Heritage Oil Plc
TSX : HOC
LSE : HOIL

Heritage Oil Plc

April 18, 2012 02:00 ET

Heritage Oil Announces Results for the Year Ended 31 December 2011

LONDON, UNITED KINGDOM--(Marketwire - April 18, 2012) -

THIS PRESS RELEASE IS NOT FOR DISTRIBUTION TO UNITED STATES NEWSWIRE SERVICES OR FOR DISSEMINATION IN THE UNITED STATES.

Heritage Oil Plc (TSX:HOC)(LSE:HOIL) ("Heritage" or the "Company"), an independent upstream exploration and production company, announces its results for the twelve months ended 31 December 2011. All figures are in US dollars unless otherwise stated.

2011 Operational Highlights

  • Awarded new licences in Tanzania which Heritage believes could be geologically analogous to the Lake Albert Basin, providing the Company with a key advantage in assessing the blocks
  • Entered Libya through an acquisition which makes Heritage well placed to be able to play a significant role in the future development of the oil and gas industry in Libya
  • Appraisal drilling, in Kurdistan, commenced on the Miran West-3 well and results to date have confirmed oil in the Upper Cretaceous and gas in the Lower Cretaceous and Jurassic reservoirs
  • An interval, above the main Jurassic reservoir, in the Miran West-3 well has recently been tested and resulted in a flow of up to 17.5 MMscfd of dry gas
  • Acquired seismic on the southern portion of the Miran Block which has identified the presence of a structure capable of containing additional resources
  • Completed seismic in Mali, Malta and Tanzania
  • Drilled first horizontal well in Russia which exceeded pre-drill expectations resulting in a year-on-year increase in production of 24%

2011 Financial Highlights

  • Cash of $311 million, excluding amounts relating to the Ugandan tax dispute
  • Production averaged 673 bopd, an increase of 24% from 2010 levels
  • Average realised price of $36.9/bbl, an increase of 45% from 2010 levels
  • Total cash capital expenditures increased to $135 million

Outlook

  • Miran East-1 well commenced drilling in March 2012 with results expected at the end of the third quarter 2012
  • Further test results expected from the Miran West-3 well
  • Undertaking work to identify a suitable drilling location in the southern portion of the Miran Block
  • Work programmes are commencing in Tanzania on newly awarded acreage
  • Planning for a high-impact exploration well offshore Malta
  • Actively looking for further opportunities

Tony Buckingham, Chief Executive Officer, commented:

"2011 has been a year in which we have enhanced the asset portfolio through the addition of acreage, investing in opportunities and through existing work programmes. We currently have two rigs drilling in Kurdistan and are reviewing results from seismic campaigns that could provide future growth in the portfolio. We are looking to further develop the existing portfolio and continue to look for value generating opportunities within our core areas."

Notes to Editors

  • Heritage is listed on the Main Market of the London Stock Exchange and is a constituent of the FTSE 250 Index. The trading symbol is HOIL. Heritage has a further listing on the Toronto Stock Exchange (TSX:HOC).
  • Heritage is an independent upstream exploration and production company engaged in the exploration for, and the development, production and acquisition of, oil and gas in its core areas of Africa, the Middle East and Russia.
  • Heritage has an exploration, appraisal and development asset in the Kurdistan Region of Iraq, exploration assets in Malta, Tanzania, Mali, Pakistan, Libya and the Democratic Republic of Congo and a producing property in Russia.
  • Heritage Energy Middle East, a wholly-owned subsidiary of Heritage, is operator and holds a 75% interest in the Miran Block. There are third party back-in rights which could reduce the holding to 56.25%

If you would prefer to receive press releases via email please contact Jeanny So (jeanny@chfir.com) and specify "Heritage press releases" in the subject line.

CHIEF EXECUTIVE'S REVIEW

We have made progress across the portfolio in 2011 through the addition of acreage, investing in opportunities and pushing forward with work programmes across our existing assets.

In particular we have added exciting new exploration acreage in Tanzania, invested in Libya, a hydrocarbon prolific area providing potential access to Africa's largest oil industry, conducted seismic across most of the existing licences, increased production in Russia through employing horizontal drilling techniques, and moved ahead with exploration, appraisal and development work in the Miran Field in Kurdistan.

Global stock markets experienced extreme volatility during 2011 due to the Eurozone crisis, and this came to a head in August.

The oil price, since the beginning of 2011, strengthened as supply side issues outweighed concerns over the financial crisis in global stock markets. A popular uprising in Tunisia sparked similar protests across the Middle East and North Africa, the Arab Spring, which still continues in certain countries. The Libyan crisis threatened the supply of approximately 1.5 million barrels of oil per day and, in addition, non-OPEC countries had outages that reduced production by an average of 0.7 million barrels per day, according to the International Energy Association.

Prices gave up the year's gains by August amid concern the US economic recovery was stalling and speculation that Libya would resume oil production faster than expected after Gadaffi's ousting that month. The price of Brent crude slipped in October to its lowest level for the year, as the debt crisis in Europe sapped confidence in the health of the global economy. Recent threats of supply disruption in the first quarter of 2012 have led to strengthening in the oil price again.

EXPLORATION OPERATIONS

Kurdistan

At the beginning of 2011 we announced the discovery of a major gas field with oil and condensate after completing drilling of the Miran West-2 well.

The Miran West-3 well commenced drilling in August 2011 with the primary objective of appraising the productivity of the Jurassic reservoir intervals from which we had achieved significant flow rates in the previous well. To date, results from the well have confirmed oil in the Upper Cretaceous and gas in the Lower Cretaceous and Jurassic reservoirs.

We successfully completed testing of the Upper Cretaceous reservoir after drilling to a depth of 876 metres in November 2011. During testing the maximum measured rate achieved from this reservoir section was 1,950 bopd and attempts to flow the well at higher rates were severely restricted by the capacity of the surface test equipment.

Gas was confirmed in the Lower Cretaceous and in April 2012, it was announced that the testing of a reservoir interval above the main Jurassic reservoir resulted in a flow of up to 17.5 MMcsfd of dry gas. This reservoir is proven to be separate from those identified to date within the Miran structure. The well is drilling ahead to the primary Jurassic reservoir targets.

In March 2012, the Miran East-1 exploration well commenced drilling. This is the first well to be drilled on the highly prospective eastern structure, which has an area of approximately 130 square kilometres. The well is targeting exploration potential within the Cretaceous and Jurassic reservoir intervals of the eastern structure, contiguous with the large hydrocarbon bearing Miran West structure. The well design utilises recently acquired 3D seismic data and an enhanced understanding of the structural configuration within the Miran Field that this has provided. Multiple intervals will be evaluated and tested as the well is drilled and have the potential to add significant hydrocarbon resources at all of the multiple reservoir intervals.

Seismic acquisition

Acquisition of 3D seismic, covering 730 square kilometres, over the Miran Block was completed in 2011. This is believed to be the largest 3D seismic programme ever acquired in the region. The increased coverage and quality of the 3D data is assisting greatly with our selection of well locations.

In addition, the acquisition of 180 kilometres of 2D seismic on the southern portion of the Miran Block to help identify further potential prospectivity was completed in October 2011. The interpretation of data has indicated the presence of a structure and we are in the process of identifying potential drilling locations.

Gas monetisation and development

We consider the Miran Gas Field to be of such a size that it is a commercial discovery. Accordingly, we are currently reviewing options, and are in discussions with third parties, for a phased development of the Miran Field which includes early gas production to existing and planned cement and power plants for local markets in Kurdistan as well as exports to Turkey and possibly to the European market under full field development. The initial priority will be to satisfy local gas demand by supplying gas on commercial terms to local end-users in the Sulymaniyah region in 2013. Early gas production would also result in associated condensate production for blending with oil production.

The early production will be paralleled with full development from 2015 and the export of gas to Turkey/Europe with the full production of blended oil and condensate. Independent gas marketing studies have highlighted increasing gas demand in the Kurdistan region, Turkey and Europe that can provide valuable markets for the gas volumes. Work on conceptual development studies and gas marketing plans and strategies has continued and we are in discussions with the Kurdistan Regional Government (the "KRG"), gas buyers and contractors regarding both early and full field development.

Tanzania

We are excited to have been appointed operator and awarded new Production Sharing Agreements ("PSAs") in Tanzania with Rukwa in November 2011 and Kyela in January 2012. With both of these areas we recognise certain geological similarities with the Albert Basin of Uganda, where we have had previous experience and commercial success, thereby providing us with a material advantage in assessing these blocks. Our work programme on Rukwa has commenced with the reprocessing of legacy 2D seismic data and we are planning on acquiring further 2D seismic in the summer of 2012. On the Kyela Block we will shortly commence the acquisition of a gravity survey following which a seismic programme will be planned.

Economic scoping has shown that, in the event of oil exploration success from either licence, there is commercial viability of either rail export or export by pipeline.

Other exploration assets

In Malta, we have an extensive data set of approximately 5,000 kilometres of 2D seismic that indicates the presence of multiple prospects and leads. This includes the acquisition over Area 7, in July 2011, of 1,400 kilometres of infill and exploration 2D seismic. Preparations are now underway to drill a high-impact well in Area 7.

In 2011 seismic was acquired in Mali, over Blocks 7 and 11, which is now being interpreted and integrated with legacy data and the acquisition of a 3D seismic programme offshore Tanzania completed.

PRODUCTION OPERATIONS

Russia

Production averaged 673 bopd over 2011, an increase of 24% on the previous year. In August 2011 we completed the drilling of well 363, the first horizontal well to have been drilled in the licence, with a year end exit rate of c.937 bopd. Results of this well exceeded pre-drill expectations and we achieved a significant increase in production from the field.

Historical development of this reservoir type throughout the region has been through conventional drilling on a grid pattern. We recognised an opportunity to improve the efficiency and economics of field development by utilising horizontal drilling technology, thus decreasing the number of wells and the total cost required to develop the field, while potentially improving recovery. Currently, we plan to commence drilling a second horizontal well in the field in the fourth quarter when the ground has frozen allowing access throughout the licence.

LIBYA

We announced an exciting acquisition in October 2011 when we acquired a controlling interest in Sahara Oil Services Holdings Limited ("Sahara Oil") which owns the entire share capital of Sahara Oil Services Limited ("Sahara"), an oil field services company in Libya. We consider that Heritage, through Sahara, is uniquely positioned to pursue field rehabilitation activities and be awarded exploration and production licences as we have operator status. This means Heritage is well placed to play a significant role in the future oil and gas industry in Libya. We view this acquisition as consistent with our strategy of first mover advantage and entering regions with vast hydrocarbon wealth where we have a strategic advantage. Ongoing discussions with the NTC and other stakeholders continue to highlight opportunities with the potential to transform Heritage.

CORPORATE

Cash

As at 31 December 2011, Heritage had a cash position of approximately $311 million, excluding amounts related to the tax dispute of approximately $405 million, which is more than sufficient to cover the current work programmes into 2013.

PetroFrontier Corp.

Heritage has continued to acquire common shares ("Shares") of PetroFrontier Corp. ("PetroFrontier") for investment purposes and currently holds 15.25% of the outstanding Shares of PetroFrontier. PetroFrontier is listed on the TSX Venture Exchange and has commenced a high-impact drilling programme in Australia targeting billions of barrels of resources.

Buy back programme

Heritage commenced a share buy back programme in April 2011. To date 33,856,107 Ordinary Shares have been bought back and are held in treasury. Consequently, Heritage has 255,891,923 Ordinary Shares in issue (excluding treasury shares) as well as 2,811,408 exchangeable shares of no par value of Heritage Oil Corporation ("HOC", the "Corporation"), each carrying one voting right in Heritage.

The total number of voting rights in Heritage, excluding treasury shares as at 17 April 2012, is 258,703,331.

UGANDA

In 1997, Heritage became the first oil and gas company in almost 60 years to undertake exploration in Uganda after being awarded a licence in the Albert Basin in western Uganda. Heritage had remarkable operational success in Uganda as a result of technical excellence and first mover advantage.

On 18 December 2009, Heritage announced that it, and its wholly owned subsidiary Heritage Oil & Gas Limited ("HOGL"), had entered into a Sale and Purchase Agreement ("SPA"), with ENI International B.V. ("Eni") for the sale of Blocks 1 and 3A in Uganda (the "Ugandan Assets"). On 17 January 2010, Tullow Uganda Limited ("Tullow") exercised its rights of pre-emption. The transaction was overwhelmingly approved by Heritage shareholders at the General Meeting on 25 January 2010.

On 27 July 2010, Heritage announced that HOGL had completed the disposal of the Ugandan Assets. Tullow paid cash of $1.45 billion, including $100 million from a contractual settlement, of which Heritage received and retained $1.045 billion.

The Uganda Revenue Authority ("URA") contends that income tax is due on the capital gain arising on the disposal and raised assessments of $404,925,000, whilst Heritage's position, based on comprehensive advice from leading legal and tax experts is that no tax is payable.

On closing, Heritage deposited $121,477,500 with the URA, representing 30% of the disputed tax assessment of $404,925,000. A further $283,447,000 was retained in escrow with Standard Chartered Bank in London.

In August 2010, the URA issued a further income tax assessment of $30 million representing 30% of the additional contractual settlement amount of $100 million. HOGL has challenged the Ugandan tax assessments, totalling $435 million, but in the fourth quarter of 2011, the Tax Appeals Tribunal in Uganda dismissed HOGL's applications. HOGL has subsequently commenced appeals to the Ugandan High Court in relation to the rulings by the Tax Appeals Tribunal which it believes is fatally flawed.

In May 2011, HOGL commenced international arbitration proceedings in London against the Ugandan Government. HOGL is seeking a decision requiring, among other things, the return or release of approximately $405 million, plus interest, in aggregate currently on deposit with the URA or in escrow with Standard Chartered Bank in London. The arbitration proceedings are being held in London in accordance with the provisions of the PSAs in relation to the Ugandan Assets.

On 15 April 2011, Heritage, and its wholly owned subsidiary HOGL, received Particulars of Claim filed in the High Court of Justice in England by Tullow seeking $313,447,500 for alleged breach of contract as a result of HOGL's and Heritage's refusal to reimburse Tullow in relation to a payment made by Tullow of $313,447,500 on 7 April 2011 to the URA. Heritage and HOGL believe that the claim has no basis and are in the process of vigorously and robustly defending it.

CORPORATE SOCIAL RESPONSIBILITY

We continue to develop our approach to CSR and engagement with stakeholders towards achieving a shared future is a key element supporting our core business model. We have developed, and continue to review, a policy framework disclosing our essential core values. I am delighted to report that we continue to maintain a strong track record for health and safety which is fundamental in being viewed as a preferred partner.

During 2011 we spent a total of approximately $700,000 on CSR related activities with community programmes focused on areas where we were operationally more active. For example, in Kurdistan we have continued with our focus on the development of local infrastructure and supporting education and in Mali we supported local healthcare.

OUTLOOK

2011 was a year in which we enhanced the portfolio in our core areas of Africa, Middle East and Russia and secured an investment foothold in Australia though our holding in PetroFrontier. We are currently drilling a high-impact exploration well in Kurdistan and are reviewing results from seismic programmes that could provide direction for future growth in the portfolio. In addition to increasing our exposure to Tanzania, in blocks where we believe we have a technical and operational advantage, we acquired a controlling interest in Sahara Oil that has, we believe, made us extremely well positioned in Libya where we expect to play an important role in the oil industry.

As always, I am very grateful to our management team, employees and supportive Board for their dedication and contribution to the progress made by Heritage this past year.

Finally, to our shareholders, thank you for your continued support and interest in Heritage. We are focused and dedicated to generating shareholder value in 2012 through development of our existing portfolio and other acquisitions.

Anthony Buckingham, Chief Executive Officer

ASSET REVIEW

KURDISTAN

Heritage was one of the first companies to be awarded a Production Sharing Contract ("PSC") in Kurdistan. Kurdistan is an autonomous region in the north of federal Iraq bordering Syria, Iran and Turkey.

In October 2007, the Group signed a PSC with the KRG and was appointed operator of the Miran Block, which covers approximately 1,015 square kilometres, in the southern part of Kurdistan. The Miran structure lies approximately 65 kilometres from the giant Kirkuk oilfield and 60 kilometres from the Taq Taq Field, which is on production. In April 2009 Genel Energy plc ("Genel Energy") was nominated as the third party participant in the Block.

As an early entrant in Kurdistan, the Group is strongly positioned to benefit from development of this significant hydrocarbon-prone region especially as the already stable security situation and political environment continue to improve. Since 2006 approximately 30 wells have been drilled resulting in c.20 discoveries. Over 40 companies are now present in the region with entrants in 2011 including ExxonMobil.

It is generally acknowledged that there is huge potential in Kurdistan for as yet undiscovered hydrocarbons. It has been estimated by the KRG, in November 2011, that there is approximately 45 billion barrels of oil and 100-200 TCF of gas in the region.

Federal elections were held in March 2010 and a coalition government, which included officials from Kurdistan, was formed in December 2010. Subsequently, in February 2011, production from two fields in Kurdistan was exported to Turkey by pipeline and in June companies began to receive payment. The Ministry of Natural Resources in Kurdistan expects construction on several pipelines to commence in 2012 to help achieve near-term targets for oil and gas export.

The work programme to date

The Miran Block contains two large contiguous structures, Miran West and Miran East, which were originally mapped using 332 kilometres of excellent quality 2D seismic data acquired by Heritage in 2008. More recently, Heritage acquired 730 square kilometres of 3D seismic data, the interpretation of which is ongoing, but which has already enabled the principal structural features to be identified with much greater clarity.

The Miran West structure is believed to be one of the largest structures in Kurdistan, with an estimated areal extent of up to 200 square kilometres and Miran East has an estimated areal extent of 130 square kilometres. Well results have established that the Miran Field contains two hydrocarbon systems with oil in the shallower Upper Cretaceous section and gas/condensate within the deeper Lower Cretaceous and Jurassic formations.

Miran West structure

Drilling of the Miran West-1 well commenced in December 2008 and reached a total depth of 2,935 metres in March 2009. Drilling operations were designed to cope with potential high reservoir pressures which, in fact, were not encountered and resulted in the loss of drilling fluid and lost circulation material in the highly permeable reservoir fracture systems. The large volumes of fluids lost constrained initial testing operations severely. Testing was completed in August 2009 with a flow rate of 3,640 bopd recorded from a single upper reservoir interval.

The Miran West-2 appraisal well, located approximately four kilometres north-west of the Miran West-1 discovery well, commenced drilling in November 2009 with the aim of appraising hydrocarbons in the Cretaceous formations discovered by that well. Data acquired after drilling operations commenced indicated that the Miran West-2 well was also optimally positioned to test deeper exploration objectives with potential for further substantial quantities of hydrocarbons.

The well was subsequently modified to assess the exploration potential of these deeper formations and was eventually drilled to a total depth of 4,426 metres. The Miran West-2 well results have confirmed three additional pay zones within the Lower Cretaceous and Jurassic formations in addition to the pay zone identified in the Upper Cretaceous in the Miran West-1 well.

Drilling of the Miran West-3 appraisal well commenced at the beginning of August 2011 with the aim of targeting reservoir sections encountered in discovery wells with the primary objective of appraising the productivity of the Jurassic reservoir formation in the Miran West structure.

Testing of the Upper Cretaceous reservoir, resulted in a maximum measured rate of 1,950 bopd. Attempts to flow the well at higher rates were severely restricted by the capacity of the surface test equipment. The oil produced on test is c.15º API with very little associated gas, similar to that tested from the same interval in the Miran West-1 discovery well.

In March 2012, it was announced that the results from detailed wireline log interpretation, observations whilst drilling and gas recovered at surface, confirmed that the Lower Cretaceous reservoir formation is gas bearing. Detailed work is now being undertaken on the recently processed 3D seismic and offset well data to establish the areas of effective reservoir for this formation.

Below the Lower Cretaceous reservoir, the well encountered a high pressure interval as well as a loss of circulation which resulted in the need to sidetrack the well.

In April 2012, it was announced that a reservoir interval above the main Jurassic reservoir had been tested and resulted in a flow of up to 17.5 MMscfd of dry gas. This reservoir interval is separate from the underlying main Jurassic gas bearing interval tested in the Miran West-2 well.

Further drilling will appraise the Jurassic reservoir intervals discovered by the Miran West-2 well. A number of tests are planned and drilling is expected to be completed during the second quarter of 2012. The well is drilling ahead to the primary Jurassic reservoir targets.

Miran East structure

Exploration drilling of the Miran East structure commenced in March 2012 with a second rig and is expected to take approximately seven months with key reservoir intervals being tested as the well is drilled.

This is the first well to be drilled on the highly prospective eastern structure, which has an area of approximately 130 square kilometres. The well is targeting exploration potential within the Cretaceous and Jurassic reservoir intervals of the eastern structure, contiguous with the hydrocarbon bearing Miran West structure. The well design utilises recently acquired 3D seismic data and the enhanced understanding of the structural configuration within the Miran Field that this has provided.

Further potential structures

Acquisition of 180 kilometres of 2D seismic on the southern portion of the Miran Block to help identify further potential prospectivity was completed in October 2011 and interpretation of the data has identified a structure capable of containing additional resources. Further work is being undertaken to identify a suitable drilling location.

3D seismic programme

Acquisition of 3D seismic data, covering 730 square kilometres, across the Miran Block has completed. The significant improvement in seismic data quality over the Miran Field is encouraging and assists greatly with the selection of well locations. An early phase of processing produced an initial dataset covering the core area of the field which was used to assist in the selection and orientation of the drilling of the deviated Miran West-3 and the Miran East-1 wells. The increased coverage and quality of the 3D data enables enhanced mapping of the structure and increased ability to identify fault systems.

Initial interpretation of the data is expected to be completed by the end of April which will assist greatly in the estimation of reservoir volumes and the identification of future drilling locations.

Development of the Miran Field

The Miran Field is a commercial discovery and independent engineering studies have confirmed the potential for a fast-tracked, phased development of the field.

Options being considered include early gas production to existing and planned cement and power plants for local markets in Kurdistan, as well as exports to Turkey and to the European market under full field development. The KRG has outlined favoured development options for gas utilisation. The initial priority will be to satisfy local gas demand by supplying gas on commercial terms to local cement plants and power stations and other end-users in the Sulymaniyah region in 2013. Development will be integrated as gas production would also result in associated condensate production for blending with the oil production.

The early production will be paralleled with full field development and the export of gas to Turkey/Europe with the full production of blended oil and condensate. Independent gas marketing studies have highlighted increasing gas demand in the KRG region, Turkey and Europe that can provide valuable markets for the gas volumes.

Conceptual engineering design studies have focused on the potential for early production of between 80 and 180 MMscfd for local markets commencing in 2013. This will be accompanied by appraisal and full development of approximately 560 to 750 MMscfd in 2015 for gas export. Export requires the construction of a 320 kilometre gas pipeline to the Iraq/Turkey border in part running parallel to the planned Kurdistan Iraq Crude Export ("KICE") pipeline, for which construction is planned to commence in 2012. Oil and condensate production of between 5,000 and 12,000 bpd would be trucked to Taq Taq for entry to the KICE pipeline. This would be followed by construction of a 70 kilometre oil/condensate pipeline to tie into the KICE line for full development production export of between 37,000 and 50,000 bopd.

TANZANIA

Heritage has been awarded four licences in Tanzania, two of which are considered to be geologically analogous to the Lake Albert Basin in Uganda.

Rukwa

In November 2011, Heritage announced the award of a PSA which covers virtually the entire Rukwa Rift Basin, split into two separate areas, Rukwa North and Rukwa South, and is the operator with a 100% interest. Limited exploration activity was undertaken in the blocks in the mid-1980s which resulted in the acquisition of c.2,300 kilometres of 2D seismic data and the drilling of two wells. Reprocessing of legacy 2D seismic data in Rukwa has commenced and the acquisition of c.600 kilometres of 2D seismic data is planned to commence in the summer of 2012.

Kyela

In January 2012, Heritage was awarded the Kyela PSA covering the entire northern onshore area of the Lake Nyasa (Livingston) Basin that lies within Tanzanian territory. The block has never previously been targeted for hydrocarbon exploration. Gravity data over the area suggests the presence of a sedimentary section of sufficient thickness to allow for the generation of oil. The work programme will commence with the acquisition of a c.1,500 square kilometre high resolution gravity survey. A 2D reconnaissance seismic programme is planned to be acquired based on the results of the gravity survey.

Satellite radar surveys indicate areas of wave-calming in Lake Rukwa and in Lake Nyasa that may be slicks resulting from oil seeps. In the event of an oil discovery, at either Rukwa or Kyela, economic scoping shows the commercial viability of either rail export to Dar es Salaam or export by pipeline depending on exploration success.

Heritage recognises that both the Rukwa Rift Basin and Kyela share certain geological similarities with the prolific Albert Basin of Uganda where Heritage had previous experience and significant success.

Latham and Kimbiji

The PSC was awarded to Petrodel Resources Limited ("Petrodel") by the Tanzanian government in September 2006 and Heritage entered into a farm-in agreement with Petrodel in April 2008. Later that year, 207 kilometres of 2D seismic was acquired onshore in the Kimbiji licence area. The acquisition of over 300 square kilometres of 3D seismic offshore Tanzania commenced in December 2010 and was completed in January 2011. Interpretation of the Latham 3D has been completed and the process of completing geophysical studies of seismic data is underway in order to finalise the evaluation of mapped prospects in order to determine the forward work programme. After a technical review it was decided that all capitalised costs in respect of the Kimbiji licence area were written off in 2011.

MALTA

In December 2007, the Group entered into a PSC with the Maltese government for a 100% interest in Areas 2 and 7 in the south-eastern offshore region of Malta.

The licences cover almost 18,000 square kilometres and are situated approximately 80 kilometres and 140 kilometres, offshore Malta, for Area 2 and Area 7 respectively, in water depths of up to approximately 300 metres. The two Areas are close to, and similar to, a number of producing fields offshore Libya and Tunisia.

The licences are underexplored with only one well previously drilled in Area 2; the Medina Bank-1 well in 1980. The well was drilled to a depth of 1,225 metres but failed to reach the target horizons, estimated to be between 1,500 and 4,500 metres.

Heritage has an extensive data set of approximately 5,000 kilometres of 2D seismic, including data acquired in July 2011 using greatly improved acquisition parameters compared to our inherited legacy dataset. The interpretation of seismic data has confirmed the mapping of a highly attractive Lower Eocene carbonate reef play within a prospect in Area 7 and also allowed for the mapping, with greater certainty, of deeper carbonate reef play within the Cretaceous section of the prospect. These primary targets are recognised as major hydrocarbon producing zones in the central part of the Mediterranean. Well planning is being undertaken to drill the principal prospect in Area 7.

In addition, the Company has recognised the presence of a north-south trending shelf margin on the eastern part of the blocks where a number of attractive reef prospects have been mapped.

MALI

Heritage announced in March 2008 that the Government of Mali had approved Heritage's farm-in on two exploration licences with a gross area of 64,404 square kilometres in the Gao Graben.

Heritage is the operator with the right to earn a 75% working interest in each of Blocks 7 and 11 by financing 100% of the minimum work programme of seismic acquisition and the drilling of one exploration well.

The two licences are located in the Gao Graben in the eastern part of the country; a Mesozoic basin that management considers geologically similar to other Mesozoic interior-rift basins within North Africa, such as the Muglad Basin of Sudan and the Doba Basin of Chad. The Gao Graben has been delineated by various surveys conducted since the early 1970s, including over 2,000 kilometres of 2D seismic and a comprehensive gravity and magnetic survey. This data shows the presence of tilted fault-blocks and indicates the possible presence of up to 4,000 metres of sediments above a Paleozoic succession.

Previous drilling in the Gao Graben encountered oil and gas shows, indicating the potential for a working hydrocarbon system. The Tin Bergoui water well, which lies approximately 30 kilometres to the west of Block 11, was drilled to a depth of 350 metres and encountered oil and gas shows in a number of horizons.

A two year extension to the original term of the licences was awarded in January 2009 and a further three year extension to Block 11 was awarded in 2011.

1,077 kilometres of 2D seismic was acquired over Blocks 7 and 11 between June and August 2011 and the data has been interpreted and integrated with legacy data.

Following the coup in March 2012, Heritage is monitoring the security situation and considering all options.

PAKISTAN

Sanjawi

Heritage has a 54% interest and is operator of the Sanjawi licence (number 3068-2) in Zone II (Baluchistan) which was awarded in November 2007. This onshore exploration licence covers a gross area of 2,258 square kilometres and is considered highly prospective due to an oil discovery to the west of the licence, a number of gas fields to the south-east of the licence and the presence of oil seeps in the licence. The licence is dominated by a series of broad east-west trending surface features including the Dabbar and Warkan Shah anticlines. These are large anticlines, the Dabbar structure being some 300 square kilometres in area.

Zamzama North

In December 2008, Heritage obtained a 48% interest in the Zamzama North licence (number 2667-8) and was appointed operator. The Zamzama North licence is located in the south of Pakistan in the western part of the Sindh Province approximately 200 kilometres north-west of Hyderabad and covers an area of 1,229 square kilometres.

Any discovered hydrocarbons could be readily connected to the existing infrastructure as one of the main pipelines runs through the licence. To the south of, and adjacent to, Zamzama North is the Zamzama Gas Field, a major gas field in production.

The current seismic database used to map the Zamzama North licence comprises some 1,000 kilometres of good quality 2D seismic including 350 kilometres of new, very good quality data acquired by Heritage in the fourth quarter of 2010. On the basis of this data, Heritage has mapped a number of structural prospects and leads and a drilling programme is under consideration. Operational activity in the area has been hindered by floods which have made access to the area difficult. It is planned to drill a well when access has improved.

LIBYA

In October 2011, Heritage acquired a controlling 51% interest in Sahara which holds the necessary long-term permits and licences to provide oil field services in Libya. Through this acquisition Heritage believes it is well positioned to play a significant role in the future development of the oil and gas industry in Libya.

Heritage has pursued its strategy of 'first mover advantage' in pursuing participation in the restoration of the Libyan oil production sector which presents a dynamic and evolving environment. Libya has proven reserves of 44 billion barrels of oil and ranks first in Africa ahead of Nigeria and Angola(1).

Only one third of the country is covered by exploration and production sharing agreements providing the potential for additional hydrocarbons to be discovered. It is a highly attractive oil province due to low cost of oil recovery, high quality oil which is generally sweet with API gravity ranging between 32-44º, proximity to European markets and well developed infrastructure. Heritage Energy International Limited, a wholly owned subsidiary of Heritage, acquired a 51% equity interest and control of Sahara Oil which owns the entire share capital of Sahara, a Libyan registered company providing services to the oil industry, for cash consideration of US$19.5 million.

Sahara Oil was established in April 2009 and has been granted long-term licences to provide full oil field services in Libya, including the ability to drill onshore and offshore and hold both oil and gas licences.

Heritage established a base in Benghazi in the first half of 2011 and has been in discussions with senior members of the NTC, the legitimate and recognised government of Libya, the Executive Committee which is the executive arm of the NTC and the National Oil Company and certain subsidiaries. The dialogue with these parties continues through Sahara with Heritage exploring ways to assist the NTC and the state oil companies rehabilitate certain of their existing fields and recommence production.

The acquisition provides diversification to the current portfolio through potentially gaining access to some large producing fields in Libya. In addition, Heritage is considering using Sahara to assist with the drilling of its targets offshore Malta and is actively looking to contract a rig to drill in Area 7.

(1) BP Statistical Review 2011

RUSSIA

Since 2005, the Group has held a 95% equity interest in ChumpassNefteDobycha Limited, a Russian company whose sole asset is the Zapadno Chumpasskoye licence.

The Zapadno Chumpasskoye licence is in the hydrocarbon-rich West Siberian province of Khanty-Mansiysk, approximately 100 kilometres from the city of Nizhnevartovsk and in the area of the region's prolific Samotlor oilfield, which makes it accessible to existing infrastructure. The licence contains the Zapadno Chumpasskoye Field, discovered in 1997. A total of 13 wells have been drilled on the licence including four by the Group. The Chumpasskoye crude is light, sweet, (42º API) oil, with moderate gas-to-oil ratios.

Since 2006, the Group has acquired 2D seismic data covering an area of 200 kilometres, constructed pilot production facilities, drilled four wells and re-entered existing well 226. Production facilities were commissioned and production commenced in May 2007. In 2009, an electric submersible pump was installed on well 226 to arrest the natural well production decline and a water shut-off operation was completed on well P4. In 2010, well P14, an exploration well drilled in 1976, was re-entered and relogged.

In August 2011, drilling of well 363, the first horizontal well in the licence, completed and results of this well exceeded pre-drill expectations. During the flow test the well produced at rates of up to 1,405 bopd.

Production for the field averaged 673 bopd for the year, an increase of 24% year on year.

Historical development of this reservoir type throughout the region has been through conventional drilling on a grid pattern. Heritage recognised an opportunity to improve the efficiency and economics of field development by utilising horizontal drilling technology, thus decreasing the number of wells and the total cost required to develop the field, while potentially improving recovery. The previous reserves review and development plan undertaken by RPS Energy in June 2009 will be updated, incorporating the results of well 363. Further drilling on the licence is expected later in 2012.

The Group commenced shipment via Transneft at the end of 2009 and completed the first export sales of Zapadno Chumpasskoye crude via the Black Sea. Approval was obtained in 2010 from Transneft for a permanent pipeline tie-in to the Transneft transportation system. The capacity of our separation facility was expanded to handle the forecast production from the upcoming planned horizontal wells. The Company will be tying into Lukoil's nearby Langepas gas plant to conserve associated gas and therefore eliminate gas flaring in the field.

FINANCIAL REVIEW

Selected operational and financial data

2011 2010 Change
Production bopd 673 542 24 %
Sales volume bopd 671 539 25 %
Average realised price $/bbl 36.9 25.5 45 %
Petroleum revenue $ million 9.0 5.0 80 %
Loss from continuing operations $ million (63.0 ) (44.2 ) (43 %)
(Loss)/gain from discontinued operations $ million (3.9 ) 1,267.2 n/a
Net (loss)/profit $ million (66.9 ) 1,223.0 n/a
Special dividend per share Pence per share - 100 n/a
Total cash capital expenditures $ million 134.9 119.0
Year end cash balance $ million 310.9 598.3

CORPORATE PERFORMANCE

Production and sales volumes

2011 petroleum revenue was generated from the Zapadno Chumpasskoye Field in Russia. Well 363, the first horizontal well to be drilled in the field, was completed in August 2011 and commenced production from mid-August. This led to an increase in production resulting in a year-on-year increase in average daily production of 24% from 542 bopd in 2010 to 673 bopd in 2011. The year end exit rate was c. 937 bopd.

The difference between the production volumes and sales volumes is due to the change in the oil inventory balance during the year.

Revenue

Petroleum revenue increased by $4.0 million (80%) to $9.0 million in 2011. This increase comprised of:

  • $1.2 million from an increase in sales volumes from 539 bopd in 2010 to 671 bopd in 2011; and
  • $2.8 million from an increase in average commodity prices from $25.51/bbl in 2010 to $36.86/bbl in 2011.

Operating results

Expenses

Petroleum operating costs increased by 42% to $2.9 million in 2011, primarily due to higher crude oil production. Average operating cost per produced barrel of oil increased from $10.64/bbl in 2010 to $11.82/bbl in 2011, due primarily to higher well workovers, fuel and logistics costs.

Production tax in Russia increased from $2.6 million in 2010 to $4.9 million in 2011 as a result of both higher production volumes and increased average commodity prices in 2011, both of which are used in the calculation of the tax.

General and administrative expenses decreased from $29.8 million in 2010 to $19.9 million in 2011. This is due, principally, to certain corporate transaction costs being expensed in 2010 and arbitration settlement costs to be paid to a former director which were incurred in 2010. The reduction was offset by increases in travel costs incurred in 2011 as the Company continued its focus on increasing and diversifying its asset portfolio.

If share-based compensation expenses are excluded, net general and administrative expenses decreased from $26.6 million in 2010 to $17.4 million in 2011. In 2011, the Group capitalised $5.5 million (2010 - $6.7 million) of general and administrative costs relating to exploration and development activities, including share-based compensation of $1.1 million (2010 - $1.1 million).

Depletion, depreciation and amortisation expenses increased by 25% to $2.6 million in 2011, in line with the increased production volumes.

Exploration expenditures expensed in the year, and not capitalised, increased from $2.8 million in 2010 to $12.3 million in 2011. Exploration expenditures in 2011 related principally to activities in Africa as the Company looked to expand its portfolio in its core areas.

In 2011, the Group recognised an impairment of intangible exploration and evaluation assets of $10.8 million (2010 - $10.5 million). After a technical review management decided to write-off expenditure of $10.8 million incurred with respect to the Kimbiji licence area in Tanzania. The impairment recognised in 2010 comprised of two elements; $1.6 million write-off in connection with the DRC and $8.9 million write-off incurred with respect to the Kisangire and Lukuliro licence areas in Tanzania.

In 2010, the Group recognised an impairment write-down of property, plant and equipment of $1.9 million (2011 - nil) relating to a reduction in the fair value of an aircraft due to unfavourable economic conditions.

Finance income/costs

In 2011, interest income was $5.7 million (2010 - $3.0 million). Cash and cash equivalents are typically held in interest bearing treasury accounts. This increase in interest income is primarily due to an increase in average cash and cash equivalents balances and an increase in interest rates in 2011 in comparison with 2010, achieved through improved treasury management.

Other finance costs increased from $3.0 million in 2010 to $3.7 million in 2011, due primarily to increased convertible bond accretion costs.

In 2011, the Group had foreign exchange losses of $0.2 million compared to $1.8 million gains in 2010. The small loss arose from net foreign exchange gains and losses on revaluation of balances denominated in currencies different from the functional currency.

Heritage recognised an unrealised loss on investments of $20.3 million in 2011 (2010 - $0.9 million gain), which comprises of a decrease of $18.8 million in market value of investments in shares of PetroFrontier and a decrease of $1.5 million in fair value of its investment in Afren plc ("Afren"). As at 31 December 2011, the Company had acquired 9,748,200 shares of PetroFrontier representing 15.25% of listed shares of the company. The investment in share capital of PetroFrontier is classified as available-for-sale and valued at fair value which is determined using market price at the end of the period. At 31 December 2011, the market price of PetroFrontier shares was Cdn $1.18 per share. As at 16 April 2012 the share price had increased to Cdn $1.68 per share.

Until 4 November 2011, Heritage held 1,500,000 warrants in Afren with an exercise price of £0.60 per warrant, which were received as partial consideration from the sale of Heritage Congo Limited in 2006. On 4 November 2011, the Afren warrants were exercised and the Company acquired 1,500,000 of the listed shares in Afren. The investment in Afren shares is classified as available-for-sale and valued at fair value which is determined using market price at the end of the period. The valuation at market price as at 31 December 2011 resulted in a gain of $120,000 which was recognised in equity.

Results from continuing operations

Heritage's loss after tax from continuing operations in 2011 was $63.0 million, compared to $44.2 million in 2010. The adjusted loss from continuing operations in 2011 was $29.4 million compared to $31.3 million in 2010 if certain non-cash items (share-based compensation expense, impairment of intangible exploration and evaluation assets, property, plant and equipment impairment write-down, foreign exchange gains, unrealised gains/losses on revaluation of Afren warrants and unrealised loss on investment in PetroFrontier shares) are excluded.

Disposals

On 18 December 2009, Heritage announced that it and its wholly owned subsidiary HOGL, had entered into a SPA, with Eni for the sale of the Ugandan Assets. On 17 January 2010, Tullow exercised its rights of pre-emption. The transaction was overwhelmingly approved by Heritage shareholders at the General Meeting on 25 January 2010.

On 27 July 2010, Heritage announced that HOGL had completed the disposal of the Ugandan Assets. Tullow paid cash of $1.45 billion, including $100 million from a contractual settlement, of which Heritage received and retained $1.045 billion.

The URA contends that income tax is due on the capital gain arising on the disposal and it raised assessments of $404,925,000 prior to completion of the disposal. Heritage's position, based on comprehensive advice from leading legal and tax experts in Uganda, the United Kingdom and North America, is that no tax should be payable in Uganda on the disposal of the Ugandan Assets.

On closing, Heritage deposited $121,477,500 with the URA, representing 30% of the disputed tax assessment of $404,925,000. $121,477,500 has been classified as a deposit in the balance sheet at 31 December 2011. A further $283,447,000 has been retained in escrow with Standard Chartered Bank in London, pursuant to an agreement between HOGL, Tullow and Standard Chartered Bank pending resolution between the Ugandan Government and HOGL of the tax dispute. Including accrued interest, an amount of $284,479,000 is classified as restricted cash in the balance sheet at 31 December 2011.

In August 2010, the URA issued a further income tax assessment of $30 million representing 30% of the additional contractual settlement amount of $100 million. HOGL has challenged the Ugandan tax assessments on the disposal of HOGL's entire interest in the Ugandan Assets.

In November 2011 and December 2011, the Tax Appeals Tribunal in Uganda dismissed HOGL's applications in relation to the two assessments amounting to $434,925,000. In December 2011 and January 2012, HOGL commenced appeals to the Ugandan High Court in relation to the rulings from the Tax Appeals Tribunal. The rulings from the Tax Appeals Tribunal in Uganda are part of a domestic process and are not final and determinative. HOGL has appealed the rulings, which it believes are fatally flawed in many respects, through the Ugandan court system commencing with the High Court and subsequently the Court of Appeal and Supreme Court if necessary.

As a result of the actions of the tax authorities in Uganda, HOGL and its advisers consider that it was compelled to take part in a Ugandan domestic process before a Tax Appeals Tribunal, notwithstanding HOGL's belief that arbitration, which is ongoing in London and detailed below, is the correct forum to settle such disputes, in view of the existence of valid and binding arbitration provisions in its PSAs with the Ugandan Government.

In May 2011, HOGL commenced international arbitration proceedings in London against the Ugandan Government. HOGL is seeking a decision requiring, among other things, the return or release of approximately $405 million, plus interest, in aggregate currently on deposit with the URA or in escrow with Standard Chartered Bank in London. Accordingly, the arbitration proceedings concern HOGL's claims that the Ugandan Government wrongfully or unreasonably withheld consent to the sale by HOGL of the rights under the PSAs for the Ugandan Assets, including by making this consent conditional upon the payment of a sum alleged to be a tax liability of HOGL. The arbitration proceedings are being held in London in accordance with the provisions of the PSAs in relation to the Ugandan Assets.

On 15 April 2011, Heritage and its wholly owned subsidiary HOGL received Particulars of Claim filed in the High Court of Justice in England by Tullow seeking $313,447,500 for alleged breach of contract as a result of HOGL's and Heritage's refusal to reimburse Tullow in relation to a payment made by Tullow of $313,447,500 on 7 April 2011 to the URA. Heritage and HOGL believe that the claim has no basis and are in the process of vigorously and robustly defending it. Heritage and HOGL have filed their Defence and Counterclaim against Tullow seeking instead the release to HOGL of the $283,447,000 plus interest currently being held in escrow with Standard Chartered Bank in London.

Although disputes of this nature are inherently uncertain, the Directors believe that the monies on deposit and held in escrow will ultimately be recovered by Heritage.

The results of the Ugandan operations have been classified as discontinued operations. (Loss)/gain on disposal of discontinued operations as at 31 December 2011 and 2010 is as follows:

Year ended 31 December
2011
$'000
2010
$'000
(Loss)/gain on disposal of discontinued operations (3,933 ) 1,267,211
(3,933 ) 1,267,211

The 2011 loss relates to legal fees incurred in connection with the tax dispute which are considered to be an adjustment to the profit on disposal of the Ugandan Assets.

The 2010 gain from discontinued operations in Uganda of $1,267.2 million may be summarised as follows:

Year ended
31 December 2010
$ million
Consideration received
Cash consideration and amount to settle contractual dispute 1,450.0
Working capital adjustments 13.6
Total 1,463.6
Less:
Carrying amount of net assets sold and expenses (196.4 )
Gain on disposal of discontinued operations 1,267.2

In March 2011, Tullow paid working capital adjustments with respect to the Ugandan Assets of $13.6 million.

In 2011, the basic and diluted loss per share from continuing operations was $0.23, compared to $0.15 and $0.30, respectively, in 2010.

Heritage's net loss in 2011 was $66.9 million, compared to a net profit of $1,223.0 million in 2010.

In 2011, the basic and diluted loss per share was $0.25, compared to the basic and diluted earnings per share of $4.25 and $3.57, respectively, in 2010.

Cash flow and capital expenditures

Cash used in continuing operating activities was $34.6 million in 2011 compared to $21.0 million in 2010. Total cash capital expenditures, including acquisition of a subsidiary, in 2011 were $134.9 million which is higher by $15.9 million than in 2010. The following major work programmes and an acquisition were undertaken in 2011:

  • testing of the Miran West-2 well in Kurdistan completed in January 2011. The well was drilled to a total depth of 4,426 metres after it was modified to assess the exploration potential of deeper formations. The Miran West-2 well results confirmed three additional pay zones within the Lower Cretaceous and Jurassic formations in addition to the pay zone identified in the Upper Cretaceous in the Miran West-1 well. The Miran Gas Field is a commercial discovery and independent engineering studies have confirmed the potential for a fast-tracked, phased development of the field;
  • acquisition of a 3D seismic survey, covering 730 square kilometres, commenced on the Miran Block in the fourth quarter of 2010 and completed in the second half of 2011. The significant improvement in seismic data quality over the Miran Field is encouraging and assists greatly with the selection of well locations. An early phase of processing produced an initial dataset covering the core area of the field which was used to assist in the selection and orientation of the drilling of the deviated Miran West-3 and the Miran East-1 wells. The increased coverage and quality of the 3D data enables enhanced mapping of the structure and increased ability to identify fault systems;
  • acquisition of 180 kilometres of 2D seismic on the southern portion of the Miran Block to help identify further potential prospectivity was completed in October 2011. Interpretation of the data has highlighted a structure capable of containing additional resources. Further work is being undertaken to identify a suitable drilling location;
  • Miran West-3 well, commenced drilling in August 2011 and continued drilling into 2012 with the aim of targeting reservoir sections encountered in discovery wells with the primary objective of appraising the productivity of the Jurassic reservoir formation in the Miran West structure. To date, results from the well have confirmed oil in the Upper Cretaceous and gas in the Lower Cretaceous and Jurassic reservoirs. In April 2012, it was announced that a reservoir interval above the main Jurassic reservoir had been tested and resulted in a flow of up to 17.5 MMscfd of dry gas. Further drilling will appraise the Jurassic reservoir intervals discovered by the Miran West-2 well. A number of tests are planned and drilling is expected to be completed during the second quarter of 2012;
  • acquisition of a 51% equity interest and control in Sahara Oil, a company wholly owning Sahara for $19.5 million. Sahara has the rights to own and operate oil and gas licences in Libya. The Group agreed to pay the vendors additional consideration of $5 million becoming due on signing of an oil service contract;
  • drilling of well 363 in the Zapadno Chumpasskoye Field, Russia, completed at the beginning of August 2011, results of this well exceeded pre-drill expectations. During the flow test the well produced at rates of up to 1,405 bopd and led to a significant increase in production;
  • acquisition of 1,400 kilometres of 2D seismic across Area 7 in Malta in July 2011. Well planning is being undertaken to drill the principal prospect in Area 7;
  • in Mali, approximately 1,077 kilometres of 2D seismic was acquired over Blocks 7 and 11 and the data has been interpreted and integrated with legacy data; and
  • acquisition of 300 square kilometres of 3D seismic offshore Tanzania completed in January 2011. Interpretation of the Latham 3D has been completed and the process of completing geophysical studies of seismic data is underway in order to finalise the evaluation of mapped prospects in order to determine the forward work programme.

Buy back programme

At the Annual General Meetings ("AGMs") held on 17 June 2010 and 20 June 2011, a Special Resolution was passed by shareholders authorising the Company to make market purchases of its own shares. In April 2011, the Company announced its intention to commence a buy back programme to spend up to $100 million to acquire its Ordinary Shares using the authority granted at the 17 June 2010 AGM. Shareholders approved the resolution at the AGM on 20 June 2011 to acquire up to 28,900,000 Ordinary Shares from that date. Purchased Ordinary Shares are held in treasury.

In July 2011, the Company announced that the share purchases would be made via a trading plan to allow the buy back programme to continue independently through close periods. In August 2011, the Company made a further announcement that the programme would continue over and above the initial amount of $100 million up to a maximum amount of the buy back authority approved at the 2011 AGM if it continues to be in the best interests of the Company and its shareholders.

As at 31 December 2011 the Company held a total of 33,228,734 Ordinary Shares in treasury equal to 11% of the issued share capital as at 1 January 2011. The total acquisition cost of these shares was $123.6 million.

To date 33,856,107 Ordinary Shares have been bought back and are held in treasury. Consequently, Heritage has 255,891,923 Ordinary Shares in issue (excluding treasury shares) as well as 2,811,408 exchangeable shares of no par value of HOC, each carrying one voting right in Heritage. The total number of voting rights in Heritage, excluding treasury shares as at 17 April 2012, is 258,703,331.

PetroFrontier shares

As at 31 December 2011, the Company had acquired 9,748,200 of the listed shares of PetroFrontier representing 15.25% of the company. Total share acquisition costs amounted to $30.2 million. PetroFrontier is listed on the TSX Venture Exchange in Canada.

On 4 November 2011 the Afren warrants were exercised and the Company acquired 1,500,000 of the listed shares in Afren, which were continued to be held at year end.

2010 special dividend

On 2 August 2010, Heritage announced the declaration of a special dividend of 100 pence per Ordinary Share of the Company and HOC, the Company's wholly owned subsidiary, also announced a declaration of a special dividend of Cdn$1.62 per Exchangeable Share of HOC, calculated at an exchange rate of £1.00:Cdn$1.62. The special dividend was paid on 27 August 2010.

Following an amendment to the terms of the $165,000,000 8.00% convertible bonds due in 2012 (the "Bonds"), the special dividend was also paid to Bondholders and no adjustments were made to the conversion rights under the terms of the Bond (the "Conversion Rights") in respect of any dividend paid or made by the Company. The Company paid a $2.4 million consent fee to Bondholders who voted in favour of the amendment to the terms. Accordingly, the Company agreed to pay the holder of each Bond a pass-through dividend (the "Pass-through Dividend") which was equal to the dividend which would be received by the holder of a number of Ordinary Shares equal to the number of Ordinary Shares to which the Bondholder would have been entitled if it had exercised its Conversion Rights on the record date of 13 August 2010. The aggregate principal amount of Bonds outstanding on the record date was $127,100,000. These Bonds were convertible into 27,042,553 Ordinary Shares pursuant to the Conversion Rights and accordingly the Company paid to Bondholders a Pass-through Dividend of £27,042,553 on 27 August 2010.

FINANCIAL POSITION

Liquidity

There was a net decrease in cash and cash equivalents in 2011 of $287.4 million. At 31 December 2011, Heritage had a working capital surplus of $550.2million, including cash and cash equivalents of $310.9 million. Like most oil and gas exploration companies, Heritage raises financing for its activities from time to time using a variety of sources. Sources of funding for future exploration and development programmes will be derived from inter alia disposal proceeds from the sale of assets, such as the sale of the Company's Ugandan Assets in 2010 (see disposals section of the Financial Review) using its existing treasury resources, new credit facilities, reinvesting its funds from operations, farm-outs and, when considered appropriate, issuing debt and additional equity. Accordingly, the Group has a number of different sources of finance.

Capital structure

Heritage's financial strategy has been to fund its capital expenditure programmes and any potential acquisitions by selling non-core assets, reinvesting funds from operations, using existing treasury resources, finding new credit facilities and, when considered appropriate, either issuing unsecured convertible bonds or equity.

On 26 July 2010, the Company completed the disposal of the Ugandan Assets for cash consideration of $1.35 billion and an additional contractual settlement amount of $100 million.

At 31 December 2011, Heritage had net cash of $135.1 million (31 December 2010 - $409.2 million) (cash and cash equivalents less total liabilities) and nil gearing (31 December 2010 - nil) (net debt as a percentage of total shareholders' equity).

In February 2012, Heritage repaid the outstanding Bonds of $127.1 million at the end of the five year term.

Creditors' payment policy

It is the Company and Group's general policy to settle all debts with creditors on a timely basis and in accordance with the terms of credit agreed with each supplier. Average creditor payment days in 2011 were approximately 45 days (2010 - 45 days).

PRIMARY RISKS AND UNCERTAINTIES FACING THE BUSINESS

Heritage's business, financial standing and reputation may be impacted by various risks, not all of which are within its control. The Group identifies and monitors the key risks and uncertainties affecting the Group and runs its business in a way that minimises the impact of such risks where possible. The primary business risks include:

  • Exploration and development expenditures and success rates - the Group has experienced management and technical teams with a track record of finding major hydrocarbon discoveries and has a diversified portfolio of exploration, appraisal, development and production assets. Considerable technical work is undertaken to reduce related areas of risk and maximise opportunities.
  • Factors associated with operating in developing countries, political, fiscal and regulatory instability - the Group maintains close contact with governments in the areas where it operates and, where appropriate, invests in community projects. Considerable work is undertaken before commencing operations in any new territory.
  • Title disputes - notwithstanding potential challenges in Kurdistan and Malta, the Group believes that it has good title to its oil and gas properties. However, the Group cannot control or completely protect itself against the risk of title disputes or challenges and there can be no assurance that claims or challenges by third parties against the Group's properties will not be asserted at a future date. Naturally, the Group strives to employ the best internal and advisory knowledge available to help to minimise this risk associated with its activities.
  • Oil and gas sales volumes and prices - whilst not under the direct control of the Company, a large movement in commodity prices could impact on the Group. The Group did not hedge oil prices in 2011.
  • Loss of key employees - remuneration packages are regularly reviewed to ensure key executives and senior management are properly remunerated. Long-term incentive programmes have been established. Employees are encouraged to develop their potential and, where appropriate, to further their careers within the Group. This is one of the Group's Key Performance Indicators and continues to remain at low levels.
  • Foreign exchange exposure - generally, it is the Group's policy to conduct and manage its business in US dollars, which is its reporting currency. Cash balances in Group subsidiaries are primarily held in US dollars but small amounts may be held in other currencies in order to meet immediate operating or administrative expenses or to comply with local currency regulations.

INTERNAL CONTROL

A system of internal control was designed and tailored to ensure key risks are addressed appropriately and to provide assurance regarding the reliability of financial reporting and preparation of financial statements. Risk and internal control are assessed continually. One weakness identified in its financial procedures reporting concerns accounting for complex transactions and the Company ensures that it seeks third party advice to mitigate this weakness.

As part of the internal control, all transactions with related parties are identified, scrutinised and disclosed in the financial statements appropriately.

Heritage maintains insurance policies in accordance with industry standards. Heritage believes that the level of insurance cover it maintains is adequate, based on various factors such as the cost of the policies, industry standard practice and the risks associated with the exploration and development of oil and gas properties in the countries in which it operates. Heritage does not insure against political risk and, therefore, shareholders have full exposure to the risks and rewards of investing in its territories.

Heritage maintains detailed financial models which allows the Company to plan future operating and capital activities in an efficient manner.

Paul Atherton, Chief Financial Officer

17 April 2012

STATEMENT OF DIRECTORS' RESPONSIBILITIES

The statement below explains the Directors' responsibility for preparation of the Annual Report and Accounts 2011.

The Directors are responsible for preparing the Annual Report and Accounts for the Group in accordance with applicable Jersey law and regulations.

Company law requires the Directors to prepare Group financial statements for each financial year. Under that law they are required to prepare the Group financial statements in accordance with International Financial Reporting Standards ("IFRS") as adopted by the European Union ("EU") and applicable law.

The Group financial statements are required by law and IFRS as adopted by the EU to present fairly the financial position of the Group and the performance for that period.

In preparing the financial statements the Directors are required to:

  • select suitable accounting policies and then apply them consistently;
  • present information, including accounting policies, in a manner that provides relevant, reliable, comparable and understandable information;
  • provide additional disclosures when compliance with the specific requirements in IFRS is insufficient to enable users to understand the impact of particular transactions, other events and conditions on the entity's financial position and financial performance;
  • state whether they have been prepared in accordance with IFRS as adopted by the EU; and
  • prepare the financial statements on a going concern basis unless, having assessed the ability of the Company to continue as a going concern, it is inappropriate to presume the Company will continue in business.

The Directors are responsible for keeping proper accounting records which disclose with reasonable accuracy at any time the financial position of the Group and enable them to ensure that its financial statements comply with the Companies (Jersey) Law 1991 (as amended) (the "Jersey Companies Law"). They have general responsibility for taking such steps, as are reasonably open to them, for safeguarding the assets of the Group and to prevent and detect fraud and other irregularities.

Under applicable law, regulations and listing rule requirements, the Directors are also responsible for the preparation of a Directors' Report, Remuneration Report and Corporate Governance Statement, all of which are in the Corporate Governance Report.

The Directors are responsible for the maintenance and integrity of the statutory and audited information on the Company's website www.heritageoilplc.com. Jersey legislation and United Kingdom regulation, governing the preparation and dissemination of financial statements, may differ from requirements in other jurisdictions.

RESPONSIBILITY STATEMENT OF THE DIRECTORS

We confirm on behalf of the Board that to the best of our knowledge:

a) the financial statements prepared in accordance with the applicable accounting standards give a true and fair view of the assets, liabilities, financial position and profit or loss of the Company and the undertakings included in the consolidation taken as a whole; and
b) the management report (which is incorporated within the Annual Review, the Corporate Governance Report and the Corporate Social Responsibility Report) includes a fair review of the development and performance of the business, the position of the Company and the undertakings included in the consolidation taken as a whole, together with a description of the principal risks and uncertainties that they face.

GOING CONCERN

The Group's activities are described in the Annual Review. The financial position of the Group, its cash flows and liquidity position are described in the financial review and financial statements within the Financial Statements Report. In addition, the notes to the financial statements include the Group's policies and processes for managing its capital and its exposures to credit and liquidity risk. Having reviewed the future plans and projections for the Group and its current financial position, the Directors have a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future, a period of not less than 12 months from the date of this report. In making this assessment they have considered the Company and Group budgets, the cash flow forecasts and reviewed the availability of banking facilities. For this reason, it continues to adopt the going concern basis of accounting in preparing the annual financial statements.

For and on behalf of the Board

Michael J. Hibberd, Chairman

Paul Atherton, Chief Financial Officer

17 April 2012

Financial Information Included in This Announcement

The following information included in this Announcement does not constitute audited financial statements of the Group. The Accounts for the year ended 31 December 2011 have been audited and will be posted on the Group's website. The auditors have issued an unqualified opinion on those Accounts; their report includes an 'emphasis of matter' drawing attention to the disclosures made in the Group financial statements concerning the uncertain outcome of a dispute as to whether or not tax is payable on the disposal of the Group's interests in Uganda (which are reproduced in note 6 below). The following financial information has been extracted from those Accounts.

HERITAGE OIL PLC
CONSOLIDATED INCOME STATEMENT
Years ended 31 December 2011 and 2010
2011
$'000
2010
$'000
Revenue
Petroleum 9,030 5,015
Expenses
Petroleum operating (2,920 ) (2,055 )
Production tax (4,905 ) (2,609 )
General and administrative (note 22) (19,856 ) (29,785 )
Depletion, depreciation and amortisation (2,630 ) (2,111 )
Exploration expenditures (note 2e) (12,319 ) (2,818 )
Impairment of intangible exploration assets (note 10) (10,775 ) (10,535 )
Impairment of property, plant and equipment (note 11) - (1,854 )
Operating loss (44,375 ) (46,752 )
Finance income (costs)
Interest income 5,741 2,967
Other finance costs (note 7) (3,681 ) (2,970 )
Foreign exchange (losses)/gains (209 ) 1,830
Unrealised (losses)/gains on other financial assets (note 12) (20,282 ) 896
(18,431 ) 2,723
Loss from continuing operations before tax (62,806 ) (44,029 )
Income tax expense (note 8) (152 ) (197 )
Loss from continuing operations after tax (62,958 ) (44,226 )
(Loss)/gain on disposal of discontinued operations (note 6) (3,933 ) 1,267,211
(Loss)/profit for the year attributable to owners of the Company (66,891 ) 1,222,985

The notes are an integral part of these consolidated financial statements.

HERITAGE OIL PLC
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Years ended 31 December 2011 and 2010
2011
$'000
2010
$'000
(Loss)/profit for the year (66,891 ) 1,222,985
Other comprehensive loss
Exchange differences on translation of foreign operations (note 19) (883 ) (124 )
Net change in fair values of available-for-sale financial assets (18,765 ) -
Net change in fair values of available-for-sale financial assets reclassified to the income statement 18,885 -
Other comprehensive loss, net of income tax (763 ) (124 )
Total comprehensive (loss)/income for the year (67,654 ) 1,222,861
Attributable to:
Owners of the Company (67,654 ) 1,222,861
Net loss per share from continuing operations (dollars)
Basic (0.23 ) (0.15 )
Diluted (0.23 ) (0.30 )
Net (loss)/earnings per share from discontinued operations (dollars)
Basic (0.02 ) 4.40
Diluted (0.02 ) 3.70
Net (loss)/earnings per share (dollars)
Basic (0.25 ) 4.25
Diluted (0.25 ) 3.57

The total comprehensive loss for the year of $67,654,000 (2010 income - $1,222,861,000) includes loss of $3,933,000 (2010 income - $1,267,211,000) from discontinued operations (note 6).

The notes are an integral part of these consolidated financial statements.

HERITAGE OIL PLC
CONSOLIDATED BALANCE SHEET
As at 31 December 2011 and 2010
2011
$'000
2010
$'000
ASSETS
Non-current assets
Intangible exploration and evaluation assets (note 10) 271,859 183,424
Property, plant and equipment (note 11) 106,852 101,993
Other financial assets (note 12) 13,268 2,050
391,979 287,467
Current assets
Inventories 78 97
Prepaid expenses 1,344 746
Trade and other receivables (note 13) 1,788 20,240
Deposit with the URA (note 6) 121,477 121,477
Restricted cash (note 6) 284,479 283,603
Cash and cash equivalents (note 14) 310,882 598,275
720,048 1,024,438
1,112,027 1,311,905
LIABILITIES
Current liabilities
Trade and other payables (note 15) 35,391 54,083
Current tax liabilities (note 8) 104 197
Borrowings (note 16) 134,397 896
169,892 55,176
Non-current liabilities
Borrowings (note 16) 5,110 133,515
Provisions (note 17) 783 389
Deferred tax (note 8) 38 -
5,931 133,904
175,823 189,080
Net assets 936,204 1,122,825
SHAREHOLDERS' EQUITY ATTRIBUTABLE TO EQUITY HOLDERS OF THE COMPANY
Share capital (note 18) 345,682 460,280
Reserves 83,326 86,678
Retained earnings 507,196 575,867
936,204 1,122,825

The notes are an integral part of these consolidated financial statements.

HERITAGE OIL PLC
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY - 2011
Year ended 31 December 2011
Share
Capital
$'000
Foreign
currency
translation
reserve
$'000
Available-
for-sale
investments
revaluation
reserve
$'000
Share-
based
payments
reserve
$'000
Retained
earnings
$'000
Equity
portion of
convertible
debt
$'000
Total
equity
$'000
Balance at 1 January 2011 460,280 (940 ) - 62,969 575,867 24,649 1,122,825
Total comprehensive loss for the year
Loss for the year - - - - (66,891 ) - (66,891 )
Other comprehensive income/(loss)
Exchange differences on translation of foreign operations - (883 ) - - - - (883 )
Net change in fair value of available-for-sale financial assets - - (18,765 ) - - - (18,765 )
Net change in fair value of available-for-sale financial asset reclassified to the income statement - - 18,885 - - - 18,885
Total other comprehensive income/(loss) - (883 ) 120 - - - (763 )
Total comprehensive income/(loss) for the year - (883 ) 120 - (66,891 ) - (67,654 )
Transactions with owners, recorded directly in equity
Contributions by and distributions to owners
Share buy back (123,575 ) - - - - - (123,575 )
Exercise of share options net of attributable dividends (note 21) 1,225 - - (1,225 ) (1,780 ) - (1,780 )
Share-based payment transactions and exercise of share options 7,752 - - (1,364 ) - - 6,388
Total transactions with owners (114,598 ) - - (2,589 ) (1,780 ) - (118,967 )
Balance at 31 December 2011 345,682 (1,823 ) 120 60,380 507,196 24,649 936,204

The notes are an integral part of these consolidated financial statements.

HERITAGE OIL PLC
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY - 2010
Year ended 31 December 2010
Share
Capital
$'000
Foreign
currency
translation
reserve
$'000
Share-based
payments
reserve
$'000
Retained
earnings/
(deficit)
$'000
Equity
portion of
convertible
debt
$'000
Total
equity
$'000
Balance at 1 January 2010 460,280 (816 ) 58,714 (153,164 ) 24,649 389,663
Total comprehensive income for the year
Profit for the year - - - 1,222,985 - 1,222,985
Other comprehensive loss
Exchange differences on translation of foreign operations - (124 ) - - - (124 )
Total other comprehensive loss - (124 ) - - - (124 )
Total comprehensive income/(loss) for the year - (124 ) - 1,222,985 - 1,222,861
Transactions with owners, recorded directly in equity
Contributions by and distributions to owners
Dividends to shareholders - - - (451,537 ) - (451,537 )
Pass-through dividend to Bondholders - - - (42,417 ) - (42,417 )
Share-based payment transactions and exercise of share options - - 4,255 - - 4,255
Total transactions with owners - - 4,255 (493,954 ) - (489,699 )
Balance at 31 December 2010 460,280 (940 ) 62,969 575,867 24,649 1,122,825

The notes are an integral part of these consolidated financial statements.

HERITAGE OIL PLC
CONSOLIDATED CASH FLOW STATEMENT
Years ended 31 December 2011 and 2010
2011
$'000
2010
$'000
Cash provided by (used in) operating activities
Net loss from continuing operations for the year (62,958 ) (44,226 )
Items not affecting cash
Depletion, depreciation and amortisation 2,630 2,111
Finance costs - accretion expenses 1,352 998
Foreign exchange gains (665 ) (289 )
Share-based compensation 2,525 3,169
Loss/(gain) on other financial assets 20,282 (896 )
Impairment of intangible exploration and evaluation assets 10,775 10,535
Impairment of property, plant and equipment - 1,854
Decrease/(increase) in trade and other receivables 139 (1,124 )
Increase in prepaid expenses (599 ) (178 )
Decrease/(increase) in inventory 18 (84 )
(Decrease)/increase in trade and other payables (7,187 ) 6,953
Accrued interest on restricted cash (876 ) -
(Decrease)/increase in tax payable (55 ) 197
Continuing operations (34,619 ) (20,980 )
Discontinued operations (note 6) (4,137 ) (300 )
(38,756 ) (21,280 )
Investing
Property, plant and equipment expenditures (6,864 ) (46,946 )
Intangible exploration and evaluation expenditures (96,469 ) (50,284 )
Other financial assets (31,612 ) -
(134,945 ) (97,230 )
Discontinued operations
Consideration on disposal (note 6) - 1,450,000
Transaction related expenses and other 9,901 (17,397 )
Increase in deposit with URA (note 6) - (121,477 )
Property, plant and equipment expenditures and intangible exploration and evaluation expenditures (note 6) - (21,735 )
Increase in restricted cash (note 6) - (283,603 )
(125,044 ) 908,558
Financing
Share buy back (123,575 ) -
Shares issued for cash, proceeds from exercise of share options 2,659 -
Payment on exercise of share options (note 21) (1,780 ) -
Payment of Bondholder consent fees (note 16) - (2,378 )
Distribution to shareholders - (451,537 )
Pass-through dividend to Bondholders - (42,417 )
Repayment of long-term debt (810 ) (823 )
(123,506 ) (497,155 )
(Decrease)/increase in cash and cash equivalents (287,306 ) 390,123
Cash and cash equivalents - beginning of year 598,275 208,094
Foreign exchange (loss)/gain on cash held in foreign currency (87 ) 58
Cash and cash equivalents - end of year 310,882 598,275
Non-cash investing and financing activities (note 24)
Supplementary information
The following have been included within cash flows for the year under operating and investing activities
Interest received 6,170 2,298
Interest paid 10,429 10,473
Aborted acquisition expenses - 800

The notes are an integral part of these consolidated financial statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1 Reporting Entity

Heritage Oil Plc was incorporated under the Jersey Companies Law on 6 February 2008 as Heritage Oil Limited. The Company changed its name to Heritage Oil Plc on 18 June 2009. Its primary business activity is the exploration, development and production of petroleum and natural gas in Africa, the Middle East and Russia. The Company was established in order to implement a corporate reorganisation of HOC.

These consolidated financial statements include the results of the Company and all subsidiaries over which the Company exercises control. The Company together with its subsidiaries are referred to as the Group. The key subsidiaries consolidated within these financial statements include inter alia Heritage Oil Corporation, Heritage Oil & Gas Limited, Heritage Oil and Gas (U) Limited, Heritage Energy Middle East Limited, Heritage DRC Limited, Coatbridge Estates Limited, ChumpassNefteDobycha, Neftyanaya Geologicheskaya Kompaniya, Heritage Mali Block 7 Limited, Heritage Mali Block 11 Limited, Begal Air Limited, Heritage Oil & Gas Holdings Limited, Eagle Drill Limited, Heritage Oil International Malta Limited, 1381890 Alberta ULC, Heritage Oil Cooperatief U.A, Heritage Oil Holdings Limited, Darwin Air Limited, Heritage Tanzania Kimbiji-Latham Limited, Heritage Oil Tanzania Limited, Heritage Oil (UK) Limited, Heritage Rukwa (TZ) Limited, Heritage Energy Limited, Heritage Energy International Limited, Sahara Oil Services Limited and Sahara Oil Services Holdings Limited.

The financial statements were approved by the Board and authorised for issuance on 17 April 2012.

2 Significant Accounting Policies

The principal accounting policies applied in the preparation of these consolidated financial statements are set out below. These policies have been consistently applied to all the years presented, unless otherwise stated.

a) Basis of preparation

The consolidated financial statements have been prepared in accordance with IFRS as adopted by the EU.

The consolidated financial statements have been prepared under the historical cost convention, as modified by the revaluation of certain financial assets and liabilities at fair value.

The Company's consolidated financial statements are presented in thousand US dollars unless otherwise stated. US dollars are the Company's functional and presentation currency.

The Group had available cash of $311 million at 31 December 2011, excluding amounts related to the tax dispute with the Ugandan Government. Based on its current plans and knowledge, its projected capital expenditure and operating cash requirements, the Group has sufficient cash to finance its operations for more than 12 months from the date of this report. As for most oil and gas exploration companies, Heritage raises financing for its activities from time to time using a variety of sources. Sources of funding for future exploration and development programmes will be derived from inter alia disposal proceeds from the sale of assets, such as the disposal of the Ugandan Assets in 2010 (note 6), using its existing treasury resources, new credit facilities, reinvesting its funds from operations, farm-outs and, when considered appropriate, issuing debt and additional equity. Accordingly, the Group has a number of different sources of finance available and the Directors are confident that additional finance will be raised as and when needed.

After making enquiries, the Directors have a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future. Accordingly, they continue to adopt the going concern basis in preparing the Annual Report and Accounts.

The financial position of the Group, its cash flows and liquidity position are described in the Financial Review of this report. In addition, note 3 of the financial statements includes the Group's policies and processes for managing its capital; its financial risk management; and its exposure to foreign exchange risk, commodity price risk, credit risk and liquidity risk.

The preparation of financial statements in conformity with IFRS requires the use of certain critical accounting estimates. It also requires management to exercise its judgement in the process of applying the Company's accounting policies. The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are significant to the consolidated financial statements, are disclosed in note 4.

b) Consolidation

The consolidated financial statements incorporate the assets and liabilities of all subsidiaries of the Company as at 31 December 2011 and 2010 and the results of all subsidiaries for the years then ended.

Subsidiaries are all entities, including special purpose entities over which the Company has the power to govern the financial and operating policies, so as to obtain benefits from its activities, generally accompanying a shareholding of more than one half of the voting rights. The existence and effect of potential voting rights that are currently exercisable or convertible are considered when assessing whether the Company controls another entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Company. They are deconsolidated from the date that control ceases.

The purchase method of accounting is used to account for the acquisition of subsidiaries by the Group. The cost of an acquisition is measured as the fair value of the assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date, irrespective of the extent of any minority interest. The excess of the cost of acquisition over the fair value of the Group's share of the net fair value of the identifiable assets, liabilities and contingent liabilities acquired is recorded as goodwill. If the cost of acquisition is less than the fair value of the net assets of the subsidiary acquired, the difference is recognised immediately in the income statement.

Inter-company transactions, balances and unrealised gains on transactions between Group entities (the Company and its subsidiaries) are eliminated. For the purposes of consolidation, the accounting policies of subsidiaries have been changed where necessary to ensure consistency with the policies adopted by the Company.

c) Segment reporting

The Group determines and presents operating segments based on the information that internally is provided to the Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"), who are the Group's chief operating decision makers.

An operating segment is a component of the Group that engages in business activities from which it may earn revenues and incur expenses, including revenues and expenses that relate to transactions with any of the Group's other components. An operating segment's operating results are reviewed regularly by the CEO and CFO to make decisions about resources to be allocated to the segment and assess its performance, and for which discrete financial information is available.

Segment results that are reported to the CEO and CFO include items directly attributable to a segment as well as those that can be allocated on a reasonable basis. Unallocated items comprise mainly corporate assets, corporate offices expenses and liabilities.

Segment capital expenditure is the total cost incurred during the period to acquire property, plant and equipment, and intangible assets other than goodwill.

d) Joint arrangements

The majority of exploration, development and production activities are conducted jointly with others under contractual arrangement and, accordingly, the Group only reflects its proportionate interest in such assets, liabilities, revenues and expenses.

e) Exploration and evaluation expenditures

The Group applies a modified full cost method of accounting for exploration and evaluation ("E&E") costs, having regard to the requirements of IFRS 6 Exploration for and Evaluation of Mineral Resources. Under the modified full cost method of accounting, costs of exploring for and evaluating oil and gas properties are capitalised on a licence or prospect basis and the resulting assets are tested for impairment by reference to appropriate cost pools. Such cost pools are based on geographic areas and are not larger than a segment. The Group had seven cost pools in 2011 (2010 - seven cost pools); Uganda (discontinued in 2010); Kurdistan; Russia; the DRC (written off in 2010); Pakistan; Malta; Mali, Tanzania and Libya (entered in 2011).

E&E costs related to each licence/prospect are initially capitalised within 'Intangible exploration and evaluation assets'. Such E&E costs may include costs of licence acquisition, technical services and studies, seismic acquisition, exploration drilling and testing, the projected costs of retiring the assets, if any, and directly attributable general and administrative expenses, but do not include costs incurred prior to having obtained the legal rights to explore an area, which are expensed directly to the income statement as they are incurred.

Where the Company farms-in to licences and incurs costs in excess of its own share of licence costs as consideration, these costs are capitalised as its own share.

Tangible assets acquired for use in E&E activities are classified as property, plant and equipment; however, to the extent that such a tangible asset is consumed in developing an intangible E&E asset, the amount reflecting that consumption is recorded as part of the cost of the intangible asset.

Intangible E&E assets related to each exploration licence/prospect are not depreciated and are carried forward until the existence, or otherwise, of commercial reserves has been determined. The Group's definition of commercial reserves for such purpose is proved and probable reserves on an entitlement basis.

Proved and probable reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty (see below) to be recoverable in future years from known reservoirs and which are considered commercially producible. There should be a 50% statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as proved and probable and a 50% statistical probability that it will be less. The equivalent statistical probabilities for the proven component of proved and probable reserves are 90% and 10%, respectively.

Such reserves may be considered commercially producible if management has the intention of developing and producing them and such intention is based upon:

  • a reasonable assessment of the future economics of such production;
  • a reasonable expectation that there is a market for all or substantially all the expected hydrocarbon production; and
  • evidence that the necessary production, transmission and transportation facilities are available or can be made available.

Furthermore:

i) Reserves may only be considered proved and probable if producibility is supported by either actual production or a conclusive formation test. The area of reservoir considered proved includes: (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, or both; and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geophysical, geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
ii) Reserves which can be produced economically through application of improved recovery techniques, such as fluid injection, are only included in the proved and probable classification when successful testing by a pilot project, the operation of an installed programme in the reservoir, or other reasonable evidence (such as, experience of the same techniques on similar reservoirs or reservoir simulation studies) provides support for the engineering analysis on which the project or programme was based.

If commercial reserves have been discovered, the related E&E assets are assessed for impairment on a cost pool basis as set out below and any impairment loss is recognised in the income statement. The carrying value, after any impairment loss, of the relevant E&E assets is then reclassified as development and production assets within property, plant and equipment.

E&E assets are assessed for impairment when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Such indicators include the point at which a determination is made as to whether or not commercial reserves exist. Where the E&E assets concerned fall within the scope of an established full cost pool, the E&E assets are tested for impairment together with all development and production assets associated with that cost pool, as a single cash generating unit. The aggregate carrying value is compared against the expected recoverable amount of the pool, generally by reference to the present value of the future net cash flows expected to be derived from production of commercial reserves. Where the E&E assets to be tested fall outside the scope of any established cost pool, there will generally be no commercial reserves and the E&E assets concerned will be written off in full.

f) Property, plant and equipment

i) Development and production assets

The Group had one interest at the development and production stage during the years covered by these financial statements: Russia.

Development and production assets are accumulated on a field-by-field basis and represent the cost of developing the commercial reserves discovered and bringing them into production, together with the E&E expenditures incurred in finding commercial reserves transferred from intangible E&E assets as outlined above, the projected cost of retiring the assets and directly attributable general and administrative expenses.

The net book values of producing assets are depleted on a field-by-field basis using the unit of production method by reference to the ratio of production in the year to the related proved plus probable reserves of the field, taking into account estimated future development expenditures necessary to bring those reserves into production.

An impairment test is performed whenever events and circumstances arising during the development or production phase indicate that the carrying value of a development or production asset may exceed its recoverable amount. The aggregate carrying value is compared against the expected recoverable amount of the cash generating unit, generally by reference to the present value of the future net cash flows expected to be derived from the production of commercial reserves. The cash generating unit applied for impairment test purposes is generally the field, except that a number of field interests may be grouped as a single cash generating unit where the cash flows generated by the fields are interdependent.

ii) Other assets

Other property, plant and equipment are stated at cost less accumulated depreciation and any impairment in value. The assets' useful lives and residual values are assessed on an annual basis. Furniture and fittings are depreciated using the reducing balance method at 20% per year.

Land is not subject to depreciation.

Aircraft are depreciated over their expected useful life of 60 months. Depreciation is charged so as to write-off the cost, less estimated residual value of aircraft on a straight-line basis.

Corporate capital assets are depreciated on a straight-line basis over their estimated useful lives. The building is depreciated on a straight-line basis over 40 years with nil residual value. The land is not depreciated.

g) Cash and cash equivalents

Cash and cash equivalents include cash on hand, deposits held at call with banks and other short-term highly liquid investments with original maturities of three months or less. Cash and cash equivalents are stated at amortised cost using the effective interest rate method.

h) Trade and other receivables

Trade and other receivables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method, less provision for impairment. A provision for impairment of trade receivables is established when there is objective evidence that the Group will not be able to collect all amounts due according to the original terms of the receivables.

i) Inventories

Inventories consist of petroleum, condensate, liquid petroleum gas and materials that are recorded at the lower of weighted average cost and net realisable value. Cost comprises direct materials, direct labour, depletion and those overheads that have been incurred in bringing the inventories to their present location and condition. Net realisable value is the estimated selling price in the ordinary course of business, less applicable variable selling expenses. Provision is made for obsolete, slow-moving or defective items where appropriate.

j) Investments

The Group classifies its investments in the following categories: financial assets at fair value through the income statement and available-for-sale financial assets. The classification depends on the purpose for which the investments were acquired. Management determines the classification of its investments at initial recognition. During the years covered by these financial statements the Group did not have any investments classified as 'loans and receivables' or 'held to maturity investments'.

i) Financial assets at fair value through the income statement

Financial assets held for trading are carried at fair value with changes in fair value recognised in the income statement. A financial asset is classified in this category if acquired principally for the purpose of selling in the short-term. Derivatives are classified as held for trading unless they are designated as hedges.

Gains or losses arising from changes in the fair value of the 'financial assets at fair value through the income statement' category are presented in the income statement within 'Unrealised gain/(loss) on other financial assets' in the year in which they arise.

ii) Available-for-sale financial assets

Available-for-sale financial assets, comprising principally marketable equity securities, are non-derivatives that are either designated in this category or not classified. They are included in non-current assets unless management intends to dispose of the investment within 12 months of the balance sheet date.

Changes in the fair value of monetary securities classified as available-for-sale (other than impairment losses and foreign exchange gains and losses which are recognised in the income statement) are recognised in equity. Upon sale of a security classified as available-for-sale, the cumulative gain or loss previously recognised in equity is recognised in the income statement.

The Group assesses at each balance sheet date whether there is objective evidence that a financial asset or a group of financial assets is impaired. Measurement is assessed by reference to the fair value of the financial asset or group of financial assets.

k) Non-current assets held for sale and discontinued operations

Non-current assets, or disposal groups, are classified as assets held for sale and stated at the lower of their carrying amount and fair value less costs to sell if their carrying amount will be recovered principally through a sale transaction rather than through continuing use.

Non-current assets, including those that are part of a disposal group are not depreciated or amortised while they are classified as held for sale. Interest and other expenses attributable to the liabilities of a disposal group classified as held for sale continue to be recognised.

Non-current assets classified as held for sale and the assets of a disposal group classified as assets held for sale are presented separately, as current assets, from the other assets in the balance sheet. The liabilities of a disposal group classified as held for sale are presented separately, as current liabilities, from other liabilities in the balance sheet.

A discontinued operation is a component of the Group's business that represents a separate major line of business or geographical area of operations that has been disposed of or is held for sale, or is a subsidiary acquired exclusively with a view to resale. Classification as a discontinued operation occurs upon disposal or when the operation meets the criteria to be classified as held for sale, if earlier. When an operation is classified as a discontinued operation, from the comparative income statement is represented as if the operation had been discontinued from the start of the comparative period.

l) Trade and other payables

These amounts represent liabilities for goods and services provided to the Group prior to the end of the financial year which are unpaid.

m) Borrowings

Borrowings are initially recognised at fair value, net of transaction costs incurred. Borrowings are subsequently measured at amortised cost. Any difference between the proceeds (net of transaction costs) and the redemption amount is recognised in the income statement over the period of the borrowings using the effective interest method.

Convertible bonds are separated into liability and derivative liability components (being the Bondholders' conversion option) and each component is recognised separately. On initial recognition, the fair value of the liability component of a convertible bond is determined using a market interest rate for an equivalent non-convertible bond. This amount is recorded as a liability on an amortised cost basis using the effective interest method until extinguished on conversion or maturity of the Bonds. The Company reassesses the classification during the life of the convertible bond and reclassifies between liabilities and equity when appropriate.

Borrowings are removed from the balance sheet when the obligation specified in the contract is discharged, cancelled or expired. The difference between the carrying amount of a financial liability that has been extinguished or transferred to another party and the consideration paid, including any non-cash assets transferred or liabilities assumed, is recognised in finance income or costs.

Borrowings are classified as current liabilities unless the Group has an unconditional right to defer settlement of the liability for at least 12 months after the balance sheet date.

n) Borrowing costs

Borrowing costs incurred for the construction of any qualifying asset are capitalised during the period of time that is required to complete and prepare the asset for its intended use or sale. Other borrowing costs are expensed.

The capitalisation rate used to determine the amount of borrowing costs to be capitalised is the weighted average interest rate applicable to the Group's outstanding borrowings during the year. For the year ended 31 December 2011, this was 13.02% (31 December 2010 - 13.01%).

o) Provisions

Asset retirement obligations

Provision is made for the estimated cost of any asset retirement obligations when the Group has a present legal or constructive obligation as a result of past events, it is probable that an outflow of resources will be required to settle the obligation and the amount has been reliably estimated. Provisions are not recognised for future operating losses. Asset retirement obligation expense is capitalised in the relevant asset category unless it arises from the normal course of production activities.

Provisions are measured at the present value of management's best estimate of expenditure required to settle the present obligation at the balance sheet date. The discount rate used to determine the present value reflects current market assessments of the time value of money and the risks specific to the liability.

Subsequent to the initial measurement of the asset retirement obligation, the obligation is adjusted at the end of each year to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognised as finance costs whereas changes in the estimated future cash flows are added to or deducted from the related asset in the current period.

p) Revenue recognition

Revenue from the sale of petroleum and natural gas is recognised at the fair value received or receivable and is recorded when the significant risks and rewards of ownership of the product are transferred to the buyer. For sales of oil and gas this is usually when legal title passes to the external party which occurs on shipment of oil and gas to the buyer. Interest income is recognised on a time proportion basis using the effective interest method.

q) Income taxes

Current income tax is based on taxable profit for the year. Taxable profit differs from profit as reported in the income statement because it excludes items that are never taxable or deductible as well as those that are taxable or deductible in a different period. The Group's current tax assets and liabilities are calculated using tax rates that have been enacted or substantively enacted by the balance sheet date.

Deferred income tax is provided in full, using the balance sheet method, on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the consolidated financial statements. Deferred income tax is determined using tax rates (and laws) that have been enacted or substantively enacted by the balance sheet date and are expected to apply when the related deferred income tax asset is realised or the deferred income tax liability is settled.

Deferred tax assets are recognised for deductible temporary differences and unused tax losses only if it is probable that future taxable amounts will be available to utilise those temporary differences and losses.

Deferred tax assets and liabilities are offset when there is a legally enforceable right to offset current tax assets and liabilities and when the deferred tax balances relate to the same taxation authority.

r) Foreign currency translation

Items included in the financial statements of each of the Company's consolidated subsidiaries are measured using the currency of the primary economic environment in which the subsidiary operates (the "functional currency"). The Company's consolidated financial statements are presented in thousand US dollars, which is the Company's functional and presentation currency.

Foreign currency transactions are translated into the respective functional currencies of Group entities using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the income statement.

The results and financial position of all the Company's consolidated subsidiaries (none of which has a functional currency that is the currency of a hyperinflationary economy) that have a functional currency different from the presentation currency are translated into the presentation currency as follows:

i) assets and liabilities for each balance sheet presented are translated at the closing rate at the date of that balance sheet;
ii) income and expenses for each year are translated at average exchange rates (unless this is not a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the dates of the transactions); and
iii) all resulting exchange differences are recognised as either income or expense in a separate component of equity.

Foreign currency loans and overdrafts are designated as, and are considered to be, hedges of the exchange rate exposure inherent in foreign currency net investments and, to the extent that the hedge is effective, exchange differences giving rise to changes in the carrying value of foreign currency loans are also recognised as income or expense directly in equity. All other exchange differences giving rise to changes in the carrying value of foreign currency loans and overdrafts are recognised in the income statement.

When a foreign operation is sold, a proportionate share of the cumulative exchange differences previously recognised in equity are recognised in the income statement, as part of the gain or loss on sale where applicable.

s) Share-based compensation plans

The Group applies the fair value method of accounting to all equity- classified share-based compensation arrangements for both employees and non-employees. Compensation costs of equity-classified awards to employees are measured at fair value of the awards at the grant date and recognised over the periods during which the employees become unconditionally entitled to the options. The compensation cost is charged to the income statement with a corresponding increase in equity. The amount recognised as an expense is adjusted to reflect the actual number of share options that vest.

The compensation cost of equity-classified awards to non-employees is initially measured at fair value of the awards at the grant date and periodically remeasured to fair value until the non-employees' performance is complete, and recognised over the periods during which the non-employees become unconditionally entitled to the options. The compensation cost is charged to income with a corresponding increase to share-based payment reserve.

Dividends declared but not paid out before exercise of the option are recognised only when the exercise price, reduced for the dividends declared, becomes a recognised receivable upon exercise. The obligation to pay the dividends reduces the unrecognised receivable due from the option holder. The dividends are netted against the amount with the proceeds from the exercise price and not recognised as a separate distribution in equity.

Upon the exercise of the award, consideration received is recognised in equity (notes 18).

t) Share capital

Ordinary and Exchangeable Shares are classified as share capital. Incremental costs directly attributable to the issue of new shares or options are shown in equity as a deduction, net of tax, from the proceeds.

If the Company reacquires its own equity instruments the cost is deducted from equity and the associated shares are cancelled or held in treasury.

u) Earnings per share

Basic earnings per share is calculated by dividing the profit attributable to equity holders of the Company by the weighted average number of Ordinary and Exchangeable Shares outstanding during the financial period. The rights of different classes of shares are the same and therefore economically equivalent. As such, Ordinary and Exchangeable Shares are treated as one class of shares for the earnings per share calculation. Diluted earnings per share adjusts the figures used in the determination of basic earnings per share to take into account the after income tax effect of interest and other financing costs associated with dilutive potential Ordinary Shares and the weighted average number of shares assumed to have been issued for no consideration in relation to dilutive potential Ordinary Shares.

The if-converted method used in the calculation of diluted earnings per share assumes the conversion of convertible securities at the later of the beginning of the reported period or issuance date, if dilutive.

v) New accounting standards and interpretations

Certain new accounting standards and interpretations have been published that are not mandatory for the year ended 31 December 2011. The Company's assessment of the impact of these new standards and interpretations which have not been adopted is set out below.

i) IFRS 9 Financial Instruments (not yet endorsed for use in the EU) is effective for accounting periods commencing 1 January 2013. The expected impact is still being assessed by management, but is expected to only impact disclosures of the Group.
ii) The amendments to IFRS 7 Disclosures - Transfer of Financial Assets (endorsed by the EU in November 2011), IAS 12 Deferred Tax: Recovery of Underlying Assets and IAS 19 Employee Benefits (not yet endorsed by the EU) are effective for accounting periods beginning on or after 1 July 2011, 1 January 2012 and 1 January 2013 respectively. They are not expected to have a significant impact upon the Group's net results, net assets or disclosures.
iii) IFRS 11 Joint Arrangements and IAS 28 Investments in Associates and Joint Ventures (2011) (not yet endorsed for use in the EU) are effective for accounting periods commencing 1 January 2013. The expected impact is still being assessed by management, to ascertain the impact upon the Group's net results, net assets and disclosures.
iv) IFRS 10 Consolidated Financial Statements, IFRS 12 Disclosure of Interests in Other Entities, IFRS 13 Fair Value Measurement and IAS 27 Separate Financial Statements (2011) (not yet endorsed for use in the EU) are effective for accounting periods commencing 1 January 2013. None of the amendments are expected to have a significant impact upon the Group's net results, net assets and disclosures.
v) Presentation of Items of Other Comprehensive Income (Amendments to IAS 1) (not yet endorsed for use in the EU) is effective for periods commencing 1 July 2012. It is not expected to have a significant impact on the disclosures of the Group.

3 Risk Management

The Group's activities expose it to a variety of financial risks that arise as a result of its exploration, development, production and financing activities. The Group's overall risk management programme focuses on the unpredictability of financial markets and seeks to minimise potential adverse effects on the Group's financial performance.

a) Financial risk management

i) Foreign exchange risk

Foreign exchange risk arises when transactions and recognised assets and liabilities of the Group entity concerned are denominated in a currency that is not the Company's functional currency. The Group operates internationally and is exposed to foreign exchange risk arising from currency exposures to the US dollar.

There are no forward exchange rate contracts in place at, or subsequent to, 31 December 2011.

At 31 December 2011, if the Canadian dollar had strengthened/ weakened by 10% against the US dollar with all other variables held constant, the loss from continuing operations for the year would have been $40,000 (31 December 2010 - $8,000) higher/(lower), mainly as a result of foreign exchange gains/losses on translation of Canadian dollar-denominated general and administrative expenses and cash in bank.

At 31 December 2011, if the Russian rouble had strengthened/weakened by 10% against the US dollar with all other variables held constant, the loss from continuing operations for the year would have been $(1,160,000) (31 December 2010 - $(761,000) higher/(lower), mainly as a result of foreign exchange gains/losses on translation of Russian rouble-denominated cash in bank and monetary assets and liabilities.

At 31 December 2011, if the GB pound sterling had strengthened/ weakened by 10% against the US dollar with all other variables held constant, the loss from continuing operations for the year would have been $1,354,000 (31 December 2010 - $611,000) higher/(lower), mainly as a result of GB pound sterling-denominated general and administrative expenses and foreign exchange gains/losses on translation of GB pound sterling-denominated long-term loan and cash in bank.

At 31 December 2011, if the Swiss franc had strengthened/weakened by 10% against the US dollar with all other variables held constant, the loss from continuing operations for the year would have been $469,000 (31 December 2010 - $728,000 higher/(lower), mainly as a result of foreign exchange gains/losses on translation of Swiss franc- denominated receivable and monetary liabilities.

ii) Commodity price risk

The Company is exposed to commodity price risk to the extent that it sells its entitlement to petroleum on a floating price basis. The Company may consider partly mitigating this risk in the future.

The table below summarises the impact of increases/decreases of the relevant oil benchmark on the Company's loss for the year. The analysis is based on the assumption that commodity prices had increased/decreased by 5% with all other variables held constant:

Year ended 31 December
2011
$'000
2010
$'000
Brent light crude 697 120
697 120

The loss from continuing operations for the year would increase/ decrease as a result of commodity revenues received.

iii) Interest rate risk

The Group had fixed rate convertible bonds in the years under review, therefore it was not exposed to interest rate risk with respect to this fixed rate borrowing. In January 2005, a wholly owned subsidiary of the Company received a sterling denominated loan of £4.5 million to refinance the acquisition of a corporate office. Interest on the loan is variable at a rate of Bank of Scotland base rate plus 1.4% (note 16). In October 2007, a wholly owned subsidiary of the Company received a long-term loan of $9.45 million with a variable rate of LIBOR plus 1.6% (note 16). An increase/decrease of LIBOR by 1% would result in an increase/decrease of the Company's loss from continuing operations for the year by $58,000 (31 December 2010 - $144,000).

iv) Credit risk

All of the Company's production in 2010 and 2011 was derived from Russia. In 2011 sales were to a maximum of eight (2010 - nine) customers.

Trade debtors of the Company are subject to internal credit review to minimise the risk of non-payment. The Company does not anticipate any default as it transacts with creditworthy counterparties. No credit limits were exceeded during the reporting years and management does not expect any losses from non-performance by these counterparties.

The Company is also exposed to credit risk in relation to regular joint venture billings which are typically outstanding for one month and in relation to its cash balances held with reputable banks.

v) Liquidity risk

Liquidity risk is the risk that the Group will not have sufficient funds to meet liabilities. Cash forecasts identifying liquidity requirements of the Group are produced quarterly. These are reviewed regularly to ensure sufficient funds exist to finance the Company's current operational and investment cash flow requirements.

Management monitors rolling forecasts of the Company's cash position on the basis of expected cash flow.

The Group had available cash of $311 million at 31 December 2011. Based on its current plans and knowledge, its projected capital expenditure and operating cash requirements, the Group has sufficient cash to finance its operations for more than 12 months from the date of this report.

The Company's financial liabilities consist of trade and other payables and borrowings. Trade and other payables are due within 12 months, and borrowings fall due as outlined in notes 15 and 16.

b) Capital risk management

The Company's objectives when managing capital are to safeguard the Company's ability to continue as a going concern in order to provide returns for shareholders, benefits for other stakeholders and to maintain an optimal capital structure to reduce the cost of capital. Capital consists of share capital and retained earnings and reserves.

The Company monitors capital on the basis of the gearing ratio. This ratio is calculated as net debt divided by total capital. Net debt is calculated as total borrowings (including 'borrowings', 'trade and other payables', 'current tax liabilities', 'deferred tax'" and 'provisions' as shown in the consolidated balance sheet) less cash and cash equivalents. Total capital is calculated as 'equity' as shown in the consolidated balance sheet plus net debt.

Year ended 31 December
2011
$'000
2010
$'000
Total borrowings 175,823 189,080
Less cash and cash equivalents (note 14) (310,882 ) (598,275 )
Net cash (135,059 ) (409,195 )
Total equity 936,204 1,122,825
Total capital 936,204 1,122,825
Gearing ratio 0 % 0 %

4 Critical Accounting Estimates, Assumptions and Judgements

In the process of applying the Company's accounting policies, which are described in note 2, management makes estimates and assumptions concerning the future. The resulting accounting estimates will, by definition, seldom equal the related actual results. The estimates and assumptions that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below.

a) Recoverability of E&E costs

Under the modified full cost method of accounting for E&E costs, certain costs are capitalised as intangible assets by reference to appropriate cost pools, and are assessed for impairment when circumstances suggest that the carrying amount may exceed its recoverable value.

Such circumstances include, but are not limited to:

i) the period for which the entity has the right to explore in the specific area has expired during the period, or will expire in the near future, and is not expected to be renewed;
ii) substantive expenditure on further exploration for, and evaluation of, mineral resources in the specific area is neither budgeted nor planned;
iii) exploration for, and evaluation of, mineral resources in the specific area have not led to the discovery of commercially viable quantities of mineral resources and the entity has decided to discontinue such activities in the specific area; and
iv) sufficient data exists to indicate that, although a development in the specific area is likely to proceed, the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or by sale.

This assessment involves judgement as to: (i) the likely future commerciality of the asset and when such commerciality should be determined; (ii) future revenues and costs pertaining to any wider cost pool with which the asset in question is associated; and (iii) the discount rate to be applied to such revenues and costs for the purpose of deriving a recoverable value. Note 10 discloses the carrying amounts of the Group's E&E assets. Consequently, major uncertainties affect the recoverability of these costs which is dependent on the Group achieving commercial production or the sale of the assets. Note 23 discloses contingencies relating to title risks. The Company assessed whether these risks are contingencies or indicators of impairment and concluded that they are contingencies. There are licences that are due for renewal in 2012. The Group is confident they will be renewed.

b) Reserve estimates

Estimates of recoverable quantities of proved and probable reserves include assumptions regarding commodity prices, exchange rates, discount rates, production and transportation costs for future cash flows. It also requires interpretation of complex and difficult geological and geophysical models in order to make an assessment of the size, shape, depth and quality of reservoirs and their anticipated recoveries. The economic, geological and technical factors used to estimate reserves may change from period to period. Changes in reported reserves can impact asset carrying values and the asset retirement obligation due to changes in expected future cash flows. Reserves are integral to the amount of depletion charged to the income statement and the calculation of inventory.

The level of estimated commercial reserves is also a key determinant in assessing whether the carrying value of any of the Group's development and production assets has been impaired.

c) Fair value of financial instruments

The Group's accounting policies and disclosures require the determination of the fair value of financial instruments. Fair values have been determined for measurement and/or disclosure purposes based on the following methods:

i) Non-derivative financial instruments

These comprise investments in equity and debt securities, trade and other receivables, cash and cash equivalents, loans and borrowings, current tax liabilities and trade and other payables. Non-derivative financial instruments are recognised initially at fair value plus, for instruments not at fair value through the income statement, any directly attributable transaction costs.

Fair value of investments in equity and debt securities is determined by reference to their quoted closing bid price at the reporting date.

Fair value of all other non-derivative financial instruments is calculated based on the present value of future principal and interest cash flows, discounted at the applicable market rate of interest at the reporting date.

ii) Derivatives

Derivatives are recognised initially at fair value; attributable transaction costs are recognised in the income statement when incurred. Subsequent to initial recognition, derivatives are measured at fair value. Embedded derivatives are separated from the host contract and accounted for separately if the economic characteristics and risks of the host contract and the embedded derivative are not closely related, a separate instrument with the same terms as the embedded derivative would meet the definition of a derivative, and the combined instrument is not measured at fair value through the income statement.

The fair value of derivative financial instruments is based on their listed market prices, if available. If a listed market price is not available, then fair value is estimated by discounting the difference between the contractual forward price and the current forward price for the residual maturity of the contract using a risk free interest rate (based on government bonds).

IFRS 7 requires the classification of fair value measurements using a fair value hierarchy that reflects the significance of the inputs used in making the assessments. The fair value hierarchy has the following levels:

  • Level 1: quoted prices (unadjusted) in active markets for identical assets or liabilities.
  • Level 2: inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly (i.e. as prices) or indirectly (i.e. derived from prices).
  • Level 3: inputs for the assets or liability are not based on observable market data (unobservable inputs).

5 Segment Information

The Group has a single class of business which is international exploration, development and production of petroleum oil and natural gas. The geographical areas are defined by the Company as operating segments in accordance with IFRS 8 Operating Segments. The Group operates in a number of geographical areas based on location of operations and assets, being Russia, the DRC (written off in 2010), Kurdistan, Pakistan, Tanzania, Malta, Mali, Uganda (discontinued) and Libya (entered in 2011). The Group's reporting segments comprise each separate geographical area in which it operates.

Year ended 31 December 2011
External
revenue
$'000
Segment
result
$'000
Total
assets
$'000
Total
liabilities
$'000
Capital
additions
$'000
Depreciation,
depletion and
amortisation
$'000
Russia 9,030 (2,641 ) 58,811 1,814 9,233 1,624
Kurdistan - - 203,113 16,311 54,405 -
Libya - (586 ) 20,176 20,176 -
Pakistan - - 4,820 - 460 -
Tanzania - (12,136 ) 15,251 271 3,271 -
Mali - - 17,871 - 14,859 -
Malta - - 20,091 58 6,346 -
Uganda - discontinued operations - (3,933 ) - - - -
Total for reportable segments 9,030 (19,296 ) 340,133 18,454 108,750 1,624
Corporate - (47,595 ) 771,894 157,369 335 1,006
Elimination of discontinued operations - 3,933 - - - -
Total from continuing operations 9,030 (62,958 ) 1,112,027 175,823 109,085 2,630
Year ended 31 December 2010
External
revenue
$'000
Segment
result
$'000
Total
assets
$'000
Total
Liabilities
$'000
Capital
additions
$'000
Depreciation,
depletion and
amortisation
$'000
Russia 5,015 (1,892 ) 52,534 1,343 4,878 1,306
DRC - (1,645 ) - - 57 -
Kurdistan - - 130,385 16,595 55,143 -
Pakistan - - 4,619 75 2,375 -
Tanzania - (8,890 ) 22,925 8,376 11,557 -
Mali - - 3,037 - 1,018 -
Malta - - 13,778 85 2,613 -
Uganda - discontinued operations - 1,267,211 - - 23,444 -
Total for reportable segments 5,015 1,254,784 227,278 26,474 101,085 1,306
Corporate - (31,799 ) 1,084,627 162,606 42,914 805
Elimination of discontinued operations - (1,267,211 ) - - (23,444 ) -
Total from continuing operations 5,015 (44,226 ) 1,311,905 189,080 120,555 2,111

The Group's 2011 revenue of $9,030,000 was from eight Russian based customers. Three (2010 - five) customers had purchases of more than 10% of revenue. The total revenue relating to these three (2010 - five) customers was $7,026,000 (2010 - $4,629,000). The remaining five customers account for revenue of $2,004,000 (2010 - $386,000).

There have been no changes to the basis of segmentation or the measurement basis for the segment result since 31 December 2010. In 2011, an impairment loss relating to Tanzania of $10,775,000 (2010 - $8,890,000), the DRC of nil (2010 - $1,645,000) and corporate of nil (2010 - $1,854,000) is included in segmental result.

6 Discontinued Operations

Uganda

On 18 December 2009, Heritage announced that it and its wholly owned subsidiary HOGL, had entered into a SPA, with Eni for the sale of the Ugandan Assets. On 17 January 2010, Tullow exercised its rights of pre-emption. The transaction was overwhelmingly approved by Heritage shareholders at the General Meeting on 25 January 2010.

On 27 July 2010, Heritage announced that HOGL had completed the disposal of the Ugandan Assets. Tullow paid cash of $1.45 billion, including $100 million from a contractual settlement, of which Heritage received and retained $1.045 billion.

The URA contends that income tax is due on the capital gain arising on the disposal and it raised assessments of $404,925,000 prior to completion of the disposal. Heritage's position, based on comprehensive advice from leading legal and tax experts in Uganda, the United Kingdom and North America, is that no tax should be payable in Uganda on the disposal of the Ugandan Assets.

On closing, Heritage deposited $121,477,500 with the URA, representing 30% of the disputed tax assessment of $404,925,000. $121,477,500 has been classified as a deposit in the balance sheet at 31 December 2011. A further $283,447,000 has been retained in escrow with Standard Chartered Bank in London, pursuant to an agreement between HOGL, Tullow and Standard Chartered Bank pending resolution between the Ugandan Government and HOGL of the tax dispute. Including accrued interest, an amount of $284,479,000 is classified as restricted cash in the balance sheet at 31 December 2011.

In August 2010, the URA issued a further income tax assessment of $30 million representing 30% of the additional contractual settlement amount of $100 million. HOGL has challenged the Ugandan tax assessments on the disposal of HOGL's entire interest in the Ugandan Assets.

In November 2011 and December 2011, the Tax Appeals Tribunal in Uganda dismissed HOGL's applications in relation to the two assessments amounting to $434,925,000. In December 2011 and January 2012, HOGL commenced appeals to the Ugandan High Court in relation to the rulings from the Tax Appeals Tribunal. The rulings from the Tax Appeals Tribunal in Uganda are part of a domestic process and are not final and determinative. HOGL has appealed the rulings, which it believes are fatally flawed in many respects, through the Ugandan court system commencing with the High Court and subsequently the Court of Appeal and Supreme Court if necessary.

As a result of the actions of the tax authorities in Uganda, HOGL and its advisers consider that it was compelled to take part in a Ugandan domestic process before a Tax Appeals Tribunal, notwithstanding HOGL's belief that arbitration, which is ongoing in London and detailed below, is the correct forum to settle such disputes, in view of the existence of valid and binding arbitration provisions in its PSAs with the Ugandan Government.

In May 2011, HOGL commenced international arbitration proceedings in London against the Ugandan Government. HOGL is seeking a decision requiring, among other things, the return or release of approximately $405 million, plus interest, in aggregate currently on deposit with the URA or in escrow with Standard Chartered Bank in London. Accordingly, the arbitration proceedings concern HOGL's claims that the Ugandan Government wrongfully or unreasonably withheld consent to the sale by HOGL of the rights under the PSAs for the Ugandan Assets, including by making this consent conditional upon the payment of a sum alleged to be a tax liability of HOGL. The arbitration proceedings are being held in London in accordance with the provisions of the PSAs in relation to the Ugandan Assets.

On 15 April 2011, Heritage and its wholly owned subsidiary HOGL received Particulars of Claim filed in the High Court of Justice in England by Tullow seeking $313,447,500 for alleged breach of contract as a result of HOGL's and Heritage's refusal to reimburse Tullow in relation to a payment made by Tullow of $313,447,500 on 7 April 2011 to the URA. Heritage and HOGL believe that the claim has no basis and are in the process of vigorously and robustly defending it. Heritage and HOGL have filed their Defence and Counterclaim against Tullow seeking instead the release to HOGL of the $283,447,000 plus interest currently being held in escrow with Standard Chartered Bank in London.

Although disputes of this nature are inherently uncertain, the Directors believe that the monies on deposit and held in escrow will ultimately be recovered by Heritage.

The results of the Ugandan operations have been classified as discontinued operations. (Loss)/gain on disposal of discontinued operations as at 31 December 2011 and 2010 is as follows:

Year ended 31 December
2011
$'000
2010
$'000
(Loss)/gain on disposal of discontinued operations (3,933 ) 1,267,211
(3,933 ) 1,267,211

The following table provides additional information with respect to the discontinued operations amounts included in the balance sheet at 26 July 2010.

26 July
2010
$'000
Assets
Non-current assets
Intangible exploration and evaluation assets 181,963
Property, plant and equipment 472
Total assets 182,435
Liabilities
Current liabilities
Trade and other payables 3,105
3,105
Non-current liabilities
Provisions 269
269
Total liabilities 3,374
Net assets 179,061

The profit on disposal of discontinued operations has been derived as follows:

Year ended
31 December 2010
$'000
Consideration received
Sales proceeds including contractual settlement 1,450,000
Working capital adjustments 13,636
Total disposal consideration 1,463,636
Add:
Revenue - transitional services agreement 1,489
Less:
Carrying amount of net assets sold (179,061 )
Other expenses (17,421 )
Expenses - transitional services agreement (1,432 )
Gain on disposal of discontinued operations 1,267,211
Year ended
31 December 2010
$'000
Cash flow from (used in) discontinued operations:
Net cash used in operating activities (300 )
Net cash from investing activities 1,005,788
Net cash flows from discontinued operations 1,005,488

In March 2011, Tullow paid working capital adjustments with respect to the Ugandan Assets of $13.6 million.

7 Other Finance Costs

Year ended 31 December
2011
$'000
2010
$'000
Interest on long-term debt 261 303
Interest on convertible bonds 10,168 10,168
Accretion of convertible debt 6,006 5,255
Accretion of asset retirement obligation 50 45
16,485 15,771
Amount capitalised (12,804 ) (12,801 )
Finance costs expensed 3,681 2,970

Finance costs are capitalised in various balance sheet categories.

8 Income Tax Expense

Recognised in the income statement:

Year ended 31 December
2011
$'000
2010
$'000
Current tax expense 114 197
Deferred tax expense 38 -
Total tax expense 152 197

Current tax expense relates to the profit on operations of the Group's UK subsidiary.

The Group did not recognise any income tax in other comprehensive income or directly in equity. The Group is subject to income taxes in certain territories in which it owns licences or has taxable operations. All of the Group's operating activities are outside of Jersey. In the UK, the tax rate applicable to the Group's operations is 26% (2010 - 28%). It is the UK government's intention to enact legislation which will reduce the main rate of UK corporation tax to 23% by 2014.

The Group has available tax deductions of $17,210,000 (31 December 2010 - $17,607,000) and tax losses of $105,374,000 (31 December 2010 - $140,376,000), of which $105,374,000 expires from 2012 to 2031, and the remaining $nil (31 December 2010 - $36,711,000) does not have an expiry period. No deferred tax assets have been recognised for the benefit of tax deductions and tax losses because realisation of the deferred tax assets in the foreseeable future is not sufficiently likely.

Factors affecting the current tax charge for the year:

Year ended 31 December
2011
$'000
2010
$'000
(Loss)/profit for the year (66,739 ) 1,223,182
Standard tax rate 0 % 0 %
Tax on (loss)/profit at standard rate - -
Effect of higher tax rates in foreign jurisdiction (3,493 ) (5,242 )
Effective weighted average tax rate 5.23 % 0.43 %
Change in statutory tax rate 158 372
Expenses not deductible for tax purposes 13,047 1,265
Foreign exchange gains 893 1,675
Effect of tax losses not recognised (10,453 ) 2,127
Tax charge 152 197
2011
$'000
2010
$'000
The balance comprises temporary differences attributable to:
Available tax losses and deductions 22,828 33,281
Deferred tax asset (unrecognised) 22,828 33,281

The tax rate applied in respect of foreign jurisdictions is the local tax rate applicable to the nature of the profits arising.

Recognised deferred tax liability

Deferred tax liabilities attributable to the following:

Year ended 31 December
2011
$'000
2010
$'000
Property, plant and equipment 38 -
38 -

9 Staff Costs

The average number of employees (including Directors) and consultants employed/contracted by the Group during the year, analysed by category, was:

Year ended 31 December
2011 2010
Jersey 4 4
Canada 5 5
Russia 42 40
Europe 24 27
Uganda 1 31
Kurdistan 27 20
Pakistan 16 17
Tanzania 13 11
Mali 1 1
South Africa 2 7
Libya 4 -
Total 139 163

The aggregate payroll expenses of those employees (including Executive Directors) and consultants was as follows:

Year ended 31 December
2011
$'000
2010
$'000
Salaries and other short-term benefits 19,076 30,117
Share-based compensation 3,597 4,256
Total employee remuneration 22,673 34,373
Capitalised portion of total remuneration 13,441 15,733

Key management compensation was:

Year ended 31 December
2011
$'000
2010
$'000
Salaries and other short-term benefits 4,689 8,291
Share-based compensation 2,276 2,988
6,965 11,279

See note 22 'Related Party Transactions' for disclosures relating to an arbitration settlement with a former director of HOC.

10 Intangible Exploration and Evaluation Assets

31 December
2011
$'000
2010
$'000
At 1 January 183,424 121,278
Effect of movement in exchange differences (307 ) (83 )
Additions 99,517 72,764
Impairment loss (10,775 ) (10,535 )
At 31 December 271,859 183,424

No assets have been pledged as security.

The balances at the end of the years are as follows:

31 December
2011
$'000
2010
$'000
Russia 10,844 11,151
Kurdistan 183,335 128,930
Pakistan 4,448 3,988
Malta 19,988 13,641
Mali 17,871 3,013
Tanzania 15,197 22,701
Libya 20,176 -
Balance - end of year 271,859 183,424

In many of the countries in which the Group operates, land title systems are not developed to the extent found in many industrial countries and there may be no concept of registered title. The risk of title disputes associated with Kurdistan and Malta is described in note 23.

On 25 August 2011, the Group acquired 15,300,000 shares, representing 51% of the shares and voting interests, in Sahara Oil, a company wholly owning Sahara for $19.5 million. Sahara has the rights to own and operate oil and gas licences in Libya. This acquisition was accounted as an intangible exploration and evaluation asset. The Group agreed to pay the vendors additional consideration of $5 million becoming due on signing of an oil service contract.

In 2011, the Group recognised an impairment of intangible exploration and evaluation assets of $10,775,000 (2010 - $10,535,000). After a technical review management decided to write-off expenditure of $10,775,000 incurred with respect to the Kimbiji licence area in Tanzania. An impairment recognised in 2010 is comprised of two elements. Firstly, following changes in future plans management decided to write-off expenditure of $1,645,000 incurred with respect to interests in Block 1 and 2 in the DRC. Secondly, after a technical review management decided to write-off expenditure of $8,890,000 incurred with respect to the Kisangire and Lukuliro licence areas in Tanzania.

11 Property, Plant and Equipment

Petroleum and
natural gas
interests
$'000
Drilling
and barge
equipment
$'000
Land and
buildings
$'000
Aircraft
$'000
Other
$'000
Total
$'000
Cost
At 1 January 2010 42,995 3,545 11,985 12,639 3,317 74,481
Additions 4,878 - - 42,850 63 47,791
Disposals - - - - (60 ) (60 )
Effect of movements in exchange rates (128 ) - - - - (128 )
At 31 December 2010 47,745 3,545 11,985 55,489 3,320 122,084
Additions 9,233 - - - 335 9,568
Disposals - - - - (185 ) (185 )
Effect of movements in exchange rates (2,054 ) - - - - (2,054 )
At 31 December 2011 54,924 3,545 11,985 55,489 3,470 129,413
Depletion, depreciation, amortisation and impairment losses
At 1 January 2010 (5,638 ) (2,898 ) (730 ) (4,637 ) (1,280 ) (15,183 )
Charge for the year (1,307 ) - - (401 ) (403 ) (2,111 )
Impairment losses - - - (1,854 ) - (1,854 )
Disposals - - - - (943 ) (943 )
At 31 December 2010 (6,945 ) (2,898 ) (730 ) (6,892 ) (2,626 ) (20,091 )
Charge for the year (1,624 ) - (138 ) (553 ) (315 ) (2,630 )
Disposals - - - - 160 160
At 31 December 2011 (8,569 ) (2,898 ) (868 ) (7,445 ) (2,781 ) (22,561 )
Net book value:
At 31 December 2010 40,800 647 11,255 48,597 694 101,993
At 31 December 2011 46,355 647 11,117 48,044 689 106,852

The corporate office, which represents the land and building category, and an aircraft serve as security for long-term loans (note 16).

In 2010, the carrying value of an aircraft was written down to the fair value less cost to sale of $5.9 million because of a reduction in fair value of an aircraft due to unfavourable economic conditions. This resulted in an impairment write down of $1.9 million recognised in the income statement in 2010.

12 Other Financial Assets

31 December
2011
$'000
2010
$'000
Investment in warrants - 2,050
Investment in listed securities 13,268 -
13,268 2,050

The investment in Afren warrants was classified as held for trading at 31 December 2010. The estimate of the fair value of the warrants is determined using the Black-Scholes model and relevant market inputs. The fair value measurement of investment in warrants was categorised as Level 2. Loss on revaluation of Afren warrants of $1,550,000 was recognised in the income statement in 2011.

On 4 November 2011, the Afren warrants were exercised and the Company acquired 1,500,000 of the listed shares in Afren. The investment in Afren shares is classified as available-for-sale and valued at fair value which is determined using market price at the end of the period. The valuation at market price at 31 December 2011 resulted in a gain of $120,000 which was recognised in equity.

As at 31 December 2011, the Company had acquired 9,748,200 of the listed shares of PetroFrontier representing 15.25% of the shares of PetroFrontier. The investment in share capital of PetroFrontier is classified as available-for-sale and valued at fair value which is determined using market price at the end of the period.

The Group recorded an impairment of its investment in PetroFrontier to reflect the market value as at 31 December 2011. The loss of $18,885,000 recognised in the available-for-sale reserve for this investment has been reclassified to the income statement.

13 Trade and Other Receivables

31 December
2011
$'000
2010
$'000
Trade receivables 189 8
Receivable from the acquirer of the Ugandan Assets on completion of the disposition (note 6) - 13,636
Other receivables 1,599 6,596
1,788 20,240

Trade receivables are due within 30 days from the invoice date. Joint ventures billings are typically paid within 30 days from the invoice date. Interest is not normally charged on the receivables. The carrying amount of trade and other receivables approximates to their fair value.

The maximum exposure to credit risk at the reporting date is the fair value of each class of receivable.

As of 31 December 2011, trade and other receivables of $1,788,000 (31 December 2010 - $20,240,000) were neither past due nor impaired. Trade and other receivables relate to a number of independent customers and joint ventures partners for whom there is no recent history of default. The ageing analysis of these trade and other receivables is as follows:

31 December
2011
$'000
2010
$'000
Up to 3 months 805 19,431
3 to 6 months 772 365
6 to 12 months 104 444
Over 12 months 107 -
1,788 20,240

Trade and other receivables analysed by currency are as follows:

31 December
2011
$'000
2010
$'000
US dollars 933 19,943
Russian roubles 100 93
Swiss francs 452 30
Canadian dollars 34 19
GB pounds sterling 248 124
Euros 21 31
1,788 20,240

14 Cash and Cash Equivalents

31 December
2011
$'000
2010
$'000
Cash at bank and in hand 310,882 598,275

Cash at bank and in hand includes cash held in interest-bearing accounts.

15 Trade and Other Payables Due Within One Year

31 December
2011
$
2010
$
Trade payables 14,986 19,525
Withholding tax accrual - 8,271
Other payables and accrued liabilities 20,405 26,287
35,391 54,083

Trade and other payables and accrued liabilities comprise current amounts outstanding for trade purchases and ongoing costs. The carrying amount of trade and other payables approximates to their fair value.

16 Borrowings

31 December
2011
$'000
2010
$'000
Non-current borrowings
Convertible bonds - unsecured - 120,468
Non-current portion of long-term debt - secured 5,110 13,047
5,110 133,515
Current borrowings
Convertible bonds - unsecured 126,406 -
Current portion of long-term debt - secured 7,991 896
134,397 896

2007 convertible bonds

On 16 February 2007, the Company raised $165 million by completing the private placement of convertible bonds. Issue costs amounted to $6,979,000 resulting in net proceeds of $158,021,000. HOC issued 1,650 $100,000 unsecured convertible bonds at par, which have a maturity of five years and one day and an annual coupon of 8% payable semi-annually on 17 August and 17 February of each year. Bondholders had the right to convert the Bonds into Ordinary Shares at a price of $4.70 per share at any time. The number of Ordinary Shares receivable on conversion of the Bonds is fixed. The Company had the right to redeem, in whole or part, the Bonds for cash at any time on or before 16 February 2008, at 150% of par value. This right was not exercised.

The fair value of the host liability component of the Bonds (net of issue costs) was estimated at $140,154,000 on 16 February 2007. The difference between the $165 million due on maturity and the initial liability component is accreted using the effective interest rate method and is recorded as finance costs. As the Company call option meant that conversion feature could be settled in cash in accordance with IAS 32 the conversion was treated as a derivative liability. The fair value of this derivative liability (estimated using the Black-Scholes option pricing model) was $17,867,000 at 16 February 2007 and subsequent gains and losses were recorded in finance income and costs up to the expiry of the Company call option on 17 February 2008. As a result of the expiry of this option, and hence the cash settlement feature, the Company has reassessed the classification of the conversion option and determined that it qualifies to be treated as equity under IAS 32, being an option to convert a fixed amount of cash for a fixed number of shares. Therefore, the fair value of the conversion option was reclassified to equity at that date.

Bondholders had a put option requiring the Company to redeem the Bonds at par, plus accrued interest, in the event of a change of control of the Company or revocation or surrender of the Zapadno Chumpasskoye licence in Russia (the "contingent put option"). In the event of a change of control and redemption of the Bonds or exercise of the conversion rights, a cash payment of up to $19,700 on each Bond will be made to a Bondholder, the amount of which depends upon the date of redemption and market value of shares at the date of any change of control event. The contingent put option has been valued separately. The fair value of the contingent put option was estimated de minimis by the Company at 31 December 2011 (31 December 2010 - de minimis). The fair value measurement of the contingent put option is categorised as Level 2.

On 18 December 2009, the Company announced it had entered into a SPA for the sale of the Ugandan Assets (note 6). The Company also announced that it would consider returning a portion of the disposal proceeds to shareholders through a special dividend on completion of the proposed transaction. Under the terms and conditions of the Bonds, the Company was restricted from making or declaring a dividend or making any other distributions to its shareholders which constitutes on a consolidated basis more than 30% of its earnings for the immediately preceding financial year.

In December 2009, the Company approached Bondholders with the proposal to agree to remove this restriction and to make some other changes in the terms and conditions of the Bonds. In consideration the Company proposed to pay to those Bondholders who vote on the proposal the sum of $2,000.00 per $100,000 of Bonds held by such Bondholders. The majority of the Bondholders voted in favour of this proposal at a meeting on 31 December 2009 and the restriction of making or declaring a dividend or making any other distributions to shareholders has been removed. On 15 January 2010, the Company paid $2,378,000 to the Bondholders who voted. In accordance with IAS 39, this amendment to the terms and conditions of the Bonds does not constitute a redemption and therefore this amount was offset against the convertible bonds liability and will be recognised in the income statement over the period of the borrowings using the effective interest method.

Convertible bonds mature within a period less than one year from 31 December 2011 and therefore have been reclassified as current liabilities at 31 December 2011. Convertible bonds were repaid in full in February 2012.

Long-term debt

In January 2005, a wholly owned subsidiary of the Company received a sterling denominated loan of £4.5 million to refinance the acquisition of a corporate office. Interest on the loan was fixed at 6.515% for the first five years and is now variable at a rate of Bank of Scotland base rate plus 1.4%. The loan, which is secured on the property, is scheduled to be repaid by 240 instalments of capital and interest at monthly intervals, subject to a residual debt at the end of the term of the loan of $3.5 million (£1.86 million). The principal balance outstanding as at 31 December 2011 was $5,590,000 (£3.6 million) (31 December 2010 - $6,030,000 (£3.9 million)).

In October 2007, a wholly owned subsidiary of the Company received a loan of $9.45 million to refinance the acquisition of an aircraft. Interest on the loan is variable at a rate of LIBOR plus 1.6%. The loan, which is secured on the aircraft, is scheduled to be repaid by 19 consecutive quarterly instalments of principal. Each instalment equals $118,000 with the final instalment being $7,218,000. The Corporation provided a corporate guarantee to the lender. The additional security of $2,454,000 was paid to the bank on 19 January 2010 to maintain the loan to value ratio specified in the loan agreement.

Fair values

At 31 December 2011, the fair values of borrowings were approximately $126.4 million (31 December 2010 - $120.5 million) for the convertible bonds, $nil million (31 December 2010 - $71.1 million) for the equity/convertible element of the convertible bonds and $13.1 million (31 December 2010 - $13.9 million) for the long-term debt.

17 Provisions

The Group's asset retirement obligation results from net ownership interests in petroleum and natural gas assets including well sites and gathering systems. The Group estimates the total undiscounted inflation adjusted amount of cash flows required to settle its asset retirement obligation to be approximately $1,239,000, which is expected to be incurred in the period between 2012 and 2024. A cost pool specific discount rate related to the liability of 9% was used to calculate the fair value of the asset retirement obligation in Russia (2010 - 9%) and 10% was used in Kurdistan in 2011 (2010 - 10%).

A reconciliation of the asset retirement obligation is provided below:

31 December
2011
$'000
At 1 January 389
Additions 344
Accretion expense (note 7) 50
At 31 December 783

18 Share Capital

The Company was incorporated under the Jersey Companies Law on 6 February 2008. The Company's authorised share capital is an unlimited number of Ordinary Shares without par value. At incorporation, there was one Ordinary Share issued at $42. On 22 February 2008, a second Ordinary Share was issued at $41.

As part of the Reorganisation described in the 2008 Annual Report and Accounts, the rights of different classes of shares are the same and therefore economically equivalent. As such, Ordinary and Exchangeable Shares were treated as one class of shares for the net earnings/(loss) per share calculation.

Ordinary Shares

Year ended
31 December 2011
Year ended
31 December 2010
Number Amount
$'000
Number Amount
$'000
At 1 January 284,899,830 457,746 284,842,830 457,697
Exchange of Exchangeable Shares for Ordinary Shares 155,700 132 57,000 49
Issued on exercise of share options (note 21) 4,692,500 8,977 - -
Shares bought back and held in treasury (33,228,734 ) (123,575 ) - -
At 31 December 256,519,296 343,280 284,899,830 457,746

Special Voting Share

Year ended
31 December 2011
Year ended
31 December 2010
Number Amount
$'000
Number Amount
$'000
At 1 January 1 - 1 -
Issued during the year - - - -
At 31 December 1 - 1 -

Exchangeable Shares of HOC each carrying one voting right in the Company

Year ended
31 December 2011
Year ended
31 December 2010
Number Amount
$'000
Number Amount
$'000
At 1 January 2,967,108 2,534 3,024,108 2,583
Exchange of Exchangeable Shares for Ordinary Shares (155,700 ) (132 ) (57,000 ) (49 )
At 31 December 2,811,408 2,402 2,967,108 2,534
Balance of Ordinary Shares of the Company, excluding treasury shares, and Exchangeable Shares of HOC at 31 December 259,330,704 345,682 287,866,938 460,280

On 26 April 2011, the Company announced a buy back programme to acquire Ordinary Shares. Shareholders approved the resolution at the AGMs on 17 June 2010 and 20 June 2011 to acquire up to 28,786,693 and 28,900,000 Ordinary Shares respectively from the date of the AGM until the next AGM. Purchased Ordinary Shares are held in treasury. At 31 December 2011, the Company held 33,228,734 Ordinary Shares in treasury.

2010 Special dividend

On 2 August 2010, Heritage announced the declaration of a special dividend of 100 pence per Ordinary Share of the Company and HOC, the Company's wholly owned subsidiary, also announced the declaration of a special dividend of Cdn$1.62 per Exchangeable Share of HOC, calculated at an exchange rate of £1.00:Cdn$1.62. The special dividend was paid on 27 August 2010.

The special dividend resulted in a payment to Bondholders. As disclosed in the announcement of 31 December 2009, certain amendments to the terms of the Bonds were approved by Bondholders. Pursuant to such amendments, no adjustments will be made to the Conversion Rights in respect of any dividend paid or made by the Company; instead, the Company agreed to pay the holder of each Bond outstanding on the record date for such dividend a Pass-through Dividend which is equal to the dividend which would be received by the holder of a number of Ordinary Shares equal to the number of Ordinary Shares to which the Bondholder would have been entitled if it had exercised its Conversion Rights on the record date of 13 August 2010.

The aggregate principal amount of Bonds outstanding on the record date was $127,100,000. These Bonds were convertible into 27,043,000 Ordinary Shares pursuant to the Conversion Rights and accordingly the Company paid to Bondholders a Pass-through Dividend of £27,043,000 on 27 August 2010.

19 Reserves

a) Available-for-sale investments revaluation reserve

Changes in the fair value and exchange differences arising on translation of available-for-sale investments such as equities, classified as available-for-sale financial assets, are taken to the available-for-sale investments revaluation reserve (note 2j). Amounts are recognised in the income statement when the associated assets are sold or impaired.

b) Foreign currency translation reserve

Exchange differences arising on translation of a foreign controlled entity are included in the foreign currency translation reserve (note 2r). The reserve will be recognised in the income statement when the net investment is sold.

c) Share-based payments reserve

The share-based payments reserve (note 2s), is used to recognise the fair value of options and LTIP awards issued, but not exercised, to employees.

d) Equity portion of convertible debt

The fair value of the conversion feature of convertible bonds is classified as the equity portion of convertible debt which is included in reserves in the balance sheet.

20 (Loss)/Earnings Per Share

The following table summarises the weighted average Ordinary and Exchangeable Shares used in calculating net earnings per share:

Year ended 31 December
2011 2010
Weighted average Ordinary and Exchangeable Shares
Basic 269,676,216 287,866,938
Diluted 284,594,888 331,012,512

The reconciling item between basic and diluted weighted average number of Ordinary Shares is the dilutive effect of share options, LTIP awards and convertible bonds. A total of nil options (31 December 2010 - nil), nil shares relating to the LTIP (31 December 2010 - nil) and 27,042,553 shares relating to the convertible bonds (31 December 2010 - nil) were excluded from the above calculation, as they were anti-dilutive. However, since the Company has made a loss in 2011 for the purposes of calculating diluted loss per share, all potential Ordinary Shares have been treated as anti-dilutive in that year. In calculating the 2010 loss per share from continuing operations 27,042,553 of shares relating to the convertible bonds were excluded from the above calculation, as they were anti-dilutive.

21 Share-Based Payments

Share options

The Company had a share option plan whereby certain Directors, officers, employees and consultants of the Group have been granted options to purchase Ordinary Shares. Under the terms of the plan, options granted normally vest one third immediately and one third in each of the years following the date granted and have a life of five years.

Ordinary Share options outstanding and exercisable:

Year ended
31 December 2011
Year ended
31 December 2010
Number
of options
Average
exercise price
(GBP)
Number
of options
Average
exercise price
(GBP)
At 1 January 23,597,010 1.52 23,597,010 1.52
Exercised (note 18) (4,692,500 ) 1.13 - -
Balance - end of year 18,904,510 1.62 23,597,010 1.52
Exercisable - at 31 December 18,904,510 1.62 23,597,010 1.52
Number of options
Exercise price (GBP) Outstanding Exercisable Remaining
life (years)
£1.08-£1.43 15,454,510 15,454,510 -
£2.45-£2.51 3,450,000 3,450,000 0.92
18,904,510 18,904,510 0.17

Following the payment of a special dividend of 100 pence per share in August 2010 (see note 18), share options holders are entitled to receive £1 per share when an option is exercised. The net exercise price for the 2,150,000 options exercised was less than 100 pence per share, which resulted in net payment of $1,780,000 to the option holders on exercise of these share options during the period ended 31 December 2011.

Long Term Incentive Plan ("LTIP")

On 20 June 2011, the shareholders of the Company at the AGM approved the 2011 LTIP. Under the terms of the plan, the LTIP awards will be in the form of full-value shares, subject to three year performance conditions agreed by the Remuneration Committee when the award is made. At the end of the three year performance period, to the extent that awards vest, there is an additional holding period of one year. Eligible employees will normally be considered by the Remuneration Committee for an award once each year.

Awards made in 2011 are subject to relative Total Shareholder Return ("TSR") performance conditions. The awards will vest in line with the following schedule:

Percentage of award vesting
Upper quartile 100% of the award
Between median and upper quartile 25% - 100% on a straight line basis
Median 25 %
Below median 0 %

TSR will be measured in comparison to a peer group of 18 international oil companies selected based on one of or a combination of size (market capitalisation, revenue, turnover, cash expenditure or a combination thereof), area of operations and country of domicile. The TSR measurement will be conducted by independent consultants in discussion with the Remuneration Committee.

Since there are market-related conditions the awards of shares under LTIP were fair valued using the Monte Carlo model which takes into account the market-based performance conditions which effectively estimate the number of shares expected to vest. The expected volatility was assessed based on the historic volatility of the Company's TSR and volatility of the TSR of each company within the comparator group. No subsequent adjustment is made to the fair value charge for shares that do not vest in the event that these performance conditions are not met. Adjustments are, however, made for leavers. The fair value of the awards is recognised as an employee expense with the corresponding increase in equity. The total amount to be expensed is spread over the vesting period during which the employees become unconditionally entitled to the shares and options.

The table below summarises the main assumptions used to fair value the awards made under the above LTIP and the fair values of the shares granted.

Award date 20 June 2011
Vesting period 3 years
Exercise price Nil
Share price at date of grant £2.128
Expected volatility 55 %
Risk free interest 1.3 %
Fair value as at grant date £1.630
Number of shares granted 2,834,367

The 2008 Long Term Incentive Plan (Performance Share Plan) (the"2008 LTIP") was approved by Shareholders at the AGM on 19 June 2008. The 2008 LTIP compared the Company's TSR over a three year period ended 19 June 2011 against a comparator group of 18 international oil companies. The 2008 LTIP comprised of two plans, one for members of staff and another for the Executive Directors. The plan for the Executive Directors included an additional share price performance condition over-and-above the Company's relative TSR performance.

Independent executive reward consultants, Hay Group, compared the Company's TSR against the comparator group during this three year period. It was found that while Heritage exceeded the TSR performance measure, the additional 2008 LTIP performance conditions for the Executive Directors were not met and so none of their awards over 3,507,246 shares vest. While performance conditions for the staff plan were achieved with the result that all of the awards of 1,419,187 shares could have vested in accordance with the plan. Participants have agreed (due to a range of contributing factors) to forego 25% of their potential awards in accordance with the 2008 LTIP rules. As a result, awards over a total of only 1,064,372 shares will vest. The Remuneration Committee also approved of such a reduction in accordance with the 2008 LTIP rules.

Pursuant to the waiver of the application of Rule 9 of the City Code approved by shareholders at the last AGM, the Remuneration Committee agreed with Anthony Buckingham, the Company's CEO, to issue his 2011 LTIP awards under the 2008 LTIP, however, Anthony Buckingham's awards fully reflect the terms and conditions of all the other 2011 LTIP awards.

The share-based payment recognised with respect to share options and LTIP awards previously granted, in the year ended 31 December 2011 was $3,675,000 (31 December 2010 - $4,255,000) out of which $1,114,000 (31 December 2010 - $1,086,000) was capitalised.

22 Related Party Transactions

During the year ended 31 December 2011, the Company incurred transportation costs of $245,000 (31 December 2010 - $93,000) with respect to the services provided by a company indirectly owned by Anthony Buckingham, CEO and a Director of the Company.

Anthony Buckingham used the corporate jet a few times during 2011 for personal trips. The cost of these trips was reimbursed at independently assessed commercial rates of $306,000 (31 December 2010 - $133,000).

Related party transactions described above have been made on an arm's length basis.

In 2010, the Company accrued $7.7 million in general and administrative expenses, in relation to an arbitration settlement to a former director of HOC whose services were terminated in 2006. Further arbitration proceedings have been initiated by this individual.

23 Commitments and Contingencies

Heritage's net share of outstanding contractual commitments at 31 December 2011 was estimated at:

Total
$'000
Less
than
1 year
$'000
1-3
years
$'000
4-5
years
$'000
After
5 years
$'000
Long-term debt, including interest 14,074 8,202 961 961 3,950
Convertible bonds, including interest 132,184 132,184 - - -
146,258 140,386 961 961 3,950
Effect of interest (5,998 ) (5,339 ) (186 ) (157 ) (316 )
Total repayments of borrowings 140,260 135,047 775 804 3,634
Operating leases 6,902 518 649 649 5,086
Work programme obligations(1) 82,246 26,926 55,320 - -
Total contractual obligations 89, 148 27,444 55,969 649 5,086
(1) Work programme obligation includes minimum required financial commitments for the Group to fulfil the requirements of licences and production sharing contracts.

Of the total contractual obligations of $89,148,000, $39,812,000 relates to the Company's share of obligations for its joint arrangements.

The Company may have a potential residual obligation to satisfy any shortfall in officers' and former officers' secured real estate borrowings in the event of default, a shortfall on the proceeds from the disposal of the properties and the individuals being unable to repay the balance. The value of the residual obligation was estimated as insignificant.

In many of the countries in which the Group operates, land title systems are not developed to the extent found in many industrial countries and there may be no concept of registered title. Although the Group believes that it has title to its oil and gas properties, it cannot control or completely protect itself against the risk of title disputes or challenges. There can be no assurance that claims or challenges by third parties against the Group's properties will not be asserted at a future date.

The Group received a letter from the Iraq Ministry of Oil dated 17 December 2007 stating that the PSC signed with the KRG without the prior approval of the Iraqi government is considered to be void by the Iraqi government as they have stated it violates the 'prevailing Iraqi law'. The Directors believe that the PSC is valid and effective pursuant to the applicable laws.

The Group received a letter from the Chairman of the Management Committee of the National Oil Company of Libya dated 28 February 2008 stating that the Block 7 licence area lies within the Libyan continental shelf and a portion of this area has already been licensed to Sirte Oil Company. This letter also demands that the Group refrain from any activities over, or concerning, the Block 7 licence area and asserts the Libyan government's right to invoke Libyan and international law to protect its rights in the Block 7 licence area. The Directors believe that the Libyan government's claims are unfounded.

24 Non-Cash Investing and Financing Activities Supplementary Information

Year ended 31 December
2011
$'000
2010
$'000
Capitalised portion of share-based compensation (1,114 ) (1,086 )
Capitalised portion of interest (12,804 ) (12,801 )
Non-cash property, plant and equipment additions relating to the capitalised portion of share-based compensation 13,918 13,887

FORWARD-LOOKING INFORMATION:

Except for statements of historical fact, all statements in this news release - including, without limitation, statements regarding production estimates and future plans and objectives of Heritage - constitute forward-looking information that involve various risks and uncertainties. There can be no assurance that such statements will prove to be accurate; actual results and future events could differ materially from those anticipated in such statements. Factors that could cause actual results to differ materially from anticipated results include risks and uncertainties such as: risks relating to estimates of reserves and recoveries; production and operating cost assumptions; development risks and costs; the risk of commodity price fluctuations; political and regulatory risks; and other risks and uncertainties as disclosed under the heading "Risk Factors" in its Prospectus and elsewhere in Heritage documents filed from time-to-time with the London Stock Exchange and other regulatory authorities. Further, any forward-looking information is made only as of a certain date and the Company undertakes no obligation to update any forward-looking information or statements to reflect events or circumstances after the date on which such statement is made or reflect the occurrence of unanticipated events, except as may be required by applicable securities laws. New factors emerge from time to time, and it is not possible for management of the Company to predict all of these factors and to assess in advance the impact of each such factor on the Company's business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking information.

Contact Information