement for the period to 30 June 2011. Total expenses of the offering incurred amounted to

US$22.1 million which are being amortised over the life the Notes.

6. Obligations under finance lease

The Group has a seven year lease of a Mobile Offshore Production Unit (MOPU) and a Floating Storage Offloading Vessel (FSO)

from Mercator Offshore (Nigeria) Limited. The capex day rate payable is accounted for as a finance lease and consequently, the

present value of the lease as at 30 June 2011 of US$141.2 million and US$21.2 million has been reported in the balance sheet in

non-current and current liabilities respectively. Interest on the finance lease included in the income statement during the period was

US$1.6 million.

7. Contingent liabilities

There has been no change to the contingencies reported in the annual report for the year ended 31 December 2010.

8. Subsequent events

On 27 July 2011, Afren announced the proposed acquisition of a 60 per cent. participating interest in the Barda Rash PSC and 20

per cent. participating interest in the Ain Sifni PSC, located in the Kurdistan region of Iraq. Total acquisition costs are approximately

US$588.25 million and include approximately US$81.0 million back costs and US$14.0 million 2011 capex related to Ain Sifni. The

acquisition will be financed by a mix of equity, debt and cash.

On 28 July 2011, Afren announced that it had raised £113.0 million (approximately US$184.5 mill ion) before commissions and

expenses by placing 83,679,544 new ordinary shares of the Company. The placing proceeds will be used to fund the acquisition

described in the above paragraph.

9. Related party transactions

Transactions between the Company and its subsidiaries, which are related parties, have been eliminated on consolidation and are

not disclosed in this note.

During the period, Group companies entered into the following transactions with related parties who are not members of the Group:

Trading transactions

(Sales)/Purchase of

goods/services

Amounts owed

from/(to) related parties

Six months

ended

30 June

2011

US$000’s

Six months

ended

30 June 2010

US$000‟s

As at 30

June 2011

US$000’s

As at 30

June 2010

US$000‟s

Energy Investment Holdings Ltd 242 244 110 (97)

St. John Advisors Ltd 121 150 – –

STJ Advisors LLP 1,150 – – –

Tzell Travel Group 432 143 (13) (16)

First Hydrocarbon Nigeria Limited – – 2,241 –

Energy Investment Holdings Ltd is the contractor company for the consulting services of Bert Cooper. Bert Cooper was a director of

a subsidiary of the company until 23 July 2010. The majority of the payments in 2011 related to his monthly fee.

St. John Advisors is the contractor company for the consulting services of John St. John, a Non-executive Director. St. John

Advisors also receive a monthly retainer of £15,000 for consulting advice. This contract is for 12 months from 27 June 2008 and

automatically continues thereafter unless terminated by either party. A separate contract was engaged in 2010 with STJ Advisors

LLP for consulting services in relation to the Senior Note which completed on 27 January 2011.



Tzell Travel Group operates as a franchise. The franchisee utilised by Afren for some of its travel needs is a close family member of

the Chief Executive Officer and Tzell Travel Group is therefore considered a related party. Afren uses several travel agents as there

is a significant travel element to its operations and Tzell competes on an even basis with these. Tzell provided approximately 10%

(2010: 8%) of the travel arrangements by value.

First Hydrocarbon Nigeria Limited (FHN) is an associate company of Afren plc.

The amounts outstanding are unsecured and are expected to be settled in cash. No guarantees have been given or received. No

provisions have been made for doubtful debts on the amounts owed by related parties.

10. Dividend

The directors do not recommend the payment of a dividend.

11. Approval of accounts

These interim accounts (unaudited) were approved by the Board of Directors on 26 August 2011.

Advisors and Company Secretary


Company Secretaries and

Registered Office

Ms. Shirin Johri

Mr. Elekwachi Ukwu

Afren plc

Kinnaird House

1 Pall Mall East

London SW1Y 5AU

Company number: 05304498

Sponsor and Broker

Merrill Lynch International

Bank of America Merrill Lynch Financial Centre

2 King Edward Street

London EC1A 1HQ

United Kingdom

www.ml.com

Joint Broker

Morgan Stanley

20 Bank Street

London E14 4AD

www.morganstanley.com

Auditors

Deloitte LLP

Chartered Accountants and Registered Auditors

2 New Street Square

London EC4A 3BZ

www.deloitte.com

Financial PR Adviser

Pelham Public Relations

12 Arthur Street

London EC4R 9AB

www.pelhampr.com

Registrars

Computershare Investor Services PLC

The Pavilions

Bridgwater Road

Bristol BS13 8AE

www.computershare.co.uk

Legal Advisers

White & Case LLP

5 Old Broad Street

London

EC2N 1DW

Dr Ken Mildwaters

Walton House

25 Bilton Road

Rugby CV22 7AG

Principal Bankers

Lloyds TSB Bank Plc

39 Threadneedle Street

London EC2R 8AU

www.lloydstsb.com

Advisors and Company Secretary


Afren plc

Kinnaird House

1 Pall Mall East

London SW1Y 5AU

England

T: +44 (0)20 7451 9700

F: +44 (0)20 7451 9701

www.afren.com

Email: [email protected]

Afren Nigeria

1st Floor, The Octagon

13A, A.J. Marinho Drive

Victoria Island Annexe

Lagos

Nigeria

T: +234 (1) 4610130 – 3

F: +234 (1) 460139

Afren Côte d’Ivoire, Limited

Avenue Delafosse Prolongée

RDC Résidence Pelieu

04 B P 827 Abidjan 04

Côte d‟Ivoire

T: +225 20 254 000

F: +225 20 226 229

Afren Resources USA, Inc

10001 Woodloch Forest Drive

Suite 360

The Woodlands

Texas 77380

USA

T: +1 281 363 8600

F: +1 281 292 0019

Afren East Africa Exploration Limited

Room No. 2 Mezzanine Floor

Hughes Building

Muindi Mbingu Street

Nairobi

Kenya

T: +254 729 943 249

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