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Heritage Oil Limited is an independent oil and gas production and exploration company with a primary listing on the Main Market of the London Stock Exchange (symbol HOIL) and an Exchangeable Share listed on the Toronto Stock Exchange (symbol HOC) and London Stock Exchange (HOX). The Company currently focuses on operations in Africa, the Middle East and Russia.

Overview01 Highlights02 Chairman’s Statement04 Chief Executive’s Review 08 Q&A10 Operations Review 10 Uganda 12 Kurdistan Region of Iraq 14 Russia 16 Oman 18 Democratic Republic of Congo 20 Malta 22 Mali 24 Pakistan 26 Tanzania

Financial Review28 Creating value

Corporate Social Responsibility34 Committed to our Communities

Board of Directors36 Directors and Senior Management

List of Advisers38 Advisers

Corporate Governance39 Corporate Governance Report44 Remuneration Report48 Directors’ Report52 Auditors’ Report to

the Shareholders

Financial Statements53 Consolidated Balance Sheets54 Consolidated Income Statements55 Consolidated Statements of

Recognised Income and Expense56 Consolidated Cash Flow

Statements57 Notes to Consolidated

Financial Statements93 Glossary of Technical Terms

FORWARD-LOOKING INFORMATIONExcept for statements of historical fact, all statements in this document – including, without limitation, statements regarding production estimates and future plans and objectives of Heritage and the Group – are forward-looking statements 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 the Prospectus and elsewhere in the Group’s documents filed from time-to-time with the London Stock Exchange and other regulatory authorities. Further, any forward-looking statement is made only as of a certain date and the Company undertakes no obligation to update any forward-looking statement 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 statement.

Heritage Oil LimitedAnnual Report & Accounts 2007

Head Office and Directors’ Business Address:28-30 The Parade, St Helier, Jersey, JE1 1BG, Channel Islands

Tel +44 1534 873000Fax +44 1534 873344

Principal Canadian Office:260 Petex Building, 600 - 6 Ave SWCalgary, Alberta, T2P 0S5 Canada

Tel: +1 403 234 9974Fax: +1 403 261 1941

www.heritageoilltd.com

I R A Q

Mosul

Baghdad

Basrah

Kirkuk

Erbil

Suleimaniah

RUSSIA

ChumpasskoyeWestern Siberia

S I C I LY

T U N I S I A

L I B Y A

M A L T AValetta

Siracusa(Syracuse)Tunis

Tarãbulus (Tripoli)

Area 7

Area 2

Bamako

MALI

Block 7

Block 11

KabulIslamabad

New Delhi

Dushanbe

Sanjawi

PAKISTAN

OMAN

Ras AlKhaimah

DubaiU.A.E.

IRAN

Block 8

BLOCK 3AHeritage

BLOCK 1

UGANDA

Dodoma

KENYA

ZAMBIA

MOZAMBIQUE

TANZANIAKimbiji

Latham

Lukoliro

Kisangire

D. R. C.

BLOCK IIHeritage

BLOCK I

RussiaThe Zapadno Chumpasskoye licence is located in the West Siberian province of Khanty-Mansiysk. The approximately 200 square kilometres licence, which expires in September 2024, contains a field originally discovered in 1997. Twelve wells have been drilled in the licence, nine prior to the Group’s acquisition in 2005. Since commencement of production on 14 May 2007, production has averaged 331 bopd for the period ended 31 December 2007 and has since climbed to approximately 800 bopd. The field is located close to well-developed infrastructure.

Democratic Republic of Congo (DRC)DRC Blocks I and II, in the Albert Basin, adjacent to Ugandan Blocks 2 and 3A, are held under a single PSC, signed in July 2006, with the Government of DRC. The initial exploration term is five years, during which time seismic data will be acquired and exploration wells drilled. Work will commence following the receipt of a Presidential Decree. With the proximity of the DRC licences to the Uganda licences in the Albert Basin, there should be cost benefits from sharing certain operating, capital and infrastructure development costs, including the development and construction of a potential international export pipeline to Mombasa on the east coast of Kenya.

MaliThe Group 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, which includes seismic and one well over the next two years. The two licences are located within the Gao Graben. The Graben has been delineated by various surveys since the early 1970’s, including over 2,000 kilometres of 2D seismic and a comprehensive gravity and magnetic survey. Tilted fault-blocks have been identified along with the presence of some 4,000 metres of sediments in the geological section. Previous drilling in the Gao Graben has encountered oil and gas shows.

OmanBlock 8 is located offshore Oman and contains the Bukha field, which commenced production of gas, condensate and LPG in 1994, and the West Bukha field. Wet gas is produced in the Bukha field through an unmanned platform and channelled onshore via a 34 kilometre pipeline. Revenue is generated from selling both the condensate and LPG from the Bukha field. The West Bukha field is located approximately 20 kilometres from the Bukha field and straddles the Iranian border. Development of this field is progressing, with first production anticipated in the third quarter of 2008.

MaltaThe 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 in December 2007. The licences are situated approximately 80 kilometres (Block 2) and 140 kilometres (Block 7) from the south eastern Maltese coast in water depths of approximately 300 metres. Initial seismic interpretation, based on the current extensive data set of almost 3,500 kilometre acquired after 2000, has identified numerous potential prospects. The work programme will commence in 2008.

PakistanThe Group was awarded a 60% participating interest in the onshore Sanjawi Block (number 3068-2) in Zone II (Baluchistan), Pakistan in November 2007. This exploration licence has a gross area of 2,258 square kilometres. A number of oil seeps occur to the south of the licence, which is encouraging for the development of an oil play.

UgandaBlocks 1 and 3A are located in the Albert Basin in Uganda, straddling the border with the DRC. The Group has maintained interests in Uganda since 1997. Eight exploration and appraisal wells have been drilled successfully in the basin since the beginning of 2006 and all encountered oil bearing reservoirs, with two of the wells testing over 12,000 bopd. The Group’s Kingfisher-1 well in Block 3A spud in August 2006 and was drilled to a total depth of 3,195 metres, the limit of the rig’s operational capability. Four intervals were tested successfully in the Kingfisher-1 well, resulting in an overall cumulative flow rate of 13,893 bopd. Multi-well drilling programmes are scheduled, commencing with the Kingfisher-2 well in Block 3A which spud at the end of April 2008. The Group’s 50% working interest share of the mean risked resources from Blocks 3A and 1 in Uganda is estimated at 462 MMboe (gross 923 MMboe).

Kurdistan Region of IraqThe Group was one of the first companies to execute a PSC in the Kurdistan Region of Iraq with the award of the Miran licence in October 2007. The licence covers approximately 1,015 square kilometres and contains the large Miran structure which provides the possibility of multiple reservoir targets. The Miran structure lies within 55 kilometres of the giant Kirkuk oilfield, with remaining reserves estimated to be in excess of 10 billion bbls, and 30 kilometres from the Taq Taq field, on which recent wells have tested 44-50 degree API oil at flow rates of between 15,000 and 37,000 bopd. Seismic acquisition commenced in the second quarter of 2008 and the first high-impact well is planned for the second half of this year.

Where we operate

TanzaniaThe Group announced in April 2008 that it had signed documentation to farm-in to four exploration licences in Tanzania. The licences, known as the Kimbiji, Latham, Kisangire and LukoliroAreas, cover approximately 25,000 square kilometres and are held under two production sharing agreements. In order to earn the working interests, the Group will fund all seismic and drilling costs of the required work programmes during the initial exploration phases. An oil seep and recent gas discovery in a neighbouring concession area indicates the presence in the region of a working hydrocarbon system that is generating both oil and gas.

Annual Report and Accounts 2007 Heritage Oil Ltd 01

Operational

Kingfisher-1 well in Block 3A in Uganda tested at 13,893 bopd from four intervals

First production from the Zapadno Chumpasskoye field in Russia

Miran Block Production Sharing Contract awarded in the Kurdistan Region of Iraq

Expanded portfolio of significant licence awards and farm-ins in Mali, Malta, Pakistan and Tanzania in the last six months

110% increase in annual production from continuing operations to 129,900 barrels of oil

Total reserves and resources increased to 626 MMboe

FinancialPrimary listing on the Main Market of the London Stock Exchange completed on 31 March 2008

Over $350 million of funds raised in 2007; $165 million by way of a convertible bond issue and $186 million from the issue of shares

Strong balance sheet with cash of $230 million at 31 December 2007

All dollars are US$ unless otherwise stated

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“ The last 15 months have been outstanding for the Group with successful exploration in Uganda and the listing on the London Stock Exchange. 2008 should be a pivotal year for the Group. The Company has the resources and team to achieve strong growth in the size and value of its energy assets.”

Highlights

Heritage Oil Ltd Annual Report and Accounts 200702 Annual Report and Accounts 2007 Heritage Oil Ltd

With our success in raising significant amounts of capital in 2007, and in securing additional exploration and development assets, it became clear that changes were required to ensure that our shareholders could benefit from higher trading liquidity and better value recognition in the price of our shares.

After spending considerable time examining the most suitable markets for listing our shares, a decision was made for Heritage Oil to enter into a corporate reorganisation and to seek a primary listing on the Main Market of the London Stock Exchange. This significant undertaking was completed at the end of March 2008.

ProgressAlthough we have been active in Uganda since 1997, our achievements over the last two years have been particularly significant. Our persistence in the face of challenging circumstances is a point of considerable corporate pride that underscores our drive to realise value from the large Uganda land base that we hold. With multi-well drilling programmes planned for Blocks 3A and 1, which commenced with the spud of the Kingfisher-2 well in April 2008, we have lots to look forward to in Uganda over the next few years.

In other areas of activity we continued to enjoy success on all fronts. We commenced production in Russia¸ were finally awarded a licence in the Kurdistan Region of Iraq, and have completed farm-ins and secured licences in several new territories. We now have a portfolio of assets with significant scope for success. This, combined with our ability to recruit and

Positioned For Growth

retain top quality people, positions us well to explore and develop large potential oil and gas resources in an increasingly energy-hungry global environment.

Social ResponsibilityIn many of our activity areas we are committed to implementing a wide range of community projects, including public health, education, environmental awareness, public facility and community relations based programmes. In these endeavours, our involvement is not simply limited to providing funds. We actively work with communities to build trust and ensure that community needs are carefully considered when the projects are planned and implemented.

Tribute For all of our pride in our success, we are mindful of and deeply saddened by the tragic loss of life of Carl Nefdt, the team leader of IMC Geophysical International Limited’s seismic crew in Uganda, on 3 August 2007. Carl’s memory will be honoured permanently as we are building a school in Uganda that will be dedicated in Carl Nefdt’s memory and named Carl Nefdt Memorial School.

Board of DirectorsI am pleased to welcome General Sir Michael Wilkes KCB, CBE, to the Group. Sir Michael is an outstanding addition to the board as he brings considerable corporate experience, an extensive network of contacts and strong corporate governance experience.

Michael J. HibberdChairman and Non-Executive Director

Chairman’s Statement

“ 2007 was a year of substantial success for the Group both operationally and financially. Our accomplishments are a result of our consistent focus on the swift appraisal and timely execution of key opportunities.”

Heritage Oil Ltd Annual Report and Accounts 2007 Annual Report and Accounts 2007 Heritage Oil Ltd 03

OutlookLooking forward, as we initiate high-impact drilling programmes in Uganda and the Kurdistan Region of Iraq, our solid working capital position ensures that we can reasonably expect to create additional shareholder value without any near-term expectation of dilution. We believe 2008 will be another exciting year for the Company as we drive our business forward at an accelerating rate and realise the benefits of an increased level of market interest in our activities.

Michael J. HibberdChairman

• April 2008: Commencement of drilling of the Kingfisher-2 well in Uganda

• April 2008: Signed documentation to farm in to four exploration licences

• March 2008: Dealings commence on the London Stock Exchange

• February 2008: Completion of Mali documentation for two licences and announcement of Corporate Reorganisation

• December 2007: Awarded production sharing contract in Malta

• November 2007: Closing of Equity Financing Raising Cdn $181.5 million

• October 2007: Awarded production sharing contract in the Kurdistan Region of Iraq

• May 2007: Commences production and development approval at Zapadno Chumpasskoye Field

• February 2007: Reports final test results of 13,893 bopd for the Kingfisher-I well in Uganda

• January 2007: Placement of US$165 million convertible bonds.

Milestones


I am pleased to report on the Group’s progress in 2007 and in the first three months of 2008. It is the over-riding objective of management to responsibly pursue activities to increase shareholder value for both the short and long-term. 2007 was a year of strong performance in this regard.

From the outset, our strategy has been to focus on high-impact international hydrocarbon prospects. Economists, business leaders and responsible governments around the world recognise that demand for hydrocarbons, as the world’s primary source of energy, will continue to increase as a result of population and economic growth, particularly in the Far East and Asia.

They also recognise that as existing major oil and gas fields deplete, exploration efforts must be turned to remote and challenging regions, both offshore and onshore. Frontier areas initially involve greater political, environmental and operational risk. While international crude oil prices remain volatile, current and recent prices provide massive upside potential for successful exploration in these regions, particularly for companies gaining early positions.

At Heritage, we have managed technical and political risk by developing a diverse portfolio that encompasses both a geographic spread of licences and a mix of exploration, development and production assets. Our experienced management and technical teams bring to bear an extensive network of contacts to accomplish our goals.

Exploring The Possibilities

We have an appreciation of risk in our core areas, and our management structure is geared to be responsive, which gives us the flexibility to make strategic decisions rapidly in response to changing circumstances. Today, the Company’s interests are spread across Africa, the Middle East, Russia and the Mediterranean, and include high-impact exploration opportunities as well as fields in development and production.

With many years of effort and commitment, we have successfully formed strategic alliances with local and international companies to secure significant holdings. We consistently look to leverage our core competencies, optimise resource commitments, and manage exploration and development risks with a view to obtaining access to future growth opportunities. This strategic approach has achieved highly encouraging results in our operations over the last two years.

AfricaThe Albert Basin, which straddles the border of Uganda and the Democratic Republic of Congo (DRC), remains the centrepiece of the Group’s portfolio. We believe it is a world-class resource with multi-billion barrel reserve potential in land positions that cover in excess of 12,000 square kilometres.

In Uganda, the Kingfisher-1 exploration well, completed in March 2007, tested 13,893 bopd from secondary zones. The oil is good quality, light (between 30º and 32º API) and sweet with a low gas-oil ratio and some associated wax. Following completion of a 3D seismic programme over the Kingfisher and Pelican

Tony BuckinghamChief Executive Officer

Chief Executive’s Review

“ The Group’s strategy is to generate growth in shareholder value through the development, production and acquisition of a portfolio of oil and gas interests, leveraging off a highly effective network of influential industry, political and institutional relationships.”


structures, a more powerful rig, capable of drilling to the primary target, was contracted and commenced drilling the Kingfisher-2 well in April 2008. The deeper target has the potential to add significantly to our asset base.

New seismic data acquired in Block 1 during 2007 has led to identification of a number of structures and drilling is expected to commence on these prospects during 2008. Additionally, we have plans to commence drilling on the offshore Pelican structure in Block 3A during 2009.

On the DRC side of the Albert Basin, a seismic programme will be undertaken in two blocks on receipt of a Presidential Decree ratifying a Production Sharing Agreement between the Group, Tullow and the Government of the DRC.

New initiatives undertaken in 2007 demonstrate our intention to explore new regions with considerable hydrocarbon upside potential. In November we committed to a work programme to acquire a 75% working interest in two licences in Mali, Northwest Africa, which is an under-explored region where seismic data indicates the possibility of potential hydrocarbon-bearing structures.

Most recently, in April 2008, we committed to a work programme to acquire interests in four licences in Tanzania, with potential to confirm the presence of a working hydrocarbon system generating oil and gas.

Middle EastIn Iraq, the Group has maintained a presence in the Kurdistan Region of Iraq since 2005. Field

geological and geophysical surveys began in 2006. In October 2007 the Group signed a Production Sharing Contract over the Miran Block in the southern part of the Kurdistan Region of Iraq, which is close to the massive Kirkuk oil field. A 270 kilometre 2D seismic programme has commenced and we plan to begin a high-impact drilling programme later in 2008. Our current estimate is that the Miran structure, with multi-reservoir targets, could contain over 3 billion barrels of oil in place, based on the size of the structure and evaluations from neighbouring fields. The Group will also operate as a 50/50 partner with the Kurdistan Regional Government to construct a 20,000 bpd refinery near the licence area. Kurdistan is considered to be prospective, with less than 10% of the region explored. With a relatively stable, and increasingly secure operating environment, we believe our existing holdings constitute an attractive opportunity for low-cost development of a major resource.

In Oman, the Group has a 10% working interest in Block 8, an offshore licence that includes Bukha, a producing gas-condensate field, and West Bukha, a light oil/gas-condensate field, for which commercial production development is proceeding well. An appraisal/development well drilled in West Bukha in late 2006 proved highly successful, testing at flow rates of about 12,750 bopd of light crude oil and 26 MMscf/d of natural gas. Development of the field continued in 2007, with construction of a production platform and pipeline to deliver the petroleum liquids to market via the existing Bukha field system. Commercial production is expected to begin in the third quarter of 2008.

RussiaIn Russia, the Group remains active in Western Siberia. This region of Russia accounts for more than 60% of the country’s oil production and provides significant cash-flow opportunities. The Group holds a 95% equity interest in the Zapadno Chumpasskoye licence, which contains the Zapadno Chumpasskoye field. Proved and probable reserves are estimated at 60.5 million barrels net to the Group. Production from the field is projected to reach approximately 16,000 bopd by 2014. A multi-well drilling programme began in April 2007 and pilot production facilities were commissioned in May. At year-end, production was averaging 342 bopd of high-quality crude oil and has since risen to over 800 bopd at the beginning of April 2008.

MediterraneanIn December we executed a Production Sharing Agreement with the Government of Malta for two offshore licences in what we believe is a significant high potential region, which may contain structures analogous to very large developed fields in Libya and Tunisia

As CEO, I can assure our shareholders that management is focused on ensuring that all of the Group’s strategies and activities are directed to our primary objective of continually increasing shareholder value. Measuring our progress to this goal is reflected in the value and liquidity of our shares, so considerable time was spent examining the most suitable markets for listing.


With our highly experienced management team, our dedicated and professional employees, contractors and advisers, our financial strength, operational expertise and diverse portfolio of opportunities, we believe the Group is well positioned to sustain strong growth in the value of its assets through 2008 and beyond.

Thank you for your continuing support.

Tony BuckinghamChief Executive Officer

Our conclusion was that a primary listing on the Main Market of the London Stock Exchange was in the best interests of the Group and our investors. We expect the initiatives we have undertaken will enhance our profile and status amongst European investors and within the oil and gas sector generally. We also expect increased trading liquidity and access to an international market with a broad, relevant peer group and considerable research expertise. Over 99.9% of shareholders voted in favour of the scheme of arrangement and the listing, indicating the overwhelming support for our recommendation.

As we move forward with capital programmes on a number of fronts, it is worth noting that we have a strong balance sheet and a demonstrated ability to secure funds to finance operations. In 2007 we raised over $350 million through bond and equity issues, therefore all of our planned programs are proceeding from a position of considerable financial strength.

Chief Executive’s Review continued

“ The Group is the operator and holds 50% interests in two licences in the Albert Basin of the Western Rift Valley of Uganda known as Block 1 and Block 3A. Recent exploration activity has focused on the northern part of Block 3A, on the eastern shores of Lake Albert, which straddles the border of Uganda and the Democratic Republic of Congo.”


Strategy and Strength

The Group aims to continue to generate growth in shareholder value by focusing on high-impact international plays that provide multiple targets with the potential to discover substantial hydrocarbon reserves. The Group’s growth strategy is to acquire and invest in, exploration and early development opportunities throughout the world, with a particular emphasis on its core areas of Africa, the Middle East and Russia.

To be successful, the Group has developed a highly effective network of influential industry, political and institutional relationships. These enable the Group to gain access to a wide variety of new oil and gas business opportunities.

The Company’s competitive strengths include:• Our ability to expand a portfolio of high-impact international plays

• Experienced management and technical teams that posses a track record of finding valuable oil discoveries

• Our position in the Albert Basin of Uganda, considered by management to have the potential to contain significant quantities of commercially developable oil

• Our demonstrated success as a first-mover in acquiring assets in territories such as Uganda and the Kurdistan Region of Iraq

• Our proven track record of creating value through asset sales; approximately $100 million was raised from the sale of assets in Republic of Congo with funds re-invested to acquire the current portfolio of play areas.

Strategy Strengths


What are the Company’s strengths?The Company’s competitive strengths include:

Our ability to secure a portfolio of high-impact international plays

Experienced and responsive management and technical teams with a proven track record of finding valuable oil discoveries

Our significant position in the Albert Basin of Uganda

Our diversified portfolio of assets

Our demonstrated success as a first-mover in acquiring assets in territories such as Uganda and the Kurdistan Region of Iraq

Our proven track record of creating value through asset sales.

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Q: What for you were the highlights of 2007?2007 was a year of substantial success for the Group both operationally and financially. The principal operational highlights included the Kingfisher-1 well in Block 3A, Uganda which tested at 13,893 bopd and the award of the Miran licence in the Kurdistan Region of Iraq. Administratively, the focal point was our corporate reorganisation that resulted in the Ordinary Shares of a newly incorporated company, Heritage Oil Limited, being listed on the Main Market of the London Stock Exchange (LSE). This was completed on 31 March 2008.

Q: Why did you decide on a London listing?We believed that the reorganisation and listing on the LSE were in the best interests of the Group. A number of significant advantages were indentified, which include:

Investors on the LSE typically give high values for exploration companies in our peer group, especially those with high-impact drilling programmes

African exploration companies listed on the LSE typically trade at a much higher enterprise value to potential resource barrel ratio than on the TSX

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The Company can be more readily peer group reviewed on the LSE

Increased research coverage and international awareness. On average, companies listed on the LSE are covered by more analysts than those listed on the TSX. We are already seeing this benefit as five analysts currently cover us, compared to one in 2007

We expect to see increased liquidity on the LSE compared to the TSX.

What are the key components of your strategy?We aim to continue to generate growth in shareholder value by focusing on high impact international plays that provide multiple targets with the potential to discover substantial hydrocarbon reserves. The Group’s growth strategy is to acquire and invest in exploration and early development opportunities throughout the world, with a particular emphasis on its core areas of Africa, the Middle East and Russia, using our highly effective network of influential industry, political and institutional relationships.

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Chief Executive’s Review continued

“ Our commitment to transparency and accountability begins at the top. In the following Q&A, Tony Buckingham takes the opportunity to answer questions that have been asked frequently by shareholders.”

Q&A


What do you believe are the main near-term priorities for the Company?In the near-term, the main priorities for the Group are to continue to drive the business forward by evaluating the prospects in Blocks 3A and 1 in the Albert Basin, Uganda, so that we can exceed the reserves threshold required to justify investment in a development programme and an export pipeline. Additionally, we need to complete the high-impact exploration campaign in the Kurdistan Region of Iraq, as well as commence operations in exciting new territories where we have been awarded or farmed-in to licences.

What do you perceive as the major risks to the Company?There are a number of risks which can affect any international exploration, development and production company, hence effective risk management is critical to continuing to achieve our goals. The Group mitigates its risks by maintaining a portfolio of assets in a variety of stages of development in different countries. The Company continually assesses any risks to ensure that sufficient policies and procedures are in place. The key risks affecting the business were summarised in the Directors’ Report.

How would you describe the culture at Heritage?We have a highly responsive management system which encourages all staff to participate and build the Company. All key members of staff are motivated to continue to generate shareholder value. We have an enviable record of attracting and retaining experienced employees.

Finally, do you have a message for shareholders?We have made tremendous progress since I was appointed CEO in October 2006. Due to the strong support of our shareholders, the dedication of our employees, our well-defined strategy and our proven ability to discover valuable oil and gas reservoirs, we are convinced that we can realise our aspirations. Unforeseen events excluded, we believe that the Group will continue to be a fast growing exploration and production company.


Uganda

Operations Review

In 1997 the Group became the first oil and gas company to actively explore in Uganda in almost 60 years, with the award of a licence covering the original Block 3 in the Albert Basin of Western Uganda. The Albert Basin is located in the western arm of the East African Rift Valley, straddling the border with the Democratic Republic of Congo (“DRC”). The Group farmed out 50% of the licence to Energy Africa (now owned by Tullow) in 2001. The original Block 3A was re-configured and re-licenced in 2004 for a term of six years. Block 3A now covers an area of 2,024 square kilometres. Block 1, which is located to the north, has an area of 3,659 square kilometres and was also awarded in 2004.

Recent oil discoveries in the Albert Basin have made it one of the most significant new basins to be discovered onshore in Sub-Saharan Africa in decades. Eight exploration and appraisal wells have been drilled successfully in the basin since the beginning of 2006, and all have encountered oil bearing reservoirs, with two of the wells testing at over 12,000 bopd.

Area Date Heritage Licence (sq km) Awarded Equity Partners Operator

Block 1 3,659 July 2004 50% Tullow Heritage

Block 3A 2,024 September 2004 50% Tullow Heritage

“ Recent oil discoveries in the Albert Basin have made it one of the most significant new basins to be discovered onshore in Sub-Saharan Africa in decades. Eight exploration and appraisal wells have been drilled successfully in the basin since the beginning of 2006, and all have encountered oil bearing reservoirs, with two of the wells testing at over 12,000 bopd.”

The Kingfisher-1 well, the Group’s first well on Block 3A, was drilled between August 2006 and March 2007 to a depth of 3,195 metres. The drilling rig did not have the operational capacity to reach the deeper primary target. The well tested successfully over four intervals in secondary targets, for an overall cumulative flow rate of 13,893 bopd of light, sweet crude oil. The oil is between 30o and 32o API, with a low gas-oil ratio and some associated wax. The sandstone reservoirs, totalling a thickness of 54 metres, exhibited very high permeabilities of up to 3,000 milliDarcies.

A rig capable of drilling to the primary target has been contracted and commenced drilling the Kingfisher-2 well in April 2008. This well will further appraise the existing secondary targets and explore the deeper zones. Management believes that the deeper target has the potential to transform the Company, with an independently evaluated gross un-risked P10 resource estimate of approximately 700 million barrels.

A 325 square kilometres 3D seismic survey was carried out on Block 3A over the Kingfisher and neighbouring Pelican structures during the summer of 2007. Initial interpretation confirms that the Kingfisher structure has an aerial extent of approximately 45 square kilometres. The data also identifies a number of appraisal/development targets within the Kingfisher structure which will require planning for a multi-well drilling programme from land locations and on Lake Albert.

Drilling of the Pelican prospect and work on other prospects in the lake identified by recent seismic programmes is planned to commence in the first quarter of 2009.

The Group also holds a 50% operating interest (in partnership with Tullow) in Block 1, at the northern end of Lake Albert, covering an area of 3,659 square kilometres. A 2D seismic survey carried out in 2007 identified a number of relatively shallow structures with amplitude anomalies. Oil is known to have migrated into Block 1, as evidenced by the active oil seep at Paraa, within the block. This oil seep, together with the presence of amplitude anomalies, supports the potential presence of hydrocarbons within the block.


Permits

Albert Graben

Heritage PSA

Oil Wells

Country Border

Prospect

Oil Field

LEGEND

BLOCK 3A Heritage

BLOCK 3B Open

BLOCK 1Heritage

BLOCK 4BDominion

TANZANIA

D. R. C.

SUDAN

KENYA

UGANDA

RWANDA

BLOCK 2Tullow

BLOCK 5Neptune

BLOCK 3C Open

BLOCK 3D Open

BLOCK 4AOpen

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50km0

Licence Boundary

Heritage PSA

International Border

LEGEND

UGANDA

RwenzoriMountains

Block 3A

D. R. CLake

Albert

Seml

iki R

iver

Albert

GrabenTuraco -3

BlueMountains

D. R. C

ONGO

UGANDA

Mputa-1

PelicanProspect

Mputa-2

Kingfisher-1

Waraga-1

Block 3D Open

B A S

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TB A S E M E N T

Nzizi-1

Block 3B Open

Nzizi-2

Mputa-4

Mputa-3

Ngassa-1

Block 3C Open

An exploration drilling programme on Block 1 is planned to commence in or after the summer of 2008, concentrating on shallower targets in the southern part of the block.

Independent Resources at Block 3A and 1RPS Energy has estimated that the gross risked recoverable contingent and prospective resources in Blocks 3A and 1 are as follows:

Gross Risked Recoverable Resources (MMstb)

p90 p50 p10 Mean 280 793 1,731 923

The Group holds a 50% working interest, however, the Government of Uganda has a back-in right which could, if exercised, reduce the Group’s working interest to 42.5%

Diagramatic representation of Kingfisher drilling

Map of Blocks 3A and 1 and Surrounding Area


Kurdistan Region of Iraq

Operations Review continued

In October 2007, the Group signed a Production Sharing Contract with the Minister of Hydrocarbons in Kurdistan, covering the Miran Block in the southern part of the Kurdistan Region of Iraq.

As an early entrant in exploration of the Kurdistan Region of Iraq, the Group is strongly positioned to benefit from development of this significant hydrocarbon-prone region, especially as the already-stable security situation continues to improve. Other exploration companies have been operating in this area for several years without major interruption.

Licence Area (sq km) Date awarded Heritage Equity

Miran Block 1,015 October 2007 100%

Satellite image of Miran Structure

“ As an early entrant in exploration of the Kurdistan Region of Iraq, the Group is strongly positioned to benefit from development of this significant hydrocarbon-prone region… the Miran Block covers an area of 1,015 square kilometres, including a potentially very large untested anticline.”

The Miran Block covers an area of 1,015 square kilometres, including a potentially very large untested anticline. The Miran structure, with multi-reservoir targets, could contain over 3 billion barrels of oil in-place, based on the size of the structure and evaluations from neighbouring fields. The Miran Block is close to and on geological trend with other oil fields that are in advanced development or yielding significant discoveries. The nearby Kirkuk field, for example, is a major producing field that is believed to contain more than 10 billion barrels of remaining reserves. The Taq Taq field, located approximately 30 kilometres from the Miran Block, recently tested wells at up to 37,500 bopd of high-quality 48o API crude oil from three formations that have been identified on the Miran Block as target zones.

A 270 kilometre 2D seismic survey commenced in April 2008. Drilling is planned to commence before the end of 2008.

The Group has also entered into a 50/50 partnership agreement with the Kurdistan Regional Government to build, own and operate a 20,000 bpd refinery in the vicinity of the Miran Block licence.


Demir Dagh

Taq Taq

Ismail 1

Kirkuk

Bai HassanChemchemal

Khabbaz

JamburKor Mor

Judaida 1Ajeel

Hamrin Pulkhana

Injana 5

Gilabat 1Qamar

Chia Surkh 2

44º0’0”E 45º0’0”E 46º0’0”E

36º0’0”N36º0’0”N

35º0’0”N 35º0’0”N

44º0’0”E 45º0’0”E 46º0’0”E

KirkukSuleimaniah

MIRAN

I R A N

I R A Q

I R A Q I K U R D I S T A N

Oil Fields

Gas Fields

Gas Condensate Field

Prospect

Heritage PSA

LEGEND

50km0

Map of Miran Block and Surrounding Area


Russia


The Western Siberia Region of Russia, which accounts for approximately 60% of Russia’s total crude oil production, is an example of the Group’s strategy of acquiring assets in both highly-prospective and established hydrocarbon-prone parts of the world.

Since 2005, the Group has held a 95% equity interest in ChumpassNefteDobycha Limited, a Russian company whose sole asset is the Zapadno Chumpasskoye Licence. This licence, which expires in 2024, 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 oil field, which makes it accessible to existing development production infrastructure and facilities. The licence covers an area of about 200 square kilometres and contains the Zapadno Chumpasskoye field discovered in 1997. A total of nine wells were drilled on the licence prior to 2005, and the Group has drilled a further three wells. The producing reservoir is a Late Jurassic sandstone at a depth of approximately 2,700 metres, and is the same producing horizon present in a number of neighbouring fields.

Proved plus probable Area Date Heritage reserves Licence (sq km) Awarded Equity Operator (MMboe)

Zapadno Chumpasskoye 196 September 1999 95% Heritage 60.4

Independent Reserves at the Zapadno Chumpasskoye FieldRPS Energy estimated the Zapadno Chumpasskoye field’s net working and entitlement interest reserves and value to the Group as at 31 December 2007, using money of the day prices, discounted at 10%, to be as follows:

Net working Net Net interest entitlement present reserves interest value

MMboe MMboe $Millions

Proved 23.1 23.1 20.7

Probable Additional 37.3 37.3 214.2

Total Proved + Probable 60.4 60.4 234.9

“ From May 2007 to 31 December 2007, production averaged 331 bopd and has since increased, as a result of bringing further wells into production, to a current level of approximately 800 bopd.”

In 2006 the Group acquired 2D seismic data covering an area of 200 kilometres, began constructing pilot production facilities and re-entered the existing well #226. Three additional wells were drilled, production facilities were commissioned and production commenced in May 2007. From May 2007 to 31 December 2007, production averaged 331 bopd and has since increased, as a result of bringing further wells into production, to a current level of approximately 800 bopd. The crude is light and sweet, 42o API crude oil, with moderate gas-to-oil ratios.

RPS Energy has independently estimated that the Zapadno Chumpasskoye field contains proved and probable reserves of 60.4 million barrels of oil net to the Group. Net Present Value, discounted at 10%, is US$234.9 million net to the Group.

Large-scale commercial development of this field is planned, with production projected to reach some 16,000 bopd by 2014. Total gross development costs of the field are estimated at over $400 million and are expected to be incurred up to 2015, with peak expenditures expected in 2009 and 2010.


ZAPADNO CHUMPASSKOYELICENCE

W E S T E R N S I B E R IA

0 1 0 k m

Heritage Licence

Fields

Oil Pipelines

Gas Pipelines

Exploration & Appraisal Well

LEGEND

4

23226

Map of Zapadno Chumpasskoye Licence and Surrounding AreaThe Group’s Russian expansion strategy is to acquire development licences at attractive prices when the potential is seen to generate early cash flow and production. In order to pursue this strategy, the Group established a jointly owned company with TISE Holding Company, TISE-Heritage Neftegas, in 2007. The other shareholders of TISE Holding Company include Concord, Zarubejneft, Zarubejneftegas (a wholly-owned Gazprom subsidiary), Technopromexport and Zarubejstroymontaj. TISE-Heritage Neftegas functions to appraise and target for acquisition oil and gas opportunities in Russia and internationally.


Oman


The Group acquired a 10% interest in Block 8 offshore of Oman in 1996. Other joint venture partners are RAK Petroleum (the operator) with a 40% interest and LG International with a 50% interest. The Block 8 licence area covers 423 square kilometres and contains the Bukha gas-condensate field, which is located 40 kilometres offshore in the Straits of Hormuz in around 90 metres of water, and the West Bukha discovery, which is approximately 20 kilometres away to the north west. The Group has net entitlement interest proved and probable reserves of 1.7 million barrels of oil equivalent liquids and gas in Oman, independently certified by RPS Energy.

The Bukha field has been producing gas and condensate from two wells since 1994. Wet gas is produced through an unmanned platform and channelled via a 34 kilometre pipeline to an onshore processing plant in Ras Al Khaimah, operated by the state gas company, Rakgas. Revenue is generated from selling the condensate and LPG.

Proved plus probable Area Date Heritage reserves Licence (sq km) Awarded Equity Operator (MMboe)

Block 8 423 April 1985 10% Rak 1.7 Petroleum (operator), LG

“ Development of the West Bukha field commenced in 2007 and is ongoing. Drilling of the West Bukha 3 well commenced in April 2008. It is planned to re-enter the West Bukha 2 well and complete it as a producer… First commercial production is anticipated in the third quarter of 2008.”

Overall, gross production of liquids from the Bukha field declined by 14% to 1,585 bopd in 2007, which is in line with expectations for this mature asset. Gas condensate is stored, for subsequent lifting when logistically economic quantities are accumulated, and sold to a third party under an annual contract. LPG is sold to Rakgas and residual gas is sold by Rakgas to local cement factories. The Company is not paid directly for gas production from the Bukha field, but will receive revenue from gas production from the West Bukha field.

The West Bukha discovery in Block 8 represents a significant potential future field development. The field is partially located in Block 8 in Oman, but a significant area of the structure is in neighbouring Iranian waters, where it is known as Hengam.

In May 2006, the West Bukha-2 appraisal/development well spud, targeting Cretaceous-age carbonates (the same formations as at Bukha) in a large, gas-condensate accumulation. The well test produced a combined flow-rate from zones tested (Ilam/Mishrif/Mauddud and Thamama) of approximately 12,750 bopd and 26 MMscf/d. The oil was light (approximately 42° API).

Development of the West Bukha field commenced in 2007 and is ongoing. Drilling of the West Bukha 3 well commenced in April 2008. It is also planned to re-enter the West Bukha 2 well and complete it as a producer. Facilities design work has been completed. A platform and pipeline are to be installed to deliver petroleum fluids to markets in Ras Al Khaimah via the existing Bukha system. First commercial production is anticipated in the third quarter of 2008.


Dubai

Ras AlKhaimah

West BukhaField

Straits of Hormuz

Khor KhwairProcessing Plant

Mubarek Field

Salakh

Gavarzin

QeshmIsland

BLOCK 8

BukhaField

OMAN

U.A.E

IRAN

OMAN

Heritage PSA

Oil Fields

Gas Fields


Oil & Gas Well

Pipelines

Processing Plant


LEGEND

100km0

Map of Block 8 and Surrounding AreaIndependent Reserves in Block 8RPS Energy has estimated net working interest reserves, net entitlement interest and net present value to the Company of West Bukha and Bukha as at 31 December 2007, using money of the day prices, discounted at 10%, as follows:

Net working Net Net interest entitlement present reserves interest value

MMboe MMboe $Millions

Proved 2.2 1.1 12.3




Democratic Republic of Congo


Established as a Belgian colony in 1908, the Republic of the Congo gained its independence in 1960, but its early years were marred by political and social instability. Today, the Democratic Republic of Congo is one of the largest countries in Africa, covering almost 2.4 million square kilometres. The terrain consists of a vast central basin, drained by the Congo River and which rises eastwards into mountainous terrain, the highest peak being Mont Ngaliema at 5,115 metres. The Blue Mountains, some 2,300 kilometres east of the capital Kinshasa, mark the approach to the border with Uganda, which runs down the centre of Lake Albert. The population is estimated to be in the region of 66.5 million with over 200 African ethnic groups represented.

In addition to its licences in Uganda, the Group holds a 39.5% non-operating interest in two blocks in the Albert Basin – Blocks I and II – on the DRC side of the border. These blocks cover more than 6,000 square kilometres, including the entire western or DRC side of Lake Albert, and are adjacent to the Group’s Block 3A and Tullow’s Block 2 in Uganda. The combination of licences in both the DRC and Uganda gives the Group a very strong acreage position in a highly prospective sedimentary basin. In 2006 the Group, with its partners in these licences, executed a Production Sharing Agreement (PSA) with the Government of the DRC.

The initial exploration term is five years, during which seismic data will be acquired and exploration wells drilled. Works will only commence following the receipt of a Presidential Decree, the timing of which is uncertain. The validity of the award of the licences is currently being disputed by the Congolese Oil Ministry; this is being vigorously defended by the joint venture partners.

Given the proximity of the DRC licences to the Uganda licences in the Albert Basin, management anticipates being able to realise cost benefits in operating, capital and infrastructure development costs, including the development and construction of a potential international export pipeline to Mombasa on the east coast of Kenya.

“ The Group holds a 39.5% non-operating interest in two blocks in the Albert Basin – Blocks I and II – on the DRC side of the border. These blocks cover more than 6,000 square kilometres, including the entire western or DRC side of Lake Albert… The combination of licences in both the DRC and Uganda gives the Group a very strong acreage position in a highly prospective sedimentary basin.”


BLOCK 1Heritage

BLOCK 4A Open

BLOCK 4B Dominion

BLOCK 2Tullow

BLOCK 5Neptune

DEMOCRATIC REPUBLIC

OF CONGO

UGANDA

BLOCK 3A Heritage

BLOCK 3D Open

BLOCK 3B Open

BLOCK 3C Open

BLOCK IIIOpen

BLOCK IVOpen

BLOCK VDominion

BLOCK ITullow

BLOCK IITullow

Permits

Heritage PSA

Albert Graben

Country Border

Oil Well

LEGEND

100km0

Waraga-1

Mputa-2Mputa-1

Kingfisher-1

Nzizi-1Nzizi-2

Ngassa-1

Mputa-3

Mputa-4

Area Date Heritage Licence (sq km) Awarded Equity Partners

Block I 3,825 Signed July 2006 39.5% Tullow Oil (awaiting presidential decree) COHYDRO

Block II 2,634 Signed July 2006 39.5% Tullow Oil (awaiting presidential decree) COHYDRO

Map of Blocks I and II and Surrounding Area


Malta


Malta is a small island nation in the Mediterranean Sea with a population of 400,000. It is situated to the south of Sicily, north of Libya and east of Tunisia and is comprised of an archipelago of seven small islands encompassing 316 square kilometres in area. It is a member of the European Union and stable politically.

On 14 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 (in the case of Area 2) and 140 kilometres (in the case of Area 7) from the south eastern Maltese coast in water depths of approximately 300 metres. Initial seismic interpretation, based on the current extensive data set of almost 3,500 kilometres acquired after 2000, indicates the presence of a variety of potential prospects. Primary targets are Lower Eocene and Cretaceous carbonates that are already recognised as major hydrocarbon producing plays in the central part of the Mediterranean. The licences are under-explored. Only one well has been drilled in Area 2 (Medina

Bank 1, 1980). The well was drilled to a depth of 1,225 metres and failed to reach the target horizons, estimated to be at 1,500 to 4,500 metres, but did encounter gas shows in porous, fractured carbonates.

The work programme has commenced with the re-interpretation of existing seismic, which will be followed by the acquisition of a further 2D seismic programme and a drilling programme during the next three years.

“ The licences cover almost 18,000 square kilometres… Primary targets are Lower Eocene and Cretaceous carbonates that are already recognised as major hydrocarbon producing plays in the central part of the Mediterranean.”


Area of seismic coverage

S I C I LY

T U N I S I A

L I B Y A

M A L T AValetta

Siracusa (Syracuse)

Tunis

Tarãbulus (Tripoli)

Sfax

MS-B1 Valetta 1

Alexia 1

Alexia 2

MS-A1

Malta 1

Aqualta 1

Naxxar 2

Madonna Taz-Zejt 1ST1

Lampuko 1

Gozo 1

Tama 1

A-001A-NC087

A-001-NC146

B-001-NC087

Medina Bank 1

Area 7

Area 2

Block boundary

Area of seismic coverage

Exploration Well

Oil & Gas shows


LEGEND

0 50 100km

0 50m25

Licence Area (sq km) Date awarded Heritage Equity

Area 2 9,190 December 2007 100%

Area 7 8,778 December 2007 100%

Map of Areas 2 and 7 and Surrounding Area


Mali


Mali is a large (1.24 million square kilometres) land-locked country in North-West Africa, with a population of 12 million. The terrain is mostly flat to rolling sand-covered northern plains, with rugged mountainous terrain in the north and east and savanna in the south. Mali is among the poorest countries in the world, with 65% of its land area desert or semi-desert and with economic activity largely confined to the riverine area irrigated by the Niger.

The Group is the operator and has the right to earn a 75% working interest in each of Blocks 7 and 11 by financing 100% of the minimum work programme over the next two years, estimated to be a minimum of $14 and $15 million. The blocks cover a gross area of over 72,000 square kilometres and are located onshore in the Gao Basin. The Group’s partner is Mali Oil Developments SARL, a wholly-owned subsidiary of Centric Energy Corporation.

The two licences are located in the east of the country within the Gao Graben, a Mesozoic basin that management considers geologically similar to other Mesozoic interior-rift basins within North Africa, such as the Muglad Basin of Sudan, the Doba Basin of Chad, and Tertiary basins such as the Albert Basin of Uganda. The Graben has been delineated by various surveys conducted since the early 1970’s, 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 presence of approximately 4,000 metres of sediments in the geological section.

Previous drilling in the Gao Graben has encountered oil and gas shows. The Tin Bergoui water well, which lies approximately 30 kilometres to the west of Block 11, was drilled to a depth of 350 metres, encountered oil and gas shows in a number of horizons, indicating the potential for a working hydrocarbon system. The Group will proceed with a comprehensive programme of seismic acquisition and reprocessing to support selection of initial drilling locations.

“ The two licences are located in the east of the country within the Gao Graben, a Mesozoic basin that management considers geologically similar to other Mesozoic interior-rift basins within North Africa, such as the Muglad Basin of Sudan, the Doba Basin of Chad, and Tertiary basins such as the Albert Basin of Uganda.”


Block 7

Block 11

Sikasso

Koulikoro

Kayes

Sègou

Mopti

Gao

Kidal

Timbuktu

BamakoOuagadougou

Niamey

M A U R I T A N I A

SENEGAL

G U I N E A

IVORY COAST

B U R K I N A F A S O

N I G E R

A L G E R I A

G H A N AB E N I NT

OG

N I G E R I A

M A L I

0º 20º 4º 6º24º

22º

20º

18º

16º

14º

12º

10º

8º 6º 4º 2º14º 12º 10º24º

22º

20º

18º

16º

14º

12º

10º0º 2º 4º8º 6º 4º 2º14º 12º 10º

Heritage PSA

Exploration Well

Well & Gas Shows


LEGEND

0 100 200km

0 100m50

Atouila-1

Yarba-1

Ansongo-1

Tahabanat-1

In Tamat-1

Tin Bergoui-1


Block 7 39,804 July 2006 75% Centric Energy Heritage

Block 11 32,810 June 2005 75% Centric Energy Heritage

Map of Blocks 7 and 11 and Surrounding Area


Pakistan


The Indus Valley civilisation, one of the oldest in the world and dating back at least 5,000 years, spread over much of what is presently Pakistan. During the second millennium B.C., remnants of this culture fused with the migrating Indo-Aryan peoples. The area underwent successive invasions in subsequent centuries from the Persians, Greeks, Scythians, Arabs (who brought Islam), Afghans, and Turks. Pakistan today covers some 800,000 square kilometres with a population of approximately 168 million. Pakistan has proved oil and gas reserves reported to be in the region of 289 million barrels and 760 billion cubic metres, respectively.

The Group was awarded a 60% participating interest in the Sanjawi Block (number 3068-2) in Zone II (Baluchistan) in November 2007, and has been appointed as operator. This onshore exploration licence covers a gross area of 2,258 square kilometres and encompasses a variety of terrains ranging from relatively flat desert and cultivated valley floors to rugged hill country. The block is considered highly prospective due to the presence of oil seeps to the south of the licence. The block is dominated by a series of broad east-west trending surface features including the Dabbar and Warkan Shah anticlines. These are large structures, the Dabbar anticline being some 300 square kilometres in area. These features will be examined as potential targets for drilling.

“ The block is considered highly prospective due to the presence of oil seeps to the south of the licence. The block is dominated by a series of broad east-west trending surface features including the Dabbar and Warkan Shah anticlines.”


64º 72º

24º 24º

32º32º

64º 72º

Indus

A F G H A N I S T A N

I N D I AI R A N

T A J I K I S T A N

C H I N A

U Z B E K I S T A N

P A K I S T A N

Heritage PSA

Oil Fields

Gas Fields



Gas pipeline

Oil pipeline

Refined product pipeline

LEGEND

KabulIslamabad

New Delhi

Dushanbe

Lahore

Quetta

Karachi

Peshawar

Sanjawi

Zarghuri South-1Khattan

Jandran -1

Miriwah -1

Savi Ragha-1

Dhodak

SalsabilKhattan

0 100 200km

0 100m50


Sanjawi Permit 2,412 November 60% Sprint Energy, Heritage 2007 Trakker Energy

Map of Sanjawi Block (Number 3068-2) and Surrounding Area


Tanzania


Tanzania is a large (0.9 million square kilometres) country in East Africa stretching over 1,000 kilometres from the Indian Ocean to the Western Rift Valley, with a population of approximately 40 million.

In April 2008, the Group signed documentation to farm-in to four exploration licences (Latham, Kimbiji, Kisangire and Lukuliro Areas) in Tanzania. The Kimbiji and Latham Areas cover approximately 9,300 square kilometres and are held under one PSA, whilst the Kisangire and Lukuliro Areas cover approximately 16,100 square kilometres and are held under another PSA.

The Latham and Kimbiji Areas, covering 5,056 square kilometres and 4,298 square kilometres respectively, encompass onshore (1,881 square kilometres), near shore (2,981 square kilometres), and deep water (4,491 square kilometres) areas. The PSA was awarded to Petrodel Resources Ltd (“Petrodel”) by the Tanzanian Government in September 2006 with exploration periods of four years, followed by extensions of four years and three years respectively, with the right to a development licence with a term of 25 years.


Kisangire Area 7,280 May 2005 55% Dominion Heritage

Lukuliro Area 8,829 May 2005 55% Dominion Heritage

Kimbiji Area 4,298 September 2006 70% Petrodel Petrodel

Latham Area 5,056 September 2006 29.9% Petrodel Petrodel

“ The Group has four licences with a gross area of over 25,000 square kilometres. The Company is very pleased to have secured these land positions which have been identified as having highly desirable exploration potential.”

Under the terms of the farm-in agreement with Petrodel, the Group has the right to earn a 70% working interest in the Kimbiji Area, and a 29.9% working interest in the Latham Area, by funding all seismic costs of the required work programmes on both blocks, comprising the acquisition of both 2D and 3D seismic data, and the drilling of two exploration wells within the Kimbiji Area. The Group will be appointed operator upon drilling the second exploration well in the Kimbiji Area.

The onshore Kisangire and Lukuliro licences were originally awarded to Dominion Oil & Gas Limited (“Dominion”) in May 2005, with an exploration period of four years, followed by one extension of four years, a further extension of three years and the right to a development licence with a term of 25 years.

Under the terms of the farm-in agreement with Dominion, the Group has the right to initially earn a working interest of 55% in both the Kisangire and Lukuliro licences. In order to earn the working interests, the Group will fund all costs to acquire a minimum of 150 kilometres of 2D seismic data and the costs of the first

commitment well. The Group also has an option to earn an additional working interest of 15% thereby increasing its participating interest to 70% by funding 87.5% of the costs of a second well. The minimum exploration expenditure required under the PSA during the first exploration period, which includes seismic acquisition and the drilling of two wells, is US$10 million.

All four licences are close to the recent Mkuranga-1 gas discovery which was drilled in 2007, and reportedly flowed gas at a rate of 20 mmcf/d from an Upper Cretaceous reservoir. This well is located approximately 25 kilometres to the east of the Kisangire Area. The large Songo Songo producing gas field is located to the south-east of the Areas.

The Wingayongo oil seep is present in the Kisangire Area, indicating the presence in the region of a working hydrocarbon system that is generating both oil and gas. Previous seismic data acquired in the Areas, combined with encouraging hydrocarbon shows in wells drilled in the licences, identifies the Areas as a highly desirable exploration province.

The farm-ins are expected to close in the second quarter of 2008, subject to certain conditions precedent, including customary governmental approvals, which are expected to be met.


Map of four licences in Tanzania


Financial Review

Creating Value

Pursuant to a reorganisation, Heritage Oil Limited became the parent company of the Group on 31 March 2008. Prior to that time, the parent company of the Heritage Group was Heritage Oil Corporation. Accordingly, for this year’s annual report, the financial statements presented in this report and the related financial information are derived from Heritage Oil Corporation.

Trading performanceProductionAverage daily production declined by 8% from 387 bopd to 356 bopd. This decline resulted from the sale of the Kouakouala field working interest in the Congo on 12 December 2006, offset by first production from the Zapadno Chumpasskoye field in Russia in May 2007.

“ As we move forward with capital programmes on a number of fronts, it is worth noting that we have a strong balance sheet and a demonstrated ability to secure funds to finance operations. In 2007 we raised over $350 million through bond and equity issues, therefore all of our planned programmes are proceeding from a position of considerable financial strength.”

Paul AthertonChief Financial Officer

2006 2007 Change

Production bpd 387 356 (8%)

Sales volume bpd 214 333 56%

Average realised price $/bbl 50.36 30.53 (39%)

Petroleum and natural gas revenue $m 3.9 3.7 (5%)

Drilling services revenue $m 2.9 –

Loss from continuing operations $m (40.8) (83.2) (104%)

Income from discontinued operations $m 12.4 –

Net loss $m (28.4) (83.2) (193%)

Net loss per share – basic and diluted $ (0.13) (0.37) (185%)

Net cash outflow from operating activities of continuing operations $m (12.7) (2.5) 80%

Total cash capital expenditures – continuing operations $m 28.5 75.3 164%

Year end cash balance $m 46.9 230.1 391%

Net (debt) cash $m (57.2) 13.7

Gearing ratio (net debt divided by total equity) % 57.0

Selected operational and financial data


RevenuePetroleum and natural gas revenue decreased by 5% to $3.7 million, due to lower condensate sales from Oman, offset by revenue from Russian production. Condensate sales from the Bukha field in Oman decreased by 56% to $1.6 million, with condensate of 11,199 barrels held in inventory for sale in 2008 (2,844 barrels at 31 December 2006 for sale in 2007). First production from Russia commenced in May 2007 generating revenue of $1.7 million during the period ended 31 December 2007.

The average realised price of $30.53 in 2007 was 39% lower than the previous year due to changes in product mix, with sales in Russia being sold to the domestic market.

There were no third party drilling services revenues realised in 2007 compared with $2.9 million in 2006. Drill rig revenue is generated from the Group’s 50% share of Eagle Drill’s sales to third parties. In 2006, Eagle Drill was a drilling contractor for the operator of Block 2 in Uganda.

Operating resultsPetroleum and natural gas operating costs increased to $2.9 million in 2007, due primarily to commencement of production in Russia in May 2007. Drilling rig operating expenses in 2007 reduced significantly, due to the lack of third party drilling activity in Uganda.

General and administrative expenses increased from $8.6 million in 2006 to $41.3 million in 2007, due principally from higher share-based compensation expenses relating to stock

options granted or approved in 2007. If share-based compensation expenses are excluded, net general and administrative expenses increased from $7.5 million in 2006 to $12.2 million in 2007. This increase resulted from the following factors:

Growth of the Group. The Group has employed additional staff and appraised and undertaken operations in new territories;Increased travel expenses supporting higher levels of activity in the Group’s core areas; andExpenses in 2007 relating to the corporate reorganisation and subsequent listing on the London Stock Exchange.

In 2007, the Group capitalised $10.3 million (2006: $1.7 million) of general and administrative costs relating to exploration and development activities, including share-based compensation of $9 million (2006: $0.7 million).

Depletion, depreciation and amortisation expenses increased by 36% to $1.9 million in 2007, principally due to depletion of the field in Russia and an increase in corporate assets subject to depreciation. The carrying value of the drilling rig was written down to its estimated fair value in 2007, resulting in a charge of $1.8 million.

Exploration expenditures expensed in the period and not capitalised decreased by 11% from $6.1 million in 2006 to $5.4 million in 2007. Exploration expenditure in 2006 principally related to activities in the Kurdistan Region of Iraq ($3.6 million) and in Oman ($1.7 million). Exploration expenditures in 2007 related mainly

•

•

•

to activities in the Kurdistan Region of Iraq of $2.3 million and potential new ventures in Russia of $1.5 million.

In December 2006, the Group disposed of its assets in Congo. The results of operations in Congo were therefore classified as discontinued operations. The gain on disposal of discontinued operations and earnings from discontinued operations amounted to $12.4 million in 2006.

In 2007, the Group recognised a gain on disposal of its shares in subsidiaries of $1.1 million. The Group’s 65% equity interests in Pipelay and Naturalay Technologies were sold for consideration of 605,000 common shares in SeaDragon Offshore Limited.

Interest income of $2.6 million in 2007 was $1.3 million higher than in 2006 as a result of higher average cash balances and higher average interest rates. Cash and cash equivalents are typically held in interest bearing treasury accounts. Cash generating this income was raised by a private placement of shares for gross proceeds of $186.4 million (Cdn$181.5 million) in November 2007 and the issue of $165 million, 8%, unsecured, convertible bonds in February 2007.

In the first quarter of 2007, the Group redeemed the 550 outstanding 10%, unsecured convertible bonds, issued in March 2006, for total proceeds of $82.5 million plus accrued interest. This resulted in a loss of $7.2 million on redemption, net of transaction costs.


Convertible bonds are separated into liability and derivative liability components (being the bondholders’ conversion option) and each component is recognised separately. The change in the fair value of the convertible bonds’ conversion options, which is primarily due to the performance of HOC’s share price, resulted in a loss of $24.9 and $21.3 million in 2006 and 2007, respectively.

Other finance costs increased from $4.6 million in 2006 to $10.7 million in 2007, from the issue of unsecured convertible bonds ($60 million in March 2006 and $165 million in February 2007), that lead to higher interest and accretion expenses.

The Group recognised an unrealised gain in the fair value of its investment in Afren plc (“Afren”) warrants of $0.2 million in 2006 and $0.9 million in 2007. The Group holds 1,500,000 warrants in Afren, received as partial consideration from the sale of Heritage Congo Limited in 2006.

The Group’s net loss in 2007 was $83.2 million, compared to $28.4 million in 2006. In 2007 the basic and diluted loss per share from continuing operations and net basic and diluted loss per share were $0.37, compared to basic and diluted loss per share from continuing operations of $0.19 and net basic and diluted loss of $0.13 in 2006.

Cash flow and capital expenditureCash used in operating activities of continuing operations was $2.5million in 2007 compared to $12.7 million in 2006. Total cash capital expenditures in 2007 were $75.3 million compared to $28.5 million in 2006. The following work was undertaken in 2007:

In Uganda, work programmes were accelerated following the discovery of a new hydrocarbon system in the Albert Basin. Following the completion of drilling and testing of the Kingfisher-1 well in the first quarter of 2007, which production tested 13,893 bopd, a series of 2D and 3D and seismic programmes were acquired in Blocks 3A and 1. These programmes have identified a number of targets which can be drilled in 2008 and beyond; An exploration and appraisal drilling programme commenced in the Zapadno Chumpasskoye field in Russia and an early production system was installed and commissioned, resulting in first production in May 2007; The development of the West Bukha field in Block 8, Oman continued during 2007; andDuring the second half of 2007, the Group acquired new prospective areas through farm-ins and licence awards in the Kurdistan Region of Iraq, Malta, Mali and Pakistan.

Cash inflow from discontinued operations was $21.3 million in 2006 (2007: $nil).

The Group achieved a net increase in cash and cash equivalents during 2007 of $182.5 million.

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Financial PositionLiquidityAt 31 December 2007, the Group had a working capital surplus of $212.2 million, including cash and cash equivalents of $230.1 million. The Group raised cash of over $350 million in 2007. $165 million was raised in February 2007 by the issue of 8%, unsecured convertible bonds, of which $82.5 million plus accrued interest was used to redeem an existing 10% convertible bond and the remainder was available for general corporate funding purposes. Gross proceeds of $186.4 million (Cdn$181.5 million) were received in November 2007 from an issue of 3,000,000 Common Shares by HOC at a price of Cdn$60.50 per share. In October 2007, the Group received a loan of $9.5 million to refinance the acquisition of a corporate jet. Interest on the loan is at a rate of LIBOR plus 1.6%.

Capital structureThe Group’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. The Group had net cash of $13.7 million at 31 December 2007 compared with net debt of $57.2 million at 31 December 2006 and a gearing ratio of 57%.

Financial Review continued


Risk and Internal Controls A thorough risk assessment of business processes was undertaken in 2006 which identified key financial risks relating to financial reporting. A system of internal controls was designed and tailored to ensure key risks are appropriately addressed and to provide assurance regarding the reliability of financial reporting and preparation of financial statements. Risk and internal controls are continually assessed. One weakness has been identified, concerning accounting for complex transactions from the transition from Canadian GAAP to IFRS, although the Company seeks third party advice to mitigate against this weakness as disclosed on page 42.

The Group maintains insurance policies in accordance with industry standards. The Group 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. The Group does not insure against political risk and, therefore, provides shareholders with full exposure to the risks and rewards of investing in its territories.

The Group maintains a detailed financial model which allows the Company to plan future operating and capital activities in the most efficient manner.

Paul AthertonChief Financial Officer


Net Net Working Entitlement Net Interest Reserves Present Reserves Number Value MMboe MMboe $ Millions

Proved 25.3 24.2 33.0



Total gross reserves and net reserves attributable to the Group’s properties are summarised below:

Light and Medium Oil Crude Oil Gas NGLs Equivalent (Mmbs) (Bcf) (Mmbs) (Mmboe)

Net Net Net Net Net entitle- Net entitle- Net entitle- Net entitle- working ment working ment working ment working ment interest interest interest interest interest interest interest interest reserve reserve reserve reserve reserve reserve reserve reserve

Proved 23.96 23.61 0.74 0.52 1.20 0.46 26.50 24.15

Probable additional 38.54 37.62 4.01 1.00 1.33 0.22 42.50 38.02

Total Proved + Probable 62.50 61.23 4.75 1.52 2.53 0.68 69.00 62.17

Reserves RPS has certified that as of 31 December 2007, the Group’s net working interest reserves and value, using money of the day prices, discounted at 10%, were as follows:

Working interest reserves represent the proportion of future production, before deducting government share of that production, attributable to the Group’s participating interests.

Entitlement reserves represent the Group’s share of future production net of government share in that production under the terms of the relevant PSAs. Government share is impacted inter alia by assumptions as to future oil prices. The Group’s PSAs all provide for the Operator’s costs to be substantially recovered via a priority allocation of oil production (“Cost Oil”). As oil prices increase, so the amount of Cost Oil required to recover past costs reduces, thereby reducing the joint venture’s share of production and so entitlement reserves, although the potential future monetary value of those reserves is increased.

Financial Review continued


Economic valuation of reserves and resources are linked to a long-term price forecast for Brent. The Base Case (US$/bbl Money of the Day) price forecasts, used for all valuations presented in this report, are set out below:

US$/bbl, MOD

2008 85.02009 82.02010 80.02011 78.02012 77.02013 77.32014 78.82015 80.42016 82.02017 83.72018 85.32019 87.02020 88.82021 90.62022 onwards +2% p.a.

Resources RPS certified that the Group had a 50% working interest share of the mean risked working interest prospective resources from Blocks 3A and 1 in Uganda of 462 MMboe (923 MMboe gross) as at 31 December 2007. The Government of Uganda has a back-in right which could, if exercised, reduce the Group’s working interest to 42.5%.


Corporate Social Responsibility

Committed To Our Communities

The Group has always been committed to responsible and respectful conduct towards the diverse communities in which it operates, recognising that only through incorporating economic, environmental and social initiatives into business activities can the Group achieve sustainable development and create long-term value creation for stakeholders, partners and employees.

Investing in local communities today is increasingly accepted as a necessary part of doing business, especially in developing economies that lack basic infrastructures and the capacity to build social capital as this contributes to a healthy and stable business climate.

CommunityOver the past five years the Group has implemented a wide range of community projects, including public health, education, environmental, public facility, and community relations based programmes. In all of these, the Group’s involvement was not simply to provide funds, but to actively work with the communities in order to build trust and ensure that both the needs of communities and those of the Group were considered when the projects were planned. For example, in Uganda the Group has worked closely with local communities in Rwebisengo Bundibugyo District and Buhuka Hoima District, to build and rehabilitate roads and valley dams, drill community water wells and construct cattle dipping tanks. The Group has constructed and repaired fencing around a number of schools such as Makondo Primary School in the Bundibugyo District and invested

in school uniforms, sportswear and equipment.The Group’s values encompass a continuous dedication to education, learning and training. To this end, the Group tailors a number of its corporate and social responsibility initiatives to be specifically education oriented. For example, in Uganda, the Group is building the Carl Nefdt Memorial School and teachers’ residences at Buhuka and establishing a Petroleum Institute for higher education collectively with other oil companies operating in Uganda. The Group has so far sponsored three undergraduate students for courses at universities in Kampala, Uganda; one comes from Bundibugyo district and two from Hoima District. The Group has also trained over 65 officials from the oil ministries in Iraq and the Kurdistan Region of Iraq.

Approximately 20% of the Group’s corporate and social responsibility expenditure is deployed in nature conservation projects. In Uganda, the Group’s employees are involved in a wide variety of field based projects including sponsorship of wildlife conservation and investment in transportation by providing four-wheel drive vehicles and motorcycles for game wardens.

From the outset of these programmes, the Group has actively engaged each community and their local government in planning and agreeing on the project implementation strategies and timings. Communities are involved at the onset of the project ensuring they have a sense of ownership and are able to continue implementation of the project on a sustainable basis.

“ The Group has always been committed to responsible and respectful conduct towards the diverse communities in which it operates, believing that it is only through such an approach to business incorporating economic, environmental and social initiatives that the Group’s sustainable development will be achieved.”

“ The Company believes that in order to create long-term value for its shareholders, partners and employees, it is imperative that it contributes to its adopted communities. Investing in local communities today is increasingly accepted as a necessary part of doing business, especially in developing economies that lack basic infrastructures and the capacity to build social capital as this contributes to a healthy and stable business climate.”


Community ProjectsBuilding and rehabilitation of roads – better access for villagers to local markets; Drilling community water wells; provision of medical supplies & health checks; Building of cattle dipping tanks and valley dams;Sponsorship of school sportswear & equipment; Sponsorship of various community aid & women’s projects; including a community radio station and the Watoto Child Care project.

Educational ProjectsBuilding the Carl Nefdt Memorial School in Buhuka;Sponsorship of local individuals to universities; Sponsorship of civil servants to attend courses on oil legislation and contract terms and to the East African Petroleum Conference.

SafetyThe Group operates in difficult and hazardous environments and the safety of its people is absolutely paramount at all times. As an organisation the Group wants to eliminate accidents and injuries to people in all aspects of its business. It recognises that this is a difficult goal but strives to succeed.

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EnvironmentThe Group is committed to protecting the environment and where a project may have an impact on the environment an Environmental Impact Assessment is usually conducted. This identifies potential impacts and what appropriate mitigation measures can be put in place. The mitigation measures are made operational by drawing up an Environmental Management Plan, which is followed by monitoring the effectiveness of the measures taken to protect the environment or allow its self renewal.

Environmental IncidentsThe Group attaches great responsibility to its emergency response plans which are instituted in case of any environmental incidents. The directors place considerable confidence in the effectiveness of the Group’s environmental incident reporting procedures. To date, the Group has not been subject to any material environmental incidents.

The Group’s objective is to minimise its impact on the environment and to undertake a series of community, conservation and education projects in certain countries in which it operates. Respect for the environment and active engagement with local communities are fundamental to the business of the Group. Above: Construction of the Carl Nefdt Memorial

School.Below: Presentation of motorbikes to the Uganda Wildlife Service.


1. Michael Hibberd, aged 52 Chairman and Non-Executive DirectorMr. Hibberd has extensive international energy project planning and capital markets experience. He has been President and CEO of MJH Services Inc., a corporate finance advisory company, since 1995, prior to which he spent 12 years with ScotiaMcLeod in corporate finance and held the position of Director and Senior Vice President, Corporate Finance. He is also Chairman and co-CEO of Sunshine Oilsands Ltd. and currently serves on the boards of directors of AltaCanada Energy Corp., Challenger Energy Corp., Iteration Energy Ltd., Pan Orient Energy Corp., Ramtelecom Inc. and Zapata Energy Corporation. Mr. Hibberd also served as a director of Rally Energy Corp. until October 2007 and as a director of Deer Creek Energy Limited until December 2005. Mr. Hibberd joined the Group in March 2006.

2. Tony Buckingham, aged 56Chief Executive OfficerMr. Buckingham is the founder of the Group. He commenced his involvement in the oil industry as a North Sea diver and subsequently became a concession negotiator acting for several companies including Ranger Oil Limited and Premier Oil plc. He was previously a security adviser to various governments.

3. Paul Atherton, aged 42Chief Financial OfficerMr. Atherton is a qualified accountant, having qualified with Deloitte & Touche, and holds a degree in geology from Imperial College London. He has a corporate finance background with specific experience in the international mining and resource sectors. He joined the Group in 2000 and joined the board of directors in 2005.

4. Gregory Turnbull, aged 53 Non-Executive DirectorMr. Turnbull is the Regional Managing Partner of the Calgary office of the law firm of McCarthy Tétrault LLP. Mr. Turnbull has extensive knowledge of corporate governance issues and has acted for many boards of directors and special committees in that regard. Mr. Turnbull started his career with the law firm of MacKimmie Matthews in 1979. From 1987 to 2001, he was a partner with Gowlings LLP (formerly Code Hunter LLP). In 2001 and 2002, he was a partner with the law firm of Donahue LLP. Mr. Turnbull has been a partner with the law firm of McCarthy Tétrault LLP since July 2002. He joined the Group in 1997.

5. John McLeod, aged 61Non-Executive DirectorMr. McLeod is a professional engineer with over 36 years of varied resources extraction experience. He is the President of McLeod Petroleum Consulting Limited, the President, CEO and a director of California Oil and Gas Corporation and has held positions and has served on various boards including at Constellation Oil & Gas Ltd.; as President and CEO of Arakis Energy Company; as VP, Operations of Pengrowth Gas Company, Rally Energy Corp., CanArgo Energy Inc. and Canoro Resources. Currently, Mr. McLeod serves as a director of Paris Energy Inc., Consolidated Beacon Resources Ltd., Tuscany Energy Ltd., Diaz Resources Ltd. and Keeper Resources Inc. He joined the Group in 1998.

Board of Directors and Senior Management

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6. General Sir Michael Wilkes, KCB, CBE, aged 67 Non Executive DirectorGeneral Sir Michael Wilkes retired from the British Army in 1995 as Adjutant General and Middle East Adviser to the British Government. As Adjutant General, Sir Michael was the most senior administrative officer within the Army and a member of the Army Board. During his distinguished career, he has seen active service across the world while also commanding at every level from Platoon to Field Army including commanding the 22 Special Air Service Regiment and serving as the Director of Special Forces. Sir Michael is the Non Executive Chairman of Cyberview Technology Ltd and a Non Executive director of the Stanley Gibbons Group, both of which are listed on AIM. In addition he holds non executive positions on a number of private companies including Britam Defence and Trico Ltd and chairs the Advisory Board of PegasusBridge Fund Management Limited, a homeland security company. He joined the Group on 18 March 2008.

7. Brian Smith, aged 55VP ExplorationMr. Smith has 30 years experience in the oil industry. He initially worked as an exploration geologist for Exxon in the North Sea and Gulf of Mexico. He subsequently joined Enterprise Oil where he managed various exploration projects in the Far East and Eastern Europe. He joined the Group in 1997.

8. Stephen Kobak, aged 53VP Production Russia and CISStephen Kobak, a qualified engineer, has 27 years of experience in oil and gas production operations, reservoir studies and asset development. The companies he has worked for include ESSO, Shell International and Khanty Mansiysk Oil Corporation in Western Siberia, where he held senior management positions guiding technical and operations activities. He has extensive international experience working in Russia, the Far East, Middle East and Canada. Mr. Kobak joined the Group in 2007.

9. Armen Sahakian, aged 69VP Business DevelopmentMr. Sahakian received his Ph.D. in geology from Harvard University. He has more than 30 years experience in the oil industry and has held senior management positions in business development and international petroleum negotiations. Among the companies and institutions he has worked for include Conoco, Hispanoil, Partex-CPS, OMV and the World Bank, where he served as petroleum advisor on the Oil and Gas Division’s financed petroleum projects.

10. James Baban, aged 56General Manager, KurdistanMr. Baban has over 30 years experience in the upstream oil and gas industry. He is a Chartered Engineer and a Fellow of The Energy Institute in the United Kingdom and has previously worked for Petro-Canada, Burlington Resources, Veba Oil, BP & BG. Mr. Baban has extensive skills in the development and management of international offshore and onshore projects, having worked in the Middle East, Far East and North Africa. Mr. Baban joined the Group in 2005.

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Heritage Oil Ltd Annual Report and Accounts 200738

List of AdvisersCompany Secretary Woodbourne Secretaries (Jersey) Limited

Ordnance House 31 Pier Road St Helier Jersey JE4 8PW Channel Islands

Registered Office Ordnance Houseof the Company 31 Pier Road

St Helier Jersey JE4 8PW Channel Islands

Head Office and Directors’ 28-30 The ParadeBusiness Address St Helier

Jersey JE1 1BG Channel Islands

U.K. Office of the Company 34 Park Street London W1K 2JD United Kingdom

Financial Advisers JPMorgan Cazenove Limited 20 Moorgate London EC2R 6DA United Kingdom

English Legal Advisers McCarthy Tétraultto the Company Registered Foreign Lawyers & Solicitors

2nd Floor 5 Old Bailey London EC4M 7BA United Kingdom

Canadian Legal Advisers McCarthy Tétrault LLPto the Company Suite 3300

421 7th Avenue S.W. Calgary, Alberta T2P 4K9 Canada

Jersey Legal Advisers Mourant du Feu & Jeuneto the Company 22 Grenville Street

St Helier Jersey JE4 8PX Channel Islands

Auditors of the Company KPMG LLP U.K. 8 Salisbury Square London EC4Y 8BB United Kingdom

Auditors of Heritage Oil Corp KPMG LLP Canada National Suite 3300 Commerce Court West 199 Bay Street Toronto, Ontario M5L 1B2 Canada

Registrars of the Company Computershare Investor Services (Channel Islands) Limited Ordnance House 31 Pier Road St Helier Jersey JE4 8PW Channel Islands

Principal Bankers Standard Bank (Europe)of the Company Bank of Scotland (Europe)

Barclays Bank

Independent Petroleum RPS EnergyEngineering Consultants Goldsworth Houseto the Company Denton Way

Goldsworth Park Woking, Surrey GU21 3LG United Kingdom

Press Agents Bell Pottinger Group 6th Floor, Holborn Gate 330 High Holborn London WC1V 7QD United Kingdom


Corporate Governance Report

The directors recognise the importance of maintaining good corporate governance practices and are committed to applying the highest industry standards of business ethics, health and safety, environment, risk management and corporate and social responsibility throughout the Company.

To this end, the Board will be putting in place policies and procedures within which it will conduct its activities along with working practices and a business culture to ensure openness and full accountability.

As described below, the Company intends in due course to comply with the June 2006 Combined Code of Corporate Governance as issued by the UK Financial Reporting Council (the “Code”) in all material respects.

Compliance with the CodeThe Company was incorporated on 6 February 2008 and listed on the London Stock Exchange on 31 March 2008 (“the Listing”).

The Company was not listed during the accounting period covered by this Annual Report.

This report describes the extent to which the Company has complied with the principles set out in section 1 of the Code and how it intends to apply those principles going forward.

Prior to the Listing, the Board took a number of steps, and continues to do so, to comply with the Code. The majority of the Board previously served as directors of Heritage Oil Corporation whose shares were listed on the Toronto Stock Exchange. The Board is therefore already accustomed to operating in a highly regulated corporate governance environment and as a result has adopted a number of its processes. Although, it is the Board’s intention to comply with the Code in full in due course, in light of its recent Listing, certain principles of the Code have not been applied at this early stage, either because it is not appropriate to do so at this stage in the Board’s development, or, because of the short period of time that has elapsed since Listing. The Board will seek to make progress during the course of the next 12 months and appropriate action will be taken and reported in next year’s Corporate Governance Report.

The Board considers that it has complied with the fundamental aspects of the Code with the exception of the following recommendations, as reported in the Prospectus and owing to the reasons cited above:

i) At least half the Board (excluding the Chairman) should be independent non-executive directors; ii) The Chairman of the Company should not be appointed as a member of the Audit Committee; andiii) The Board has yet to appoint the Senior Independent non-executive director.

Board of DirectorsThe initial Board comprises six directors which include a non-executive Chairman, two executive directors and a further three non-executive directors (as noted below). The Chairman and two of the non-executive directors are deemed to be independent under the terms of the Code. All of the directors bring either extensive experience of the oil industry or a broad range of business, commercial and corporate governance experience, to the Board. The executive directors have close involvement with the operations of the business through their operational roles. The biographies of the Board are set out on pages 36 and 37.

The Board is accountable to shareholders for the creation and delivery of strong sustainable financial performance, guidance, perspective and long-term shareholder value. In doing this, the Board must ensure the effectiveness of the system of internal controls including effectively managing and considering the commercial risks and financing needs, the disposal of businesses, assessing the most appropriate balance between acquisition led growth and organic growth. In practice, these corporate governance and stewardship obligations require individual directors and the Board to be constantly evaluating and challenging the Company’s business strategy to ensure they identify areas where improvements can be made or where new opportunities exist so that the strategies remain appropriate and relevant to the Company’s business. In order to ensure that the Company complies with its obligations as a listed company, the Board must also have responsibility for communications with shareholders, health and safety policy and the review of the Company’s management and financial performance. Further details of compliance with these obligations are set out below.

The main Committees to which the Board delegates certain of its responsibilities are the Audit, Remuneration and Nominations Committees. Further details of these Committees and their activities can be found later in this report and also in the Directors’ Remuneration Report on pages 44 to 47.


The Board was not formed until 2008 and therefore did not meet during the 2007 financial year under review. The Board will meet sufficiently regularly to discharge its duties during 2008 by way of formal Board meetings as well as ad hoc meetings. The frequency of these meetings and the production of a formal schedule detailing matters specifically reserved for its decision and those that will be delegated to management have yet to be determined. Such details and information, together with the levels of individual attendances at Board meetings, will be provided and reported upon next year.

The Board intends to utilise the Group’s existing system for identifying, evaluating and managing the significant risks faced by the Company and its system of internal control. This system is designed to manage, rather than eliminate, the risk of failure to achieve business objectives and can only provide reasonable and not absolute assurance against material misstatement or loss. The Board will continue to review and improve its system of internal controls.

The Company Secretary is a corporate entity based in Jersey that will deal with normal statutory compliance. The Company, the Board and its Committees will be serviced by the Company Secretary or its nominee. The other duties that would normally be carried out by the Company Secretary such as the provision of information flows to the Board, will be dealt with by either the Chairman or Company Chief Financial Officer or their nominee. In terms of corporate governance issues, the Board will be advised by McCarthy Tétrault Registered Foreign Lawyers & Solicitors in London. The Board will monitor the provision of Company Secretarial duties and take any action as appropriate to ensure its requirements are met. The appointment or removal of the Company Secretary will be a matter for the Board as a whole.

As part of the Listing, all non-executive directors executed letters of appointment on 28 March 2008 setting out their respective terms of appointment including their expected time commitment which has been agreed and confirmed with them. The letters are available for inspection and further details can be found in the Directors’ Remuneration Report on pages 44 and 47.

The directors are aware of their responsibilities and feel able to raise any concerns at Board meetings which are minuted accurately in the Board meeting minutes. The Board will adopt a formal procedure on this in due course.

As required by the Code, the Company maintains Directors’ and Officers’ Liability insurance cover, in respect of any legal action taken against the directors, which is reviewed annually.

Chairman and Chief ExecutiveThere is a clear division of responsibility between Chairman and Chief Executive Officer to ensure an appropriate balance of responsibility and accountability. These responsibilities will be formalised in writing and approved by the Board.

The Chairman’s role will be to ensure the effective running of the Board on all aspects of its roles and setting its agenda. His other key responsibilities include leading the Board, setting the Board’s agenda, ensuring effective communication with shareholders, ensuring constructive relations between all directors and that all directors are encouraged to participate fully in the activities and decision making process of the Board. The Chairman will also ensure that the directors receive accurate, timely and clear information with all Board and Committee meeting information being issued to members in advance. At each Board meeting there will be an update on operational and financial performance including a review of the performance and future potential of all material assets.

The Board shall ensure that all directors and Committees have access to independent professional advice whenever it is required and at the Company’s expense.

The Chief Executive is responsible for managing the Group’s business, proposing and developing the Group’s strategy and overall commercial objectives in consultation with the Board and, as leader of the executive team, implementing the decisions of the Board and its Committees.

Board balance and independenceThe Board comprises the following directors:

Michael Hibberd Chairman and non-executive directorAnthony Buckingham Chief Executive OfficerPaul Atherton Chief Financial OfficerGregory Turnbull Non-executive directorJohn McLeod Non-executive directorGeneral Sir Michael Wilkes Non-executive director

The Board is satisfied that its composition will ensure that no individual or group of individuals will dominate the decision-making process and that there will soon be a strong presence on the Board of both executive and non-executive directors.

Corporate Governance Report continued


The Board considers John McLeod and General Sir Michael Wilkes are independent in character and judgement and free from relationships or circumstances which may affect their judgement. On appointment, the Chairman was also considered to be independent.

Albion Energy Limited (“Albion”), the Company’s largest shareholder and Anthony Buckingham entered into a relationship agreement with the Company on 28 March 2008 (the “Relationship Agreement”) as part of the Listing. The purpose of the Relationship Agreement was to ensure that transactions and relationships between the Group, Albion and Anthony Buckingham were at arm’s length and on normal commercial terms. The Relationship Agreement prescribes that at all times, the Board shall be comprised of a majority of directors who are all independent of Anthony Buckingham.

Gregory Turnbull does not meet the independence criteria set out by the Code as he is a partner of McCarthy Tétrault LLP, the Canadian advisers to the Company.

As noted above, one of the main areas of non-compliance with the Code is the appointment of the Chairman as a member of the Audit Committee which is considered necessary due to his financial background.

The Board will look to appoint another non-executive director, so that the fundamental areas of non-compliance with the Code are rectified.

Board CommitteesAs mentioned above, the Board has three Committees, being the Remuneration, Audit and Nominations Committees. The duties of these Committees are set out in formal terms of reference that were adopted by the Board on 18 March 2008 and are available on the Company website. The Committee memberships will be refreshed regularly.

Audit Committee and internal controlsAudit CommitteeThe initial members of the Audit Committee are Michael Hibberd (Chairman), John McLeod and General Sir Michael Wilkes. All members, including the Chairman, are independent non-executive directors. Other members of the Board may also be invited to attend as and when appropriate. The auditors will also be invited to attend regularly.

The Chairman is to be replaced as a member of the Committee as soon as a new independent non-executive director is appointed. The Board considers that Michael Hibberd has recent and relevant financial experience due to his extensive corporate finance background.

The Committee will meet at least twice a year to discharge its responsibilities which are set out in its terms of reference and include responsibility for:

Integrity of financial statements, including annual and interim reports, preliminary results announcements and any other formal announcement relating to its financial performance;Considering the establishment of internal audit function;Making recommendations to the Board on the appointment, review and removal of external auditors;Monitoring external auditors independence; andPolicy on external auditors’ non-audit services.

The Committee will also oversee the Company’s relationship with its external auditors and review the effectiveness of the external audit process. The ultimate responsibility for reviewing and approving the interim and annual financial statements will remain with the Board.

In fulfilling its responsibility of monitoring the integrity of financial reports to shareholders, the Audit Committee shall review the accounting principles, policies and practices adopted in the preparation of public financial information and will examine documentation in relation to the annual report and preliminary announcement.

Internal controlsThe Committee will give due consideration to laws and regulations, provisions of the Code and the requirements of the Listing Rules. It will also have responsibility for reviewing the effectiveness of the Company’s system of internal controls and risk management systems. The Board has taken into account the relevant provisions of the Code in formulating the systems and procedures in operation in the Company. It currently maintains a system of internal control as Heritage Oil Corporation was previously subject to compliance with relevant rules and regulations in Canada (Multilateral Instrument 52-109 of the Canadian Securities Administrators). A further review of the system of internal control will be undertaken prior to the publication of the 2008 annual report.

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The Board is aware of the need to conduct regular risk assessments to identify any deficiencies in the controls currently operating over all aspects of the Company. A formal risk assessment will be conducted on an annual basis on internal controls to cover material controls, both financial and operational, and risk management systems. A report by exception will also be made on any material changes during the year.

The Board recognises the need for effective high level internal controls and for evaluating and managing the risks of the Company. Such matters will be addressed with the Board at its formal Board meetings, ad hoc discussions or via the whistle-blowing policy currently in place (see below).

Financial reporting procedures were reviewed as part of the Listing process and a Board memorandum was prepared. Having considered the findings, the directors were able to confirm that the financial reporting procedures established provided them with a reasonable basis to make proper judgments on the financial position and prospects of the Company on an ongoing basis. However, one weakness was noted, that the preparation of the Group’s consolidated IFRS financial information is a fairly complex task requiring IFRS-experienced accounting personnel and involving the recording of complicated and non-routine transactions that are technical in nature. There is an increasing demand for a limited number of IFRS-experienced accounting personnel who also have knowledge of Canadian GAAP as more Canadian companies prepare financial statements on the basis of IFRS or other international standards. Furthermore, HOC, as a listed entity in Canada, has historically prepared its consolidated financial information according to Canadian GAAP and applied Canadian corporate practice and financial reporting procedures such that there can be no guarantee that the Group will not face difficulties in preparing consolidated IFRS financial information or in applying its new UK financial reporting procedures in all circumstances in the future. Any of the above factors could materially adversely affect the Group’s business, results of operations, financial condition and prospects. However, in any event, the Group does consult with third-party experts from time to time on technical matters in relation to recording items in its financial statements and the nature of its financial reporting procedures and notwithstanding the above, the directors believe that the Group’s financial systems, which have been reviewed by its professional advisers, are sufficient to ensure compliance with the requirements of the Disclosure and Transparency Rules published by the FSA from time to time as a listed entity.

The directors recognise the need to maintain financial reporting procedures, to review them on an ongoing basis and to adapt them to changing circumstances and will use the Board memorandum as a basis for further developing the Board processes.

Remuneration CommitteeThe initial members of the Remuneration Committee are John McLeod (Chairman), Michael Hibberd and General Sir Michael Wilkes. All the members are independent non-executive directors. The Chief Executive and external advisers may also be invited to attend. Further information on the Committee can be found in the Directors’ Remuneration Report on pages 44 to 47.

It is intended that the Remuneration Committee will meet at least once a year and have responsibility for making recommendations to the Board on the framework, or broad Company policy, for the remuneration of the Chairman and the specific remuneration packages including pension rights, and any compensation payments for each of the executive directors, the senior management and such other members of the executive management as it is designated to consider. The Committee will also ensure compliance with the Code and Companies Act 1985 (as amended by the Companies Act 2006) in this respect. No director may be involved in any decisions as to their own remuneration.

Nomination CommitteeThe majority of the Board have previously served as directors of Heritage Oil Corporation and they were judged on their merit before being appointed to the Board. Future re-elections of directors will be subject to satisfactory performance and refreshing of the Board.

Neither the Chairman nor any other director have any other significant appointments and no executive director holds any appointments of FTSE 100 companies.

The initial members of the Nomination Committee are Michael Hibberd (Chairman), General Sir Michael Wilkes and Anthony Buckingham. The majority of the members are independent non-executive directors and Anthony Buckingham is the Chief Executive. External advisers may also be invited to attend meetings as and when required.

It is intended that the Committee will meet at least once a year and will have responsibility for making recommendations to the Board on its composition (including the skills, knowledge and experience), structure and size and that of its Committees, as well as on retirements and appointments of additional and replacement directors taking into account the challenges and opportunities facing the Company.

A number of the Code provisions relating to the Nomination Committee are not relevant at this early stage of the Company’s Listing. The requirements of the Code are included in the Terms of Reference and in due course, processes will be adopted to implement these in practice to ensure compliance with all aspects of the Code.

Corporate Governance Report continued


Information and professional developmentThe Board believes that the Company’s directors possess a wealth of diverse experience and business skills.

The members of the Board have also received full, formal and tailored induction from the Company’s lawyers as part of the Listing process.

The Company will make the necessary resources available for any director’s development needs including access to independent professional advice, services and any other resources including Company Secretarial services as may be necessary to discharge their responsibilities.

Performance evaluationThe Chairman will also ensure meetings are held with non-executive directors without the executive directors present. The non-executive directors shall also meet led by a senior independent director and without the Chairman present, at least once a year, in order to evaluate the Chairman’s performance.

Whistle-blowing policyThe Company has implemented a whistle-blowing policy and information has been sent to all employees advising them that they can raise concerns in confidence about possible wrongdoing by contacting the Chairman of the Audit Committee. In addition, whistle-blowing is an agenda item at Board and Audit Committee meetings and will be reviewed by the Audit Committee and appropriate action taken.

Re-electionIn accordance with the Company’s Articles of Association no director will resign and be subject to re-election by shareholders at the forthcoming Annual General Meeting.

Thereafter, one third or the nearest to one third of the directors shall retire at subsequent Annual General Meetings.

Shareholder relations and constructive use of AGMThe Chairman is responsible for ensuring effective communication of shareholder’s views to the Board as a whole and will update the rest of the Board accordingly. Board Members will use their best endeavours to attend the AGM in order to keep in touch with shareholder opinion.

The Chairman will also ensure that the respective chairmen of the Remuneration, Audit and Nominations Committees attend the Annual General Meeting to answer questions and that the other directors also attend.

Corporate information including the Annual Report and other financial presentations and announcements (including the Prospectus) are available on the Company’s website at www.heritageoilltd.com.


Remuneration Report

In line with the Board’s commitment to applying the Combined Code in the fullness of time, the Company has adopted the fundamental principles of good governance relating to directors’ remuneration as set out in the 2006 Combined Code on Corporate Governance (the “Code”). This Report has been prepared in accordance with the provisions of Companies Act 2006 and Listing Rules of the Financial Services Authority.

Remuneration CommitteeThe Company set up a Remuneration Committee (“the Committee”) on 18 March 2008 shortly prior to its listing on the London Stock Exchange on 31 March 2008 (“the Listing”). As a result of its recent Listing, a number of elements in the Code are not applicable at this early stage; however the Board and the Committee will use their best endeavours to implement these during the course of the next 12 months or so.

The members of the Committee are John McLeod (Chairman), Michael Hibberd and General Sir Michael Wilkes. The Committee will meet at least once a year. The Chief Executive and external advisers will be invited to attend meetings but will not take part in the decision making process.

The Committee’s main responsibilities will be to:Advise on remuneration policy for the Chairman, executive directors and senior executives;Assess and determine total rewards available to the executive and non-executive directors;Determine policy and scope for pension rights and any compensation payments and ensure compliance with the Code in this respect.Make recommendations to the Board for its approval and that of shareholders on the design of future long-term incentive plans and make recommendations for the grant of options to executives under such plans.

It is the Company’s intention over time to provide executive rewards in line with the Association of British Insurers and the National Association of Pension Funds guidelines, whilst maintaining an internationally competitive position. This will be done in association with independent consultants. Such consultants will also advise the Company on remuneration and sector issues and have no connection with the Company.

The Remuneration Committee has clearly defined terms of reference which were adopted by the Board on 18 March 2008 and are available on the Company’s website.

No director will be involved in deciding their own remuneration.

Total shareholder returnThe historical comparator total shareholder return graph has not been included as it was considered not to be meaningful due to the Company’s recent Listing.

Executive directors’ remunerationThe Company’s remuneration policy is intended to enable it to recruit, retain and motivate the best people for the Group. It is the Company’s aim to ensure that there is a clear link between the Company’s performance and executive reward with pay varying with performance. Executive directors’ total reward consists of salary, annual bonus, long-term incentives and other benefits.

Shortly prior to Listing, the executive directors entered into new service agreements with the Company. The main elements of the service agreements relating to salary and benefits are set out below:

a) Service agreementsThe executive directors’ service agreements with the Company are for no fixed term. In normal circumstances, the agreements may be terminated by the Company giving not less than 24 months’ notice and the director giving six months’ notice. These arrangements were in place during their time as executive directors of Heritage Oil Corporation and have been inherited by the Company. The Board feels that these notice periods were appropriate to recruit and retain the executive directors, and whilst it has no present intention of changing them, it will keep them under review.

In the event of a change of control of the Company, if the executive directors resign or the Company terminates their appointment within 24 months of such an event, they will each be entitled to an immediate payment in lieu of notice of a sum equivalent to three times their annual salary. In addition, they will be entitled to a payment of $75,000 in the event they are asked to resign from the Board of Heritage Oil Corporation in any event other than as a result of a change of control. The Company also may terminate the agreements and make payments in lieu of notice.

Currently the executive directors’ service contracts do not provide for mitigation in the event of early termination. The executive directors do not have service contracts with any Group subsidiary.

••••


Their terms of appointment and election are set out below:

Dateof Noticeperiod Noticeperiod contract byCompany bydirector

AnthonyBuckingham 28March2008 24months 6monthsPaulAtherton 28March2008 24months 6months

b) Salary, bonus and other benefitsThe executive directors’ annual salaries on Listing were:

Anthony Buckingham £675,000Paul Atherton £500,000

The executive directors will also be entitled to an annual performance related bonus determined by the Committee. It is expected that approximately half of the executive directors’ remuneration will be fixed and the remaining will be performance related.

In addition, they are entitled to the benefits of private medical insurance, life insurance and executive participation in the Company’s retirement and welfare benefit scheme. Both executive directors are entitled to allowances of £100,000 (Anthony Buckingham) and £77,500 (Paul Atherton) to cover their living expenses.

Their salaries will be subject to regular review by the Committee and it is anticipated that the first review will take place towards the end of 2008.

The executive directors do not have any other significant appointments, nor do they hold any appointments of FTSE 100 companies. The Board does not expect this to change but will keep it under review and report any changes in the future.

Non-executive directors’ remunerationThe remuneration of non-executive directors is a matter for the Chairman and the executive members of the Board. The Company’s policy will be to set compensation levels for non-executive directors’ remuneration so as to ensure that they are sufficient to attract, retain and motivate high quality executives. They will also be in line with best practice.

Non-executive directors’ annual fees on Listing were:

Michael Hibberd £80,000Gregory Turnbull £50,000John McLeod £50,000General Sir Michael Wilkes £50,000

In addition, they will each receive an additional fee of £2,000 (or such other amount as the Board in its sole discretion deems appropriate) for each additional day worked in excess of the agreed 20 days per annum. The level of non-executive directors’ fees is governed by the Company’s Articles of Association and any changes will be subject to shareholder approval.

The non-executive directors’ terms of appointment may be terminated by each party giving three months’ notice in writing. Michael Hibberd and George Turnbull will be entitled to a change of control bonus of $75,000 plus a pro-rata amount of their previous year’s bonus multiplied by a stock price performance factor in the event that Heritage Oil Corporation changes control.

With the exception of General Sir Michael Wilkes, all the non-executive directors will be entitled to a payment of $75,000 in the event they are asked to resign from the Board of Heritage Oil Corporation in any event other than as a result of a change of control. General Sir Michael Wilkes received a payment of £50,000 on joining the Board of the Company. No other director received this form of payment on joining the Board of the Company.


Terms of appointment and re-appointment are set out below:

Subsequent Dateof Notice Initialtermof termof contract period appointment appointment1

MichaelHibberd 28March2008 3months 2010AGM 3yearsGeorgeTurnbull 28March2008 3months 2009AGM 3yearsJohnMcLeod 28March2008 3months 2009AGM 3yearsGeneralSirMichaelWilkes 28March2008 3months 2011AGM 3years

Non-executive directors will not participate in the Company’s pension arrangements or the Company’s future long-term incentive plans. In addition, neither the Chairman nor any other non-executive director hold appointments of any FTSE 100 companies.

2008 Replacement Share Option SchemeHeritage Oil Corporation implemented The Heritage Oil Corporation Plan (“the Original Plan”) following approval by its shareholders in 2004 and granted options under the Original Plan to its executive and non-executive directors and other employees and consultants at that time. The grant of options included all the then current executive and non-executive Board members with the exception of General Sir Michael Wilkes. As a result of the Group reorganisation and subsequent Listing, all the Board members were entitled to retain their options under the Original Plan and exchange them for options to acquire 10 Ordinary Shares of the Company for every one Common Share they held under option. The Original Plan was then cancelled and on 18 March 2008, the Company adopted The Heritage Oil Limited 2008 Replacement Share Option Scheme (“Replacement Scheme”) which is substantially in the same form as the Original Plan. The purpose of the Replacement Scheme is to act as a replacement to the Original Plan and to honour the options granted under it by granting holders the option to purchase Ordinary Shares. The Replacement Scheme will be administered by the Board and no further options will be granted under it.

The maximum number of Ordinary Shares that may be issued under the Replacement Scheme is 24,545,340, being the equivalent number of shares required to replace the options granted under the Original Plan that were still in existence prior to their cancellation.

The Company intends to seek shareholder approval for a new performance-related executive long-term incentive plan at the forthcoming Annual General Meeting. Further details of this will be provided in the Notice of Annual General Meeting to be published later. The Company will not grant any options under this new or any other new share scheme to non-executive directors and all options will be granted at the full market price.

Directors’ remuneration and interests in shares and optionsAs the Company was not in existence during the financial year under review and did not list its shares until recently, it is not appropriate to show directors’ remuneration and interests in shares and options for that period. This Report does however show information on directors’ remuneration and interests in shares and options since Listing.

Details of directors’ remuneration on Listing are shown on page 45 of this Report.

Remuneration Report continued


On Listing, the directors (including non-executive directors) held the following options under the Replacement Scheme:

Exercise NoofOrdinary priceper Shares Ordinary Vesting ExpiryDirector underoption Share1 periods date

MichaelHibberd 150,000 £0.81 23June2006–23June2008 23June2011 750,000 £1.43 14December2006–14December2008 14December2011 250,000 £2.45 21December2007–21December2009 21December2012AnthonyBuckingham 500,000 £0.48 20May2005–20May2007 20May2010 9,129,510 £1.43 14December2006–14December2008 14December2011 500,000 £2.45 21December2007–21December2009 21December2012PaulAtherton 1,250,000 £0.48 20May2005–20May2007 20May2010 1,125,000 £1.43 14December2006–14December2008 14December2011 500,000 £2.45 21December2007–21December2009 21December2012GregoryTurnbull 150,000 £0.48 20May2005–20May2007 20May2010 300,000 £1.43 14December2006–14December2008 14December2011 150,000 £2.45 21December2007–21December2009 21December2012JohnMcLeod 100,000 £0.48 20May2005–20May2007 20May2010 300,000 £1.43 14December2006–14December2008 14December2011 150,000 £2.45 21December2007–21December2009 21December2012

1 The final exercise prices were converted into pounds sterling on Listing using the exchange rate in effect on that date.

The highest and lowest mid-market prices of HOC’s shares during the period were £0.81 and £3.33 respectively after taking into account the effects of the corporate re-organisation. The mid market price of the Company’s shares at 31 December 2007 is not available due to its recent Listing.

Further details of the Replacement Scheme can be found on page 46 of this Report

The directors’ interests in the Ordinary Shares of the Company on Listing as shown below:

At31March2008

MichaelHibberd 0AnthonyBuckingham(1) 84,540,340PaulAtherton 1,140,000GregoryTurnbull 300,070JohnMcLeod 20,000GeneralSirMichaelWilkes 0

Note:1: Mr Buckingham’s Ordinary Shares include the Ordinary Shares held by Albion Energy Ltd, the Company’s major shareholder which is owned and controlled by

Mr Buckingham.

ApprovalThe Directors’ Remuneration Report has been approved by the Board of directors of the Company.

Signed on behalf of the Board of Heritage Oil Limited

John McLeodRemuneration Committee Chairman30 April 2008


The directors of Heritage Oil Limited (the “Company”) submit their report together with the consolidated audited financial statements of Heritage Oil Corporation (“HOC”) for the year ended 31 December 2007 for the Company and its subsidiaries (“the Group”). The Company was incorporated subsequent to the year-end as part of a reorganisation of the Group which is discussed in more detail below.

Principal activities and business review The Group is an independent, international oil and gas exploration, development and production Group with a focus on Africa, the Middle East and Russia. It also has exploration projects in Uganda, the Kurdistan Region of Iraq, the Democratic Republic of Congo, Malta, Pakistan, Tanzania and Mali, and producing properties in Oman and Russia. The Group operates through a number of subsidiaries which are set out on page 57.

A review of the business including the development and performance of the Group are set out on pages 10 to 27. A description of the significant risk factors and uncertainties facing the Group are set out below.

Results and dividends The Group’s financial statements for the year ended 31 December 2007 are set out on pages 53 to 92.

The Company and HOC and their subsidiaries have not declared or paid any dividends since their incorporation. For the foreseeable future, the Company anticipates that it will retain future earnings and other cash resources for the operation and development of its business.

ReorganisationThe Company was incorporated on 6 February 2008 in Jersey under the Companies (Jersey) Law 1991, as amended (the “Jersey Companies Law”) to become the ultimate holding company of the Group. It changed its status to a public company on 25 February 2008 in preparation for the listing of its Ordinary Shares on the Main Market of the London Stock Exchange (the “LSE”) on 31 March 2008 (the “Listing”). The Company’s registered office is in Jersey.

Prior to the Listing, the holding company of the Group was HOC, a Canadian registered company whose common shares (“Common Shares”) were traded on the Toronto Stock Exchange (“TSX”). As part of the Listing, the Group was reorganised and HOC became an indirect wholly-owned subsidiary of the Company (the “Reorganisation”). The Reorganisation culminated in the Common Shares being de-listed from the TSX and a new class of exchangeable shares being created and issued by HOC (“Exchangeable Shares”). Holders of Common Shares could exchange their Common Shares for either Ordinary Shares of the Company (“Ordinary Shares”) which are traded on the LSE or for Exchangeable Shares of HOC that are traded on both the LSE and the TSX. Further details of the Listing and Reorganisation can be found in the prospectus dated 28 March 2008 (the “Prospectus”) and available on the Company’s website at www.heritgageoilltd.com.

Capital structure The Company has two classes of shares, namely the Ordinary Shares and the special voting share of HOC (the “Special Voting Share”). Its subsidiary HOC has one class of shares, being the Exchangeable Shares.

The Ordinary Shares and the Special Voting Share carry no right to fixed income. The Ordinary Shares have a right to one vote at general meetings whilst the holders of Exchangeable Shares have rights through the Special Voting Share held by the trustee of the Voting and Exchange Trust to one vote at general meetings for every Exchangeable Share on the same basis as if they had exchanged them for Ordinary Shares. For clarity, the Voting and Exchange Trust is a Canadian trust that holds the Special Voting Share for the benefit of the registered holders of the Exchangeable Shares pursuant to the terms of a Voting and Exchange Trust Agreement dated 27 February 2008.

The issued share capital of the Company and total voting rights of the Company are as follows:250,513,032 Ordinary Shares of the Company are issued and outstanding, which constitutes 98.3% of the total voting rights of the Company; and4,431,120 Exchangeable Shares of HOC are issued and outstanding, which constitutes 1.7% of the total voting rights of the Company.

The directors’ interests in the Ordinary Shares, Exchangeable Shares and options granted under the employee share scheme are set out in the Directors’ Remuneration Report on pages 44 to 47.

•

•

Directors’ Report


Major shareholdersThe Company was not incorporated until 6 February 2008. In accordance with Rule 5 of the Disclosure and Transparency Rules, the shareholders listed below have notified the Company of their interests in the Ordinary Shares of the Company as at 29 April 2008:

OrdinaryName Sharesheld %Held1

AlbionEnergyLimited 84,540,3402 33.20%CapitalResearchandManagementCompany 20,212,000 7.93%LansdownePartnersLimited 18,996,540 7.45%FirebirdGlobalMasterFund,Ltd 14,384,000 5.64%HarrierHoldingsLtdreLCAM 11,720,480 4.60%

1 Includes voting rights attaching to the Special Voting Share as well as the Ordinary Shares.2 Number of Ordinary Shares held by both Albion Energy Limited and Anthony Buckingham.

Albion Energy Limited (“Albion”) and Anthony Buckingham entered into a relationship agreement with the Company on 28 March 2008 (the “Relationship Agreement”) as part of the Listing. The purpose of the Relationship Agreement was to ensure that transactions and relationships between the Group, Albion and Anthony Buckingham were at arm’s length and on normal commercial terms.

DirectorsThe following directors held office:

Appointment dates

MichaelHibberd 18March2008AnthonyBuckingham 25February2008PaulAtherton 6February2008GregoryTurnbull 18March2008JohnMcLeod 18March2008GeneralSirMichaelWilkes 18March2008

With the exception of General Sir Michael Wilkes, all the directors were previously and continue to be directors of HOC. William Kaufmann is the other director of HOC.

With regard to retirement and re-election of directors, the Company is governed by its Articles of Association, the Combined Code of Corporate Governance and the Jersey Companies Law.

It has not been appropriate to carry out an evaluation of the Board of directors at this stage, however, the effectiveness and time commitment of each of the individual directors’ was taken into consideration at the time of their initial appointments as directors of the Company which included, where relevant, their prior service as directors of HOC.

Biographical information on all the directors can be found on pages 36 and 37.

Annual General MeetingFull details of the Annual General Meeting which is to be held on 19 June 2008, will be set out in the Notice of Meeting to be published later. Formal notice of the Annual General Meeting including details of special business is set out in the Notice of the Annual General Meeting and on the Company’s website at www.heritageoilltd.com

At the meeting, a special resolution will be proposed for the approval of a new long-term incentive plan. Further details on this will be found in the Notice of the Annual General Meeting.


RegistrarThe Company’s share registrar is Computershare Investor Services (Channel Islands) Limited, Ordnance House, 31 Pier Road, St Helier, Jersey JE4 8PW Channel Islands.

Creditors’ payment policyThe Company was not incorporated until 6 February 2008, however, it is the Company and Group’s policy to settle all debts with creditors on a timely basis and in accordance with the terms of credit agreed with each supplier.

Employees As at 31 December 2007, the Group had 89 employees (including full-time contractors, consultants and executive directors) based in the following locations:

Russia 41 South Africa 4Kurdistan Region of Iraq 5 Switzerland 3UK 14 Canada 1Uganda 21

Significant risk factors and uncertainties The Prospectus identified a variety of material risk factors that could have an impact on the Company, including risks relating to operations, countries in which the Group operates, the Group structure and risks relating to the Ordinary Shares and the Exchangeable Shares. The most significant risk factors impacting on the Group are considered to be:

Exploration and development expenditure and success rates;Factors associated with operating in developing countries, political and regulatory instability;Oil and gas sales volumes and prices; andReliance on key employees.

Additional risk factors were all also identified and further information on these, and the significant risk factors above, can be found in the Prospectus. The above risk factors (and the additional risk factors identified in the Prospectus) could materially adversely affect cash flows to an extent that the Group may, in certain circumstances, need to obtain further debt or equity financing after 28 March 2009.

Political and charitable donationsThe Group did not make any charitable donations during 2007. In addition, the Company has not made any political donations since its Listing. The Group has undertaken a wide range of community schemes, including public health, education, environment, public facility and community relations based programmes.

AgreementsThe Takeovers Directive (Interim Implementation) Regulations 2006 requires the Company to disclose whether there are any significant agreements to which it is a party that take effect after, or terminate upon, a change of control of the Company following a takeover bid and the effects of such agreements. The Company confirms that it has not entered into such agreements since its Listing.

Important events since the year endThe important events since the year end which affect the Company are its incorporation on 6 February 2008 and its subsequent Listing.

Audit and Auditors The directors who held office at the date of approval of this directors’ report confirm that, so far as they are each aware, there is no relevant audit information of which the Company’s auditors are unaware; and each director has taken all the steps that they ought to have taken as a director to make themselves aware of any relevant audit information and to establish that the Company’s auditors are aware of that information.

KPMG LLP UK were appointed as auditors of the Company on 13 February 2008 and have expressed their willingness to continue as auditors. A resolution to reappointment KPMG LLP UK as auditors of the Company will be proposed at the forthcoming Annual General Meeting.

••••

Directors’ Report continued


Statement of directors’ responsibilitiesThe directors are responsible for preparing the Annual Report and the financial statements for the Group in accordance with International Financial Reporting Standards (“IFRS”) and applicable law. As the Company was not incorporated until after the 2007 financial year the financial statements of Heritage Oil Corporation, which was the parent company of the Group in 2007, have been included herein and prepared in accordance with applicable Canadian law and IFRS.

The directors are responsible for keeping proper accounting records which disclose with reasonable accuracy at any time the financial position of the Group, for safeguarding the assets, for taking reasonable steps for the prevention and detection of fraud and other irregularities and for the preparation of a Directors’ Report and Directors’ Remuneration Report which comply with the requirements of the Company’s articles and applicable law.

In the case of IFRS accounts International Accounting Standard 1 requires that financial statements present fairly for each financial year the Group’s financial position, financial performance and cash flows. This requires the faithful representation of the effects of transactions, other events and conditions in accordance with the definitions and recognition criteria for assets, liabilities, income and expenses set out in the International Accounting Standards Board’s ‘Framework for the Preparation and Presentation of Financial Statements’. In virtually all circumstances, a fair presentation will be achieved by compliance with all applicable IFRS. Directors are also required to:

Properly select and apply accounting policies; 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; and Prepare the accounts on a going concern basis unless, having assessed the ability of the Company to continue as a going concern, management either intends to liquidate the entity or to cease trading, or has no realistic alternative but to do so.

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

Going concern After making due enquiries, the directors have made an informed judgment at the time of approving the Financial Statements, that there is a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future. For this reason, the directors continue to adopt the going concern basis in preparing the Financial Statements.

Approved by the Board on 30 April 2008

Anthony BuckinghamChief Executive Officer30 April 2008

•••

•


We have audited the consolidated balance sheets of Heritage Oil Corporation as at December 31, 2007 and 2006 and the consolidated statements of income, recognized income and expense, and cash flow for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2007 and 2006 and the results of its operations and its cash flows for the years then ended in accordance with International Financial Reporting Standards.

Chartered AccountantsCalgary, CanadaApril 28, 2008

Auditors’ Report To The Shareholders


Consolidated Balance SheetsAs at 31 December 2006 and 2007

31December 2006 2007 Notes $ $

ASSETSNon-current assetsIntangibleexplorationassets 10 54,767,332 102,862,754Intangibledevelopmentcosts 11 1,574,039 –Property,plantandequipment 12 32,187,098 64,225,918Otherfinancialassets 13 914,558 5,044,201

89,443,027 172,132,873

Current assetsInventories 98,921 199,465Prepaidexpenses 531,273 447,271Tradeandotherreceivables 14 9,839,506 6,759,261Cashandcashequivalents 15 46,861,146 230,089,323

57,330,846 237,495,320

146,773,873 409,628,193

LIABILITIESCurrent liabilitiesTradeandotherpayables 16 12,715,381 24,646,531Borrowings 17 147,720 623,640

12,863,101 25,270,171

Non-current liabilitiesBorrowings 17 63,124,843 154,253,701Derivativefinancialliability 23 27,997,140 36,739,990Provisions 18 62,322 170,899

91,184,305 191,164,590

104,047,406 216,434,761

42,726,467 193,193,432

SHAREHOLDERS’ EQUITY ATTRIBUTABLE TO EQUITY HOLDERS OF THE CORPORATIONSharecapital 19 24,580,984 217,672,243Reserves 20 2,637,058 43,178,359Retainedearnings(deficit) 20 15,508,425 (67,657,170)

42,726,467 193,193,432

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

Approved by the Board of Directors

Anthony Buckingham William KaufmannDirector Director


Consolidated Income StatementsYears ended 31 December 2006 and 2007


RevenuePetroleumandnaturalgas 3,938,512 3,709,503Drillingservices 2,895,727 –

6,834,239 3,709,503

ExpensesPetroleumandnaturalgasoperating 723,611 2,897,603Drillingrigoperating 2,291,585 38,360Generalandadministrative 7 8,628,127 41,271,960Foreignexchangelosses(gains) 627,005 (931,913)Depletion,depreciationandamortisation 1,351,987 1,892,290Explorationexpenditure 1e 6,066,977 5,415,696Impairmentofproperty,plantandequipment 12 – 1,799,762

19,689,292 52,383,758

Gain on disposal of subsidiaries 9 – 1,077,132

Finance income (costs)Interestincome 1,336,351 2,648,691Lossonredemptionofliabilitycomponentofconvertiblebonds 17 – (7,155,622)Lossonderivativefinancialliabilityrelatingtoconvertiblebonds 1q (24,851,295) (21,279,964)Otherfinancecosts 5 (4,642,126) (10,688,220)Unrealisedgainonotherfinancialassets 13 195,178 906,643

(27,961,892) (35,568,472)

Loss from continuing operations (40,816,945) (83,165,595)

Gain on disposal of discontinued operations 8 9,200,700 –Earnings from discontinued operations 8 3,248,490 –

Income from discontinued operations 12,449,190 –

Net loss for the year attributable to equity holders of the Corporation (28,367,755) (83,165,595)

Net loss per share from continuing operationsBasicanddiluted 1w,21 (0.19) (0.37)

Net earnings per share from discontinued operationsBasicanddiluted 0.06 –

Net loss per shareBasicanddiluted (0.13) (0.37)



Consolidated Statements of Recognised Income and ExpenseYears ended 31 December 2006 and 2007


Changesinthefairvalueofavailable-for-salefinancialassets 20 – 168,000Exchangedifferencesontranslationofforeignoperations 20 (4,003) 434,583

Net income (expense) recognised directly in equity (4,003) 602,583Netlossfortheyear (28,367,755) (83,165,595)

Total recognised income and expense for the year (28,371,758) (82,563,012)



Consolidated Cash Flow StatementsYears ended 31 December 2006 and 2007


Cash provided by (used in)Operating activitiesNetlossfromcontinuingoperationsfortheyear (40,816,945) (83,165,595)Itemsnotaffectingcash Depletion,depreciationandamortisation 1,351,987 1,892,290 Financecosts–accretionexpenses 647,453 3,619,198 Foreignexchangelosses(gains) 422,648 (153,174) Share-basedcompensation 1,417,044 31,300,295 Lossonredemptionofconvertiblebonds – 7,155,622 Lossonderivativefinancialliability 24,851,295 21,279,964 Gainondisposalofsubsidiaries – (1,077,132) Gainonotherfinancialassets (195,178) (906,643) Impairmentofproperty,plantandequipment – 1,799,762 (Increase)decreaseintradeandotherreceivables (972,251) 5,195,888 (Increase)decreaseinprepaidexpenses (312,051) 84,002 (Increase)decreaseininventory 142,809 (100,544) Increaseintradeandotherpayables 725,738 10,585,162

Continuingoperations (12,737,451) (2,490,905)Discontinuedoperations 3,748,853 –

(8,988,598) (2,490,905)

Investing activitiesProperty,plantandequipmentexpenditures (12,265,063) (27,236,018)Intangibleexplorationexpenditures (16,172,102) (48,095,422)Intangibledevelopmentexpenditures (386,668) (64,931)Investmentinshares – (200,000)

Continuingoperations (28,823,833) (75,596,371)Discontinuedoperations 17,576,116 –

(11,247,717) (75,596,371)

Financing activitiesSharesissuedforcash 1,318,945 187,106,476Shareissuecosts – (10,473,386)Convertiblebonds 60,000,000 165,000,000Convertiblebondissuecosts (3,000,000) (6,979,268)Redemptionofconvertiblebonds – (83,022,752)Long-termdebt – 9,450,000Long-termdebtissuecosts – (314,897)Repaymentoflong-termdebt (287,759) (155,537)

58,031,186 260,610,636

Increase in cash and cash equivalents 37,794,871 182,523,360Cash and cash equivalents—beginning of year 8,583,321 46,861,146Foreignexchangegainoncashheldinforeigncurrency 482,954 704,817

Cash and cash equivalents—end of year 46,861,146 230,089,323

Non-cash investing and financing activities 26 Supplementary information Thefollowinghavebeenincludedwithincashflowsfromcontinuingoperationsforthe yearunderoperatingactivitiesInterestreceived 1,665,998 3,504,866Interestpaid 5,032,919 8,546,840



Notes to Consolidated Financial StatementsYears ended 31 December 2006 and 2007

Heritage Oil Corporation (the “Corporation”) is incorporated under the Business Corporations Act (Alberta) and its primary business activity is the exploration, development and production of petroleum and natural gas in Africa, Russia, Pakistan and the Middle East.

These consolidated financial statements include the results of the Corporation and all subsidiaries over which the Corporation exercises control. The subsidiaries consolidated within these financial statements include inter alia Heritage Oil & Gas Limited, Eagle Energy (Oman) Limited, Heritage Oil and Gas (U) Limited, Heritage Energy Middle East Limited, Heritage DRC Limited, Coatbridge Estates Limited, ChumpassNefteDobycha, Neftyanaya Geologicheskaya Kompaniya, Heritage Oil & Gas (Austria) GesmbH, Heritage Mali Block 7 Limited, Heritage Mali Block 11 Limited, Heritage Energy Holding GesmbH (Austria), Heritage Oil & Gas (Gibraltar) Limited, TISE Heritage Neftegaz, Begal Air Limited, Heritage International Holding GmbH, Heritage Talinskoye GmbH, Heritage Oil & Gas Holdings Limited, Eagle Drill Limited, Heritage Oil (Barbados) Limited, Heritage Oil & Gas (Switzerland) SA, Heritage International Malta Limited and Heritage International Holding (Gibraltar) Limited. On 24 March 2008, the Corporation entered into a corporate reorganisation which resulted in a newly incorporated company, Heritage Oil Limited, becoming the parent company of the Corporation and its current subsidiaries. Further details are provided in Note 27.

The Corporation’s consolidated financial statements are presented in US dollars, which is the Corporation’s functional and presentation currency.

The financial statements were approved by the Board and authorised for issuance on 28 April 2008.

1 Significant accounting policiesThe 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 preparationThe consolidated financial statements have prepared in accordance with International Financial Reporting Standards (IFRS). The Corporation’s first set of financial statements prepared under IFRS were those which included annual 2005 and 2006 and the nine-month periods ended 30 September 2007 as filed for the first time with the UK Listing Authorities. The IFRS 1 disclosures concerning the transition to IFRS 1 can be found in those statements as well as note 28.

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 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 Corporation’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 3.

b) ConsolidationThe consolidated financial statements incorporate the assets and liabilities of all subsidiaries of the Corporation as at 31 December 2006 and 2007 and the results of all subsidiaries for the years then ended.

Subsidiaries are all entities (including special purpose entities) over which the Corporation 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 Corporation controls another entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Corporation. They are deconsolidated from the date that control ceases. In this section, the Corporation together with its subsidiaries are referred to as the Group.

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, plus costs directly attributable to the acquisition. 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 Corporation 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 Corporation.

c) Segment reportingThe Corporation’s primary segment reporting format is geographical. A geographical segment is engaged in providing products or services within a particular economic environment, that are subject to risks and returns, that are different from those of segments operating in other economic environments.

d) Joint VenturesThe 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 expenditureThe 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 nine cost pools: Uganda, Kurdistan Region of Iraq, Russia, Oman, Democratic Republic of Congo (“DRC”), Pakistan, Congo, Malta and Mali during the years under review.

E&E costs related to each licence/prospect are initially capitalised within “Intangible exploration assets’. Such E&E costs may include costs of licence acquisition, technical services and studies, seismic acquisition, exploration drilling and testing and the projected costs of retiring the assets (if any), 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.

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 proven and probable reserves on an entitlement basis.

Proven 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 proven and probable and a 50% statistical probability that it will be less. The equivalent statistical probabilities for the proven component of proven 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; andevidence that the necessary production, transmission and transportation facilities are available or can be made available.

Furthermore:(i) Reserves may only be considered proven and probable if producibility is supported by either actual production or conclusive formation test.

The area of reservoir considered proven 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 proven 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.

•••

Notes to Consolidated Financial Statements continuedYears ended 31 December 2006 and 2007


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 equipmentDevelopment and production assetsThe Group had three cost pools at the development and production stage: Congo, Russia and Oman during the years under review.

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 and the projected cost of retiring the assets.

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.

Other assetsOther 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.

Drilling rig equipment is depreciated using the unit-of-production method based on 2,740 drilling days with a 20% residual value.

The corporate jet is depreciated over its expected useful life of 69 months. Depreciation is charged so as to write off the cost, less estimated residual value of corporate jet 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.

g) Cash and cash equivalentsCash and cash equivalents includes cash on hand, deposits held at call with banks, 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 receivablesTrade 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) InventoriesInventories 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 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) Intangible development costsDevelopment costs are recognised as intangible assets when it is probable that the project will, after considering its commercial and technical feasibility, be completed and generate future economic benefits and its costs can be measured reliably. All other research and development costs are charged to earnings in the year incurred.

k) InvestmentsThe 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’.

Financial assets at fair value through the income statementFinancial 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 gains/(losses) on other financial assets’ in the year in which they arise.

Available-for-sale financial assetsAvailable-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 and non-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.

l) Non current assets held for sale(i) Assets held for saleNon-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.

(ii) Discontinued operationsA discontinued operation is a component of the Group that has been disposed of or is classified as held for sale and represents a separate major line of business or geographical area of operations, or is part of a single coordinated plan to dispose of such a line of business or area of operations, or is a subsidiary acquired exclusively with a view to resale. The earnings from discontinued operations are presented separately on the face of the income statement.



m) Trade and other payablesThese amounts represent liabilities for goods and services provided to the Group prior to the end of the financial year which are unpaid.

n) BorrowingsBorrowings 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 fair value of the derivative liability component (see also 1 (q)) is determined using a Black-Scholes option pricing model, and this amount is recorded as a liability.

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.

o) Borrowing costsBorrowing 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 2007, this was 10.70% (31 December 2006—2.64%).

p) ProvisionsAsset retirement obligationsProvision 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 increase due to changes in the estimated future cash flows are capitalised.

q) Derivative financial liabilitiesDerivatives are initially recognised at fair value on the date a derivative contract is entered into and are subsequently remeasured to their fair value at each reporting date. Changes in the fair value are recognised immediately in the income statement.

r) Revenue recognitionRevenue from the sale of petroleum and natural gas is recorded when the significant risks and rewards of ownership of the product is transferred to the buyer. For sales of oil and gas this is usually when legal title passes to the external party. Interest income is recognised on a time proportion basis using the effective interest method.

Drilling services revenue relates to the provision of drilling services in respect of the drilling rig.


s) Income taxesCurrent 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. 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 liability 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.

t) Foreign currency translationItems included in the financial statements of each of the Corporation’s consolidated subsidiaries are measured using the currency of the primary economic environment in which the subsidiary operates (“the functional currency”). The Corporation’s consolidated financial statements are presented in US dollars, which is the Corporation’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, except when they are deferred in equity as part of or as a hedge of the net investment in a foreign operation.

The results and financial position of all the Corporation’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); andiii) all resulting exchange differences are recognised as income and 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 or any borrowings hedging forming part of the net investment are repaid, 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.

u) Share-based compensation plansThe Group applies the fair value method of accounting to all equity classified share-based compensation arrangements for both employees and non-employees. Compensation cost of equity classified awards to employees are measured at fair value at the grant date and recognised over their vesting period 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, and periodically remeasured to fair value until the non-employees’ performance is complete, and recognised over their vesting period with a corresponding increase to contributed surplus. Upon the exercise of the award, consideration received is recognised in equity. See note 22.



v) Share capitalCommon 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 Corporation reacquires its own equity instruments the cost is deducted from equity and the associated shares are cancelled.

w) Earnings per shareBasic earnings per share is calculated by dividing the profit attributable to equity holders of the Corporation by the weighted average number of Common Shares outstanding during the financial period.

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 Common Shares and the weighted average number of shares assumed to have been issued for no consideration in relation to dilutive potential Common 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. In all cases, the weighted average number of shares used has been adjusted to reflect the effective 1 for 10 share split that took place as part of the corporate reorganisation described in note 27.

x) New accounting standards and interpretationsCertain new accounting standards and interpretations have been published that are not mandatory for the year ended 31 December 2007. The Corporation’s assessment of the impact of these new standards and interpretations which have not been adopted is set out below.

i) IFRS 8, “Operating segments’ (effective from 1 January 2009), replaces IAS 14 and aligns segment reporting with the requirements of the US standard SFAS 131, “Disclosures about segments of an enterprise and related information’. The new standard requires a “management approach’, under which segment information is presented on the same basis as that used for internal reporting purposes. The expected impact is still being assessed by management, but is expected to only impact the disclosures of the Group.

The following standards are assessed not to have any impact on the Corporation’s financial statements:

i) IAS 23 (Amendment), “Borrowing costs’ (effective from 1 January 2009), requires the Group to capitalise borrowing costs directly attributable to the acquisition, construction or production of a qualifying asset (one that takes a substantial period of time to get ready for use or sale) as part of the cost of that asset. The Group currently applies the capitalisation approach to borrowing costs.

ii) IFRIC 11, “IFRS 2—Group and treasury share transactions’ (effective from 1 January 2008), provides guidance on whether share-based transactions involving treasury shares or involving group entities (for example, options over a parent’s shares) should be accounted for as equity-settled or cash-settled share-based payment transactions in the stand-alone accounts of the parent and group companies.

iii) IFRIC 12, “Service concession arrangements’ (effective from 1 January 2008), applies to contractual arrangements whereby a private sector operator participates in the development, financing, operation and maintenance of infrastructure for public sector services.

iv) IFRIC 13, “Customer loyalty programmes’ (effective from 1 July 2008), clarifies that where goods or services are sold together with a customer loyalty incentive (for example, loyalty points or free products), the arrangement is a multiple element arrangement and the consideration receivable from the customer is allocated between the components of the arrangement using fair values.

v) IFRIC 14, “IAS 19—The limit on a defined benefit asset, minimum funding requirements and their interaction’ (effective from 1 January 2008), provides guidance on assessing the limit in IAS 19 on the amount of the surplus that can be recognised as an asset. It also explains how the pension asset or liability may be affected by a statutory or contractual minimum funding requirement.

The following amendments have been published, but have not been applied in these financial statements:

i) IFRS 2 (Amendment), Share-based payment—Vesting Conditions and Cancellations: effective for accounting periods commencing on or after 1 January 2009;

i) IFRS 3 (Amendment) Business Combinations: effective for accounting periods commencing on or after 1 July 2009;iii) IAS 1 (Amendment), Presentation of Financial Statements: effective for accounting periods commencing on or after 1 January 2009;iv) IAS 27 (Amendment), Consolidated and Separate Financial Statements: effective for accounting periods commencing on or after 1 July 2009.

The directors do not anticipate that the adoption of these amendments will have a material impact on the Group’s financial statements in the period of initial application.


2 Risk managementThe 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 riskForeign exchange risk arises when transactions and recognised assets and liabilities of the Group entity concerned are denominated in a currency that is not the Corporation’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 2007.

At 31 December 2007, if the Canadian dollar had strengthened/weakened by 10% against the US dollar with all other variables held constant, the loss for the year would have been $2,978,702 (31 December 2006: $125,982) 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. Profit is more sensitive to movement of Canadian/US dollar exchange rates in 2007 than 2006 because of significantly higher general and administrative expenses in 2007 in comparison with 2006.

At 31 December 2007, if the Russian rouble had strengthened/weakened by 10% against the US dollar with all other variables held constant, the loss for the year would have been ($329,361) (31 December 2006: ($236,730)) 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 2007, if the GB pound sterling had strengthened/weakened by 10% against the US dollar with all other variables held constant, the loss for the year would have been $343,011 (31 December 2006: $730,637) higher/(lower), mainly as a result of foreign exchange gains/losses on translation of GB pound sterling denominated long-term loan.

At 31 December 2007, if the Swiss franc had strengthened/weakened by 10% against the US dollar with all other variables held constant, the loss for the year would have been $(420,274) (31 December 2006: $(286,493)) higher/(lower), mainly as a result of foreign exchange gains/losses on translation of Swiss franc denominated cash at bank.

ii) Commodity price riskThe Corporation is exposed to commodity price risk to the extent that it will sell its entitlement to petroleum, condensate and liquid petroleum gas production on a floating price basis.

The Corporation may consider partly mitigating this risk in the future.

The table below summarises the impact of increases/decreases of the relevant oil/condensate/LPG benchmark on the Corporation’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:

Yearended 31December 2006 2007 $ $

Brentlightcrude – 85,886Condensate 196,926 77,831LPG 144,786 21,759

341,712 185,476

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



iii) Interest rate riskThe Group had fixed rate long-term debt and fixed rate convertible bonds in the years under review, therefore it was not exposed to interest rate risk with respect to these fixed rate borrowings. In October 2007, a wholly-owned subsidiary of the Corporation received a long-term loan of $9,450,000 with a variable rate of LIBOR plus 1.6% (note 17). An increase/decrease of LIBOR by 1% would result in an increase/decrease of the Corporation’s loss for the year of $17,325.

iv) Credit riskAll of the Corporation’s production was derived from the Republic of Congo, Russia and Oman. In 2006 and 2007, the Corporation sold all of its production, at any point in time, in each country to a single customer for each commodity. Accordingly, substantially all the Corporation’s accounts receivables from petroleum and natural gas sales were from a maximum of four customers during these years.

Debtors of the Corporation are subject to internal credit review to minimise the risk of non-payment. The Corporation 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.

v) Liquidity riskLiquidity 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 Corporation’s current operational and investment cash flow requirements.

Management monitors rolling forecasts of the Corporation’s liquidity reserve on the basis of expected cash flow.

The Group had available cash of $230 million at 31 December 2007. Based on its current plans and knowledge, its projected capital expenditure and operating cash requirements, the Group projects available cash at 31 December 2008 of approximately $122 million.

The Corporation’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 note 25.

b) Capital risk managementThe Corporation’s objectives when managing capital are to safeguard the Corporation’s ability to continue as a going concern in order to provide returns for shareholders and benefits for other stakeholders and to maintain an optimal capital structure to reduce the cost of capital.

The Corporation 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’ and “trade and other payables’ 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.

Asat31December 2006 2007 Notes $ $

Totalborrowings 104,047,406 216,434,761Lesscashandcashequivalents 15 (46,861,146)(230,089,323)

Netdebt(cash) 57,186,260 (13,654,562)

Totalequity 42,726,467 193,193,432

Totalcapital 99,912,727 193,193,432

Gearingratio 57% 0%

This decrease in the gearing ratio during 2007 resulted primarily from the issue of shares (note 19).


3 Critical accounting estimates, assumptions and judgementsIn the process of applying the Corporation’s accounting policies, which are described in note 1, 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 exploration and evaluation costsUnder 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; andiv) sufficient data exist 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, and (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.

b) Reserve estimatesEstimates of recoverable quantities of proven 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 instrumentsThe 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 instrumentsThese comprise investments in equity and debt securities, trade and other receivables, cash and cash equivalents, loans and borrowings and trade and other payables. Non-derivative financial instruments are recognised initially at fair value plus, for instruments not at fair value through profit or loss, any directly attributable transaction costs.

Fair value 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) DerivativesDerivatives are recognised initially at fair value; attributable transaction costs are recognised in the profit or loss 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).

iii) Compound financial instrumentsCompound financial instruments issued by the Group comprise convertible bonds that can be converted to share capital at the option of the holder, and the number of shares to be issued does not vary with changes in their fair value.

The convertible bonds are separated into liability and derivative liability components (being the bondholders’ conversion option). The liability component of a compound financial instrument is recognised initially at fair value, determined by reference to market interest rates for equivalent bonds which do not contain conversion features. Subsequent to initial recognition, the liability component is measured at amortised cost using the effective interest method. The fair value of the derivative liability component is determined using a Black-Scholes option pricing model and this amount is recorded as a liability. The Black-Scholes model contains assumptions and determinations pertaining to volatility, risk free interest rates, and the terms of the options.

4 Segment informationThe Group has a single class of business which is international exploration, development and production of petroleum oil and natural gas.

The Group operates in a number of geographical areas based on location of operations and assets, being Russia, Oman, Uganda, DRC, Congo, Kurdistan Region of Iraq, Pakistan, Malta and Mali.

Yearended31December2006 Depreciation, External Segment Total Total Capital depletionand revenue result assets liabilities additions amortisation $ $ $ $ $ $

Russia – (3,698) 23,395,149 150,324 12,830,190 –Oman 3,938,512 716,322 10,439,341 642,607 5,226,268 807,424Uganda1 2,895,727 428,129 46,537,931 7,311,956 14,934,054 176,013DRC – (51,552) 35,468 – 35,468 –Congo2 5,762,283 12,449,190 5,157,646 – 2,610,699 843,562KurdistanRegionofIraq3 – (3,556,202) – – – –Pakistan – (715,776) – – – –Unallocated–Corporate 1,336,351 (37,634,168) 61,208,338 95,942,519 1,510,919 368,550

13,932,873 (28,367,755) 146,773,873 104,047,406 37,147,598 2,195,549


Yearended31December2007 Depreciation, External Segment Total Total Capital depletionand revenue result assets liabilities additions amortisation $ $ $ $ $ $

Russia 1,717,717 (2,653,941) 46,384,681 2,874,575 24,306,477 558,604Oman 1,991,786 1,027,069 13,817,039 331,379 4,408,453 370,868Uganda1 – (38,359) 92,398,347 6,036,508 32,993,911 –DRC – – 1,296,220 – 710,751 –KurdistanRegionofIraq – (2,273,220) 1,622,934 – 1,622,934 –Pakistan – (311,778) 952,406 – 952,406 –Malta – (32,846) 6,517,779 – 6,517,779 –Mali – (159,947) 213,145 – 213,146 –Unallocated–Corporate 2,648,691 (78,722,573) 246,425,642 207,192,299 11,765,343 962,818

6,358,194 (83,165,595) 409,628,193 216,434,761 83,491,200 1,892,290

1 Uganda includes exploration activity as well as revenue and operating profit from drilling services.2 Revenues and expenses from Congo have been included as discontinued operations in the income statement.3 Kurdistan Region of Iraq information was not a separate geographic segment as defined in note 1(e) until October 2007. However, information was presented for clarity.

Exploration expenditures in respect of E&E assets relate to pre-licence costs which are expensed in accordance with IFRS 6.

5 Other finance costs Yearended 31December 2006 2007 $ $

Interestonlong-termdebt 532,918 678,199Interestonconvertiblebonds 4,602,740 12,573,959Accretionofconvertibledebt 860,895 3,601,636Accretionofassetretirementobligation – 7,636

5,996,553 16,861,430Amountcapitalised (1,354,427) (6,173,210)

Financecostsexpensed 4,642,126 10,688,220

Finance costs are capitalised in various balance sheet categories.

6 Income tax expenseThe Group is subject to income taxes in Canada, Uganda and Russia. All of the Group’s operating activities are outside of Canada. In Oman, the effective tax rate is nil as in this jurisdiction the Group is subject to a production sharing agreement.

In Canada, Uganda and Russia, the Group has available tax deductions of $37,624,932 (31 December 2006: $13,190,581) and tax losses of $77,749,022 (31 December 2006: $56,018,930), of which $29,006,996 expires from 2008 to 2027, and the remaining $48,742,026 does not have an expiry period. No deferred tax assets have been recognised for the benefit of the Canadian tax deductions and Canadian and Russian tax losses because realisation of the deferred tax assets in the foreseeable future is not sufficiently likely.



Factors affecting current tax charge for the year: Yearended 31December 2006 2007 $ $

Netlossbeforetax (28,367,755) (83,165,595)Standardtaxrate 34.70% 32.12%Taxonlossatstandardrate (9,843,611) (26,712,789)Changeinstatutorytaxrate 468,887 1,165,447Effectivelowertaxratesinforeignjurisdiction 192,485 215,472Expensesnotdeductiblefortaxpurposes 7,882,589 22,010,883Foreignexchangegains(losses) 84,624 (687,333)Effectoftaxlossesnotrecognised 1,215,026 4,008,320

Currenttaxcharge – –

Asat31December 2006 2007 $ $

Thebalancecomprisestemporarydifferencesattributableto:Availabletaxlossesanddeductions 16,639,282 24,011,654

Deferredtaxasset(unrecognised) 16,639,282 24,011,654

7 Staff costsThe average number of employees (including executive directors) employed by the Group during the year, analysed by category was:

Yearended 31December 2006 2007

Canada – 1Switzerland 3 3Russia 25 41UnitedKingdom 13 14Uganda 21 21KurdistanRegionofIraq 7 5SouthAfrica 3 4

Total 72 89

The aggregate payroll expenses of those employees was as follows: Yearended 31December 2006 2007 $ $

Salariesandothershort-termbenefits 9,726,603 12,871,099Share-basedcompensation 1,765,681 39,001,420

Totalemployeeremuneration 11,492,284 51,872,519

Capitalisedportionoftotalremuneration 4,211,166 14,217,495


Key management compensation was: Yearended 31December 2006 2007 $ $

Salariesandothershort-termbenefits 4,111,948 4,263,647Share-basedcompensation 753,174 28,313,954

4,865,122 32,577,601

8 Discontinued operationsOn 6 June 2006, the Group entered into an agreement to sell Heritage Congo Limited which held all of the Group’s interests in the Noumbi Exploration Permit and the Kouakouala A and B licences in the Republic of Congo (“Congo”) to Afren PLC, subject to a number of conditions precedent and pre-emption rights. During 2006, the Group’s partners in the Kouakouala A and B licences exercised their pre-emption rights in respect of the sale of these assets. Accordingly, the Group sold these assets to three separate public entities later in 2006.

On 22 November 2006, the Group completed the sale of Heritage Congo Limited, which held a 14% working interest in the Noumbi Exploration Permit, to Afren PLC (“Afren”) for the following consideration:

a) Cash of $21,000,000; andb) 1,500,000 Afren warrants, with a term of five years and an exercise price of £0.60 per share. The fair value of the Afren warrants, determined

by using the Black-Scholes model, was $719,380 at the date of sale (note 13).

On 18 January 2007, the Group finalised the statement of adjustments relating to the sale of its 25% working interest in the Kouakouala A and 30% working interest in the Kouakouala B licence in Congo to the other partners in the licences, Maurel et Prom and Burren Energy, for the following consideration:

a) Cash of $6,052,515; andb) An overriding royalty of 15% over a 30% working interest in the Kouakouala B licence in relation to the Mengo field. The Mengo field is not in

production.

All of the disposition agreements were completed by 12 December 2006. The gain on disposal of all of the Group’s interests in the Congo was $9,200,700 in 2006. As at 31 December 2006, accounts receivable included $5,157,646 relating to the unpaid portion of the sales proceeds, which was received in January 2007.

The results of operations in Congo have been classified as earnings from discontinued operations. The following table provides additional information with respect to the amounts included in the earnings from discontinued operations.

Periodended 12December 2006 $

RevenuePetroleumandnaturalgas 5,116,368Other 645,915

5,762,283

ExpensesOperating 902,776Royalties 767,455Depletion,depreciationandaccretion 843,562

2,513,793

3,248,490



The following table provides additional information with respect to the amounts included in the balance sheet as assets of the disposal group held for sale. Periodended 12December 2006 Notes $

AssetsNon-current assetsIntangibleexplorationassets 10 8,323,966Property,plantandequipment 12 11,638,420

19,962,386

LiabilitiesCurrent liabilitiesTradeandotherpayables 971,421

Non-currentProvisions 18 419,770

1,391,191

Net assets 18,571,195

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

Yearended 31December 2006 $

ConsiderationreceivedorreceivableCash 27,052,515Warrants 719,380

Totaldisposalconsideration 27,771,895Less:carryingamountofnetassetssold (18,571,195)

Gainondisposal 9,200,700

9 DisposalsOn 9 March 2007, the Group disposed of its previously consolidated 65% interests in Natural Pipelay Worldwide Limited (“NPWL”) and Naturalay Technologies Limited (“Naturalay”) in consideration for 605,000 common shares in a private company named SeaDragon. The fair value of the common shares consideration received of $2,420,000, which was based on the most recent private placement by SeaDragon in October 2006, resulted in a gain of $1,077,132 on the disposal. The Group’s CFO is a director and CFO of SeaDragon.

Below is an analysis of the assets and liabilities of NPWL and Naturalay as at 9 March 2007, the date of sale completion:

$

AssetsIntangibledevelopmentcosts 1,642,868

LiabilitiesTradeandotherpayables 300,000

Net assets 1,342,868


The gain on disposal of the previously consolidated subsidiary has been derived as follows: $

Considerationreceivedorreceivable Fairvalueofshares 2,420,000Totaldisposalconsideration 2,420,000

Less:carryingamountofnetassetssold 1,342,868

Gainondisposalofsubsidiaries 1,077,132

10 Intangible exploration assets 31December 2006 2007 Notes $ $

Balance-beginningofyear 43,503,704 54,767,332Exchangedifferences 64,121 251,338Additions 20,656,473 57,337,190Assetstransferredtoproperty,plantandequipment 12 (1,133,000) (9,493,106)Assetstransferredtodisposalgroupheldforsale 8 (8,323,966) –

Balance–endofyear 54,767,332 102,862,754

No assets have been pledged as security.

The balances at the end of the years are as follows: 31December 2006 2007 $ $

Russia 6,437,022 18,019,174Oman 7,048,524 550,867Uganda 41,246,318 74,240,229DRC 35,468 746,219KurdistanRegionofIraq – 1,622,934Pakistan – 952,406Malta – 6,517,779Mali – 213,146


11 Intangible development costs 31December 2006 2007 Notes $ $

Cost 1,574,039 –Accumulatedamortisation – –

Netbookamount 1,574,039 –

Netbookamount—beginningofyear 1,187,371 1,574,039Additions—internaldevelopment 386,668 68,829Disposals—saleofsubsidiaries 9 – (1,642,868)

Netbookamount—endofyear 1,574,039 –

Intangible development costs, such as personnel and production expenses, are related to the development of the Buoyant Drum Lay System (“Pipelay System”). As the Pipelay System development was not complete, amortisation had not commenced before the disposal of the subsidiaries.



12 Property, plant and equipment Yearended 31December 2006 2007 Notes $ $

Petroleumandnaturalgasinterests 18,091,216 42,056,745Drillingandbargeequipment 3,544,969 3,544,969Landandbuilding 11,984,701 11,984,701Other 2,687,590 14,452,933

Property,plantandequipment,atcost 36,308,476 72,039,348Accumulateddepletionanddepreciation (4,121,378) (7,813,430)

Net book amount 32,187,098 64,225,918

Reconciliation of movements during the yearPetroleum and natural gas interestsCost-beginningofyear 13,255,901 18,091,216Accumulateddepletionanddepreciation–beginningofyear (3,303,490) (3,051,966)

Net book amount – beginning of year 9,952,411 15,039,250

Netbookvalue–beginningofyear 9,952,411 15,039,250Exchangedifferences 103,065 335,094Additions 14,128,855 14,137,329Assetstransferredfromintangibleexploration 10 1,133,000 9,493,106Assetstransferredtodiscontinuedoperations 8 (8,638,125) –Depletionanddepreciation (1,639,956) (929,472)

Net book amount – end of year 15,039,250 38,075,307

Cost–endofyear 18,091,216 42,056,745Accumulateddepletionanddepreciation–endofyear (3,051,966) (3,981,438)


Drilling and barge equipmentCost–beginningofyear 2,693,618 3,544,969Accumulateddepletionanddepreciation–beginningofyear (171,728) (347,741)


Netbookamount–beginningofyear 2,521,890 3,197,228Additions 851,351 –Depletionanddepreciation (176,013) –Impairment – (1,799,762)


Cost–endofyear 3,544,969 3,544,969Accumulateddepletionanddepreciation–endofyear (347,741) (2,147,503)

Net book amount—end of year 3,197,228 1,397,466

Land and buildingCost—beginningofyear 11,984,701 11,984,701Accumulateddepletionanddepreciation–beginningofyear (173,973) (313,151)


Netbookamount–beginningofyear 11,810,728 11,671,550Depletionanddepreciation (139,178) (139,178)



Yearended 31December 2006 2007 Notes $ $

Cost–endofyear 11,984,701 11,984,701Accumulateddepletionanddepreciation–endofyear (313,151) (452,329)


OtherCost–beginningofyear 1,176,671 2,687,590Accumulateddepletionanddepreciation–beginningofyear (179,148) (408,520)

Net book amount – beginning of year 997,523 2,279,070

Netbookamount–beginningofyear 997,523 2,279,070Additions 1,510,919 11,765,343Depletionanddepreciation (229,372) (823,640)


Cost–endofyear 2,687,590 14,452,933Accumulateddepletionanddepreciation–endofyear (408,520) (1,232,160)


The corporate office which represents the land and building category serves as security for a long-term loan (note 17).

The carrying value of the drilling rig was written down to its estimated fair value based on third party quoted sales prices. This resulted in an impairment write down of $1,799,762 recognised in the income statement during the year ended 31 December 2007.

13 Other financial assets 31December 2006 2007 Notes $ $

Investmentinwarrants 8 914,558 1,821,201Investmentinunlistedsecurities 9 – 3,223,000

914,558 5,044,201

The investment in Afren warrants is classified as held for trading. The investment in unlisted securities represents common shares in a private company named SeaDragon, which is classified as available-for-sale.

There were no other disposals (see note 9) or impairment losses on held for trading or available-for-sale financial assets in the reporting years under these financial statements.

The fair value of unlisted shares of SeaDragon is based on the most recent private placement of SeaDragon on 26 October 2006. The directors consider that there has been no change in the fair value of these shares since this date.



14 Trade and other receivables 31December 2006 2007 $ $

Tradereceivables 890,662 318,417Otherreceivables 8,948,844 6,440,844

9,839,506 6,759,261

Trade and other receivables are due within 30 days from the invoice date. No interest is charged on the receivables. The carrying amount of trade and other receivables approximates 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 2007, trade receivables of $6,759,261 (31 December 2006: $9,839,506) were neither past due nor impaired. These relate to a number of independent customers for whom there is no recent history of default. The ageing analysis of these trade and other receivables is as follows: 31December 2006 2007 $ $

Upto3months 9,703,000 4,964,4803to6months 136,506 1,794,781

9,839,506 6,759,261

Trade and other receivables analysed by category are as follows:

31December 2006 2007 $ $

USdollars 7,970,228 4,050,828Russianroubles 1,495,891 2,064,084Swissfrancs 349,347 528,035Canadiandollars – 100,032GBpoundssterling 24,040 16,282

9,839,506 6,759,261

15 Cash and cash equivalents 31December 2006 2007 $ $

Cashatbankandinhand 46,861,146 230,089,323

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


16 Trade and other payables 31December 2006 2007 $ $

Tradepayables 9,253,320 14,055,027Otherpayablesandaccruedliabilities 3,462,061 10,591,504

12,715,381 24,646,531

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 their fair value.

17 Borrowings 31December 2006 2007 $ $

Non-current borrowingsConvertiblebonds–unsecured 54,715,050 137,213,274Non-currentportionoflong-termdebt 8,409,793 17,040,427

63,124,843 154,253,701

Long-term debt – securedCurrent 147,720 623,640Non-current 8,409,793 17,040,427

8,557,513 17,664,067

2006 convertible bondsOn 27 March 2006, the Corporation issued 600 unsecured convertible bonds each with a par value of $100,000 for aggregate proceeds of $60,000,000. Issue costs amounted to $3,000,000 resulting in net proceeds of $57,000,000. The bonds bear a coupon rate of 10% per annum and a term of five years and one day. On maturity, any bonds outstanding are redeemed for cash. At the option of the holders, the bonds are convertible, in whole or in part, into Common Shares at a price of US$18.00 per share at any time during the term of the bonds. The Corporation could redeem, in whole or part, the bonds for cash at any time on or before 28 March 2007 at 150% of par value. Pursuant to the bond agreement, the Group is required to maintain an equity to debt, net of cash and cash equivalent, ratio of no less than 0.65:1.00. The proceeds of the bond can be employed for development of the Zapadno Chumpasskoye field in Russia and for general corporate purposes.

The bonds included conversion features which in certain circumstances could be settled in cash and so these features represent a derivative financial instrument which is classified as a liability.

The fair value of the liability component of the bonds (net of issue costs) was estimated at $53,862,435. The fair value of the derivative financial liability representing the bondholders’ conversion feature (note 23) (net of issue costs) was estimated at $3,137,565 on 27 March 2006. The difference between the $60,000,000 principal amount due on maturity and the recorded liability component is accreted and recorded as finance costs using the effective interest method. The derivative financial instrument is recorded at fair value with resulting gains and losses recorded in finance income and costs.

On 17 January 2007, the Corporation gave notice that it had exercised its option to redeem 550 outstanding bonds at 150% of par value for total proceeds of $82,500,000 plus accrued interest which was paid on 28 March 2007. This resulted in the recognition of a loss of $7,155,622 on the redemption, net of transaction costs, on the recorded liability and derivative liability. Previously, early in 2007, 50 bonds, with a total par value of $5,000,000, had been converted into 277,778 Common Shares. As a result of this conversion, a total amount of $7,104,327 was transferred to Share Capital from the convertible bonds and derivative liability of the convertible bonds.



2007 convertible bondsOn 16 February 2007, the Corporation raised $165,000,000 by completing the private placement of convertible bonds. Issue costs amounted to $6,979,268 resulting in net proceeds of $158,020,732. The Corporation issued 1,650 unsecured convertible bonds at par, which have a maturity of five years and one day and an annual coupon of 8.00% payable semi-annually on 17 August and 17 February of each year. The bondholders had the right to convert the bonds into Common Shares at a price of $47.00 per share at any time. The Corporation 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. Proceeds were used to finance the redemption of the outstanding of convertible bonds, issued on 26 March 2006, at a premium of 150% and for general corporate funding purposes.

Bondholders have a put option requiring the Corporation to redeem the bonds at par, plus accrued interest, in the event of a change of control of the Corporation or revocation or surrender of the Zapadno Chumpasskoye licence in Russia. 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 the bondholder, the amount of which depends upon the date of redemption and market value at the date of any change of control event.

The bonds included conversion features which in certain circumstances could be settled in cash and so these features represent a derivative financial instrument which is classified as a liability.

The fair value of the liability component of the bonds (net of issue costs) was estimated at $140,154,215. The fair value of the derivative financial liability representing the bondholders’ conversion feature (note 23) (net of issue costs) was estimated at $17,866,517 on 16 February 2007. The difference between the $165,000,000 due on maturity and the initial liability component is accreted using the effective interest method and is recorded as finance costs. The derivative financial instrument is recorded at fair value with resulting gains and losses recorded in finance income and costs.

In July 2007, a bondholder with US$7 million of bonds gave notice of the exercise of 70 bonds and received 148,937 Common Shares in August 2007. As a result of this conversion, $8,944,487 was transferred to Share Capital from convertible bonds, derivative liability component of convertible bonds and accrued liabilities.

Pursuant to the terms of the convertible bond, the Corporation is required to provide security, in a separate escrow account, equal to the first three interest payments in the total amount of $19,841,551. The escrow account is reduced for each interest payment such that it will be $nil on 17 August 2008. In August 2007, the first interest payment of $6,355,108 was made from the escrow account. Cash in the escrow account, including accrued interest income, is included in cash and cash equivalents.

Long-term debtIn January 2005, a wholly-owned subsidiary of the Corporation received a sterling denominated loan of £4.5 million to refinance the acquisition of a corporate office. Interest on the loan is fixed at 6.515% for the first five years and is then variable at a rate of London Interbank Offered Rate (“LIBOR”) plus 1.35%. The loan, which is secured on the property, is scheduled to be repaid by 240 installments 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 (£1,860,000). The current principal balance outstanding as at 31 December 2007 was $8,519,037 (£4.3 million) (31 December 2006: $8,557,513 (£4.4 million)).

In October 2007, a wholly-owned subsidiary of the Corporation received a loan of $9,450,000 to refinance the acquisition of the corporate jet. Interest on the loan is variable at a rate of LIBOR plus 1.6%. The loan, which is secured on the corporate jet, is scheduled to be repaid by 19 consecutive quarterly installments of principal. Each instalment equals to $117,500 with the final installment being $7,217,500. The Corporation provided a corporate guarantee to the lender.

Fair valuesAt 31 December 2006 and 31 December 2007, the fair values of borrowings are approximately equal to their carrying amounts as the facilities bear interest at market rates of interest.


18 ProvisionsThe 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 $573,657, which is expected to be incurred in the period from 2012 to 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 2007 (2006: 10%).

A reconciliation of the asset retirement obligation is provided below: 31December 2006 2007 Notes $ $

Balance – beginning of year 434,849 62,322Additions 62,322 97,737Revision(duetochangeindiscountrate) (41,170) 3,204Accretionexpense 5 26,091 7,636Liabilitiestransferredtodiscontinuedoperations 8 (419,770) –

62,322 170,899

19 Share capitalThe authorised share capital has unlimited number of Common Shares without par value.

31December2006 31December2007 Number Amount Number Amount Notes $ $

Balance–beginningofyear 21,865,701 22,854,418 22,009,034 24,580,984Issueofshares – – 3,000,000 175,963,414Issuedonexerciseofstockoptions 22 143,333 1,726,566 52,000 1,079,031Issuedonconversionofbonds 17 – – 426,715 16,048,814

Balance–endofyear 22,009,034 24,580,984 25,487,749 217,672,243

On 14 November 2007, the Corporation closed an equity offering of 3,000,000 Common Shares which were issued at a price of Cdn$60.50 per Common Share for gross proceeds of $186,436,800 (Cdn$181.5 million) to the Company. Share issue costs were $10,473,386. In addition, Albion Energy Limited sold 3,000,000 Common Shares at a price of Cdn$60.50 per Common Share for gross proceeds of $186,436,800 (Cdn$181.5 million). The ultimate owner of Albion Energy is Mr. Anthony Buckingham, a director and Chief Executive Officer of the Corporation.

Subsequent to the year-end there was a 1 for 10 share split that took place as part of the corporate reorganisation described in note 27.



20 Reserves and retained earnings (deficit)(a) Reserves 31December 2006 2007 $ $

Available-for-saleinvestmentsrevaluationreserve – 168,000Foreigncurrencytranslationreserve (4,003) 430,580

(4,003) 598,580Share-basedpaymentsreserve 2,641,061 42,579,779

2,637,058 43,178,359

MovementsAvailable-for-sale investments revaluation reserveBalance–beginningofyear – –Revaluation – 168,000

Balance–endofyear – 168,000

Foreign currency translation reserveBalance–beginningofyear – (4,003)Currencytranslationdifferencesarisingduringyear (4,003) 434,583

Balance–endofyear (4,003) 430,580Share-basedpaymentsreserveBalance–beginningofyear 973,956 2,641,061Compensationcosts–optionsissued 2,074,727 40,491,888Transfertosharecapitalonexerciseofoptions (407,622) (409,363)Optionsforfeited – (143,807)


(b) Retained earnings (deficit) 31December 2006 2007 $ $

Balance–beginningofyear 43,876,180 15,508,425PremiumonrepurchaseandcancellationofCommonShares – –Netlossfortheyear (28,367,755) (83,165,595)

Balance–endofyear 15,508,425 (67,657,170)

(c) Nature and purpose of reservesi) Available-for-sale investments revaluation reserveChanges 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, as described in note 1(k). Amounts are recognised in profit and loss when the associated assets are sold or impaired.

ii) Foreign currency translation reserveExchange differences arising on retranslation of the foreign controlled entity are taken to the foreign currency translation reserve, as described in note 1(t). The reserve will be recognised in the income statement when the net investment is disposed.

iii) Share-based payments reserveThe share-based payments reserve, as described in note 1 (u), is used to recognise the fair value of options issued, but not exercised, to employees.


21 Loss per shareThe following table summarises the weighted average Common Shares used in calculating net earnings per share: Yearended 31December 2006 2007

Weighted average Common SharesBasic 219,173,630 227,504,282Diluted 220,955,070 237,562,982 The weighted average number of shares has been adjusted to reflect the effective 1 for 10 share split that took place as part of the corporate reorganisation described in note 27. The reconciling item between basic and diluted weighted average number of Common Shares is the dilutive effect of stock options and convertible bonds. A total of nil options (31 December 2006: 5,350,000) and 33,617,020 of shares relating to the convertible bonds (31 December 2006: 33,333,333) were excluded from the above calculation, as they were anti-dilutive.

22 Share-based paymentsStock optionsThe Corporation has a stock option plan whereby certain directors, officers, employees and consultants of the Group may be granted options to purchase Common 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.

Common Share options outstanding and exercisable:

31December2006 31December2007 Number Average Number Average ofoptions exerciseprice ofoptions exerciseprice Notes Cdn$ Cdn$

Balance–beginningofyear 425,000 9.57 831,667 21.63Granted 550,000 27.98 1,723,201 34.05Exercised 19 (143,333) 10.27 (52,000) 13.13Forfeited – – (41,667) 9.70

Balance–endofyear 831,667 21.63 2,461,201 30.71

Exercisable–endofyear 350,002 18.89 1,569,301 28.12

Numberofoptions RemainingExerciseprice(Cdn) Outstanding Exercisable life(years)

$9.70 210,000 210,000 2.39$16.60 15,000 10,000 3.48$22.00–$29.14 1,833,701 1,215,134 3.95$50.06–$51.25 402,500 134,167 4.93

2,461,201 1,569,301 3.97

During the year ended 31 December 2007, the weighted average share price at the date of option exercise was Cdn$46.12 (31 December 2006: Cdn$19.58).

The fair value of each stock option grant on the date of grant was estimated using the Black-Scholes option pricing model with the following weighted average assumptions and results. The fair value of stock options is amortised over the vesting year of the option.



31December 2006 2007

Weighted average assumption and resultsRiskfreeinterestrate(%) 4.13 4.25Volatility(%) 42.99 46.90Dividendyield(%) – –Expectedlife(years) 3.42 3.00Grantdatefairvalue(Cdn$) 8.80 29.28

23 Derivative financial liability 31December 2006 2007

Convertiblebond–conversionoption 27,997,140 36,739,990

For details of the convertible bond, refer to note 17.

The fair value of the convertible bonds conversion option has been estimated using the Black-Scholes option pricing model at each period end, with changes in the fair value of the conversion option recognised in income during the period. The expected life of the conversion option has been adjusted to reflect the bondholders’ put option and the Corporation’s redemption option as detailed in note 17.

24 Related party transactionsDuring the year ended 31 December 2007, general and administrative expenses included an advisory fee of $1,878,560 (31 December 2006: $1,494,317) charged by Mr. Anthony Buckingham, a director of the Corporation who was appointed CEO on 6 October 2006.

Mr. Atherton, a director of the Corporation, is also a director and CFO of SeaDragon. The Group acquired 605,000 common shares of SeaDragon on 9 March 2007 through the sale of its 65% interest in Pipelay and Naturalay Technologies.

25 Commitments and contingenciesHeritage’s net share of outstanding contractual commitments at 31 December 2007 was estimated at:

Lessthan After Total 1year 1-3years 4-5years 5years $’000 $’000 $’000 $’000 $’000

Long-termdebt 17,662 617 1,234 8,334 7,477Convertiblebonds 158,000 – – 158,000 –

Totalrepaymentsofborrowings 175,662 617 1,234 166,334 7,477

Operatingleases 8,261 148 133 133 7,847Otherlong-termobligations 140,000 40,000 100,000 – –Workprogrammeobligations 121,033 54,766 52,303 13,965 –

Totalcontractualobligations 269,294 94,913 152,436 14,098 7,847 The Corporation 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 Production Sharing Contract (“PSC”) signed with the Kurdistan Regional Government (“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’. On the basis of KRG legal advice, the Directors believe that the PSC is valid and effective pursuant to the applicable laws.

In addition, the DRC work programme pursuant to the DRC PSC cannot be commenced prior to the grant of a Presidential Decree from the DRC government. There can be no assurance that final approval or ratification will ever be received in respect of the DRC PSC or that the pre-agreed fiscal terms will not be re negotiated at a later date by the DRC Government.

Furthermore, the Group received a letter from the chairman of the Management Committee of the National Oil Corporation 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.

26 Non-cash investing and financing activities supplementary information Yearended 31December Notes 2006 2007

Capitalisedportionofshare-basedcompensation (940,000) (9,043,886)Non-cashproperty,plantandequipmentadditionsrelatingtothecapitalisedportionof share-basedcompensation 940,000 9,043,886Non-cashportionofsalesproceedsondisposalofdiscontinuedoperations 719,380 –Receiptofwarrantaspartofthesalesproceedsfromthedisposalofdiscontinuedoperations (719,380) –Dispositionofsubsidiaries 9 – (1,342,868)Gainondisposalofsubsidiaries 9 – (1,077,132)ReceiptofSeaDragonsharesasaproceedsfordisposalofsubsidiaries 9 – 2,420,000ReceiptofSeaDragonsharesasaresultoftheissuanceoftheCorporation’sguaranteefor athirdparty’sdebt – 435,000AccrualofpayablerepresentingthefairvalueoftheCorporation’sguaranteeissuedfora thirdparty’sdebt – (435,000)

27 Subsequent eventsOn 24 March 2008, the Corporation entered into a corporate reorganisation which resulted in a newly incorporated company, Heritage Oil Limited (“Heritage Jersey”), becoming the parent company of the Corporation and its current subsidiaries. Heritage Jersey’s corporate head office is now located in the Channel Islands and Heritage Jersey is subject to the Companies (Jersey) Law 1991 (as amended). In connection with the reorganisation, Heritage Jersey listed its ordinary shares (“Heritage Jersey Shares”) on the Official List of the United Kingdom Listing Authority (the “UKLA”) and trades on the Main Market of the London Stock Exchange plc (the “LSE”) (collectively, “Admission”). The Corporation has delisted its existing Common Shares (“Heritage Shares”) from the Toronto Stock Exchange (the “TSX”) and obtained a listing for a new class of exchangeable shares (the “Exchangeable Shares”) on the TSX. As part of the reorganisation, implemented by way of court-approved plan of arrangement (the “Arrangement”) under the Business Corporations Act (Alberta), the Corporation split its stock such that each existing Heritage Share was exchanged for either ten Heritage Jersey Shares or ten Exchangeable Shares in accordance with the terms of the Arrangement.

On 2 April 2008, the Corporation and Heritage Oil Limited collectively, together with their subsidiaries and affiliates, jointly announced that Articles of Arrangement implementing the previously announced Arrangement involving the Corporation and Heritage Jersey had been filed with the Registrar of Corporations for the Province of Alberta with an effective date of 31 March 2008. As a result, former holders of Common Shares of the Corporation were entitled to either 10 Ordinary Shares of Heritage Jersey or 10 Exchangeable Shares of the Corporation for each Common Share held depending on the elections previously made by such shareholders. Effective at the opening of business on 3 April 2008, the Exchangeable Shares were listed and posted for trading in substitution for the previously listed Common Shares of the Corporation which were delisted at that time. The Exchangeable Shares were also admitted to trading on the Main Market of the LSE on 2 April 2008. Trading of Heritage Jersey shares commenced on the LSE on 31 March 2008.



In connection with this reorganisation Heritage Jersey has agreed that the 2007 convertible bonds outstanding were convertible with shares of Heritage Jersey rather than shares of the Corporation.

On 11 April 2008, Heritage Jersey announced signing of documentation to farm-in to two exploration licences in Tanzania. The licences, known as the Kimbiji and Latham Areas are held under one production sharing agreement (“PSA”). The PSA was awarded by way of a competitive tender process to Petrodel Resources Ltd (“Petrodel”) by the Tanzanian Government in September 2006 with exploration periods of four years, followed by extensions of four years and three years respectively, with the right to a development licence with a term of 25 years. Under the terms of the farm-in agreement with Petrodel, a wholly-owned subsidiary of Heritage Jersey has the right to earn a 70% working interest in the Kimbiji Area, and a 29.9% working interest in the Latham Area. In order to earn the working interests, Heritage will fund all seismic costs of the required work programmes on both blocks, comprising the acquisition of both 2D and 3D seismic data, and the drilling of two exploration wells within the Kimbiji Area. Heritage will be appointed operator upon drilling the second exploration well in the Kimbiji Area. Total exploration costs for the initial exploration term for the two licences are estimated at approximately $17.5 million for the Kimbiji Area and between $5 million and $12 million for the Latham Area.

On 21 April 2008, Heritage Jersey announced the signing of documentation to farm-in to two further exploration licences in Tanzania. The licences, known as the Kisangire and Lukuliro Areas are held under one PSA. Heritage will be appointed as operator. The farm-in agreement and appointment of a wholly-owned subsidiary of Heritage as operator are subject to the approval of the Government of Tanzania. The PSA was originally awarded to Dominion Oil & Gas Limited (“Dominion”) in May 2005, with an exploration period of four years, followed by one extension of four years, a further extension of three years and the right to a development licence with a term of 25 years. Under the terms of the farm-in agreement with Dominion, Heritage has the right to initially earn a working interest of 55% in both the Kisangire and Lukuliro licences. In order to earn the working interests, Heritage will fund all costs to acquire a minimum of 150 kilometres of 2D seismic data and the costs of the first commitment well. Heritage also has an option to earn an additional working interest of 15% thereby increasing its participating interest to 70% by funding 87.5% of the costs of a second well. The minimum exploration expenditure required under the PSA during the first exploration period, which includes seismic acquisition and the drilling of two wells, is $10 million.


28 Explanation of transition to IFRSReconciliation of equity reported under previous Canadian Generally Accepted Accounting Principles (CGAAP) to equity under International Financial Reporting Standards (IFRS):

At the date of transition IFRS – 1 January 2005 Effectof Previous transition CGAAP toIFRS IFRS Notes $ $ $

AssetsNon-current assetsIntangibleexplorationassets (b),(c) – 32,725,642 32,725,642Intangibledevelopmentcosts 1,013,012 – 1,013,012Property,plantandequipment (a),(b),(d),(g) 54,083,097 (32,306,191) 21,776,906

55,096,109 419,451 55,515,560

Current assetsInventories (d) 94,483 24,976 119,459Prepaidexpenses 272,168 – 272,168Tradeandotherreceivables 8,920,963 – 8,920,963Cashandcashequivalents 16,235,523 – 16,235,523

25,523,137 24,976 25,548,113

80,619,246 444,427 81,063,673

LiabilitiesCurrent liabilityTradeandotherpayables 6,397,247 – 6,397,247

Non-current liabilityProvisions 328,553 – 328,553

6,725,800 – 6,725,800

73,893,446 444,427 74,337,873

EquitySharecapital 21,434,168 – 21,434,168Reserves 24,421 – 24,421Retainedearnings (a)(c)(d)(g) 52,434,857 444,427 52,879,284

73,893,446 444,427 74,337,873



At the end of the comparative period under previous CGAAP – 31 December 2005 Effectof Previous transition CGAAP toIFRS IFRS Notes $ $ $

AssetsNon-current assetsIntangibleexplorationassets (b),(c),(f) – 43,503,704 43,503,704Intangibledevelopmentcosts 1,187,371 – 1,187,371Property,plantandequipment (a),(b),(d),(g) 74,729,540 (49,446,988) 25,282,552

75,916,911 (5,943,284) 69,973,627

Current assetsInventories (d) 216,474 35,441 251,915Prepaidexpenses 219,222 – 219,222Tradeandotherreceivables 1,318,450 – 1,318,450Cashandcashequivalents 8,583,321 – 8,583,321

10,337,467 35,441 10,372,908

86,254,378 (5,907,843) 80,346,535

LiabilitiesCurrent liabilitiesTradeandotherpayables 4,438,649 – 4,438,649Borrowings 248,045 – 248,045

4,686,694 – 4,686,694

Non-current liabilitiesBorrowings 7,520,438 – 7,520,438Deferredtaxliabilities (f) 2,346,605 (2,346,605) –Provisions 434,849 – 434,849

10,301,892 (2,346,605) 7,955,287

14,988,586 (2,346,605) 12,641,981

EquitySharecapital 22,854,418 – 22,854,418Reserves (e) 517,209 456,747 973,956Retainedearnings(deficit) (a),(c),(d),(e),(g) 47,894,165 (4,017,985) 43,876,180

71,265,792 (3,561,238) 67,704,554


Reconciliation of loss for the year ended 31 December 2005 Effectof Previous transition CGAAP toIFRS IFRS Notes $ $ $

RevenuePetroleumandnaturalgas 841,766 – 841,766Drillingservices 342,359 – 342,359

1,184,125 – 1,184,125

ExpensesPetroleumandnaturalgas 465,110 – 465,110Drillingrigoperating 196,804 – 196,804Generalandadministrative (e) 5,249,649 456,747 5,706,396Foreignexchangelosses 1,170,906 – 1,170,906Depletion,depreciationandamortisation (c),(d),(g) 536,093 202,537 738,630Explorationexpenditure (a) – 4,517,411 4,517,411Impairmentofunprovedpetroleumandnaturalgasinterest (a) 724,915 (724,915) –

8,343,477 4,451,780 12,795,257

Finance income (costs)Interestincome 330,290 – 330,290Financecosts (491,824) – (491,824)

(161,534) – (161,534)

Loss from continuing operations (7,320,886) (4,451,780) (11,772,666)Earningsfromdiscontinuedoperations (g) 3,521,073 (10,632) 3,510,441

Net loss (3,799,813) (4,462,412) (8,262,225)



Reconciliation of cash flow statement for the year ended 31 December 2005 Effectof Previous transition CGAAP toIFRS IFRS Notes $ $ $

Cash provided by (used in)Operating activitiesNetlossfromcontinuingoperations (a),(c),(d),(e),(g) (7,320,886) (4,451,780) (11,772,666)Itemsnotinvolvingcash Depletion,depreciationandamortisation (c),(d),(g) 536,093 202,537 738,630 Financecosts–accretionexpenses – – – Foreignexchangelosses 480,253 – 480,253 Share-basedcompensation (e) 625,365 456,747 1,082,112 Impairmentofunprovedpetroleumandnaturalgasproperties (a) 724,915 (724,915) – Increaseintradeandotherreceivables (258,398) – (258,398) Decreaseinprepaidexpenses 1,921,678 – 1,921,678 Increaseininventory (98,878) – (98,878) Increaseintradeandotherpayables 52,946 – 52,946

(3,336,912) (4,517,411) (7,854,323)Discontinuedoperations 4,034,035 – 4,034,035

697,123 (4,517,411) (3,820,288)

Investing activitiesProperty,plantandequipmentexpenditures (a),(b) (16,289,772) 13,721,708 (2,568,064)Intangibleexplorationexpenditures (b) – (9,204,297) (9,204,297)Developmentexpenditures (174,359) – (174,359)

(16,464,131) 4,517,411 (11,946,720)Discontinuedoperations 279,782 – 279,782

(16,184,349) 4,517,411 (11,666,938)

Financing activitiesSharesissuedforcash 1,423,011 – 1,423,011Long-termdebt 8,577,350 – 8,577,350PurchaseofCommonSharesforcancellation (876,217) – (876,217)Repaymentoflong-termdebt (103,997) – (103,997)

9,020,147 – 9,020,147

Foreign exchange losses on cash held in foreign currency (1,185,123) – (1,185,123)

Decrease in cash and cash equivalents (7,652,202) – (7,652,202)Cash and cash equivalents – beginning of year 16,235,523 – 16,235,523

Cash and cash equivalents – end of year 8,583,321 – 8,583,321


At the end of the last reporting period under previous CGAAP – 31 December 2006 Effectof Previous transition CGAAP toIFRS IFRS Notes $ $ $

AssetsNon-current assetsIntangibleexplorationassets (b)(c)(f)(k) – 54,767,332 54,767,332Intangibledevelopmentcosts 1,574,039 – 1,574,039Property,plantandequipment (a)(b)(d)(f)(g)(h)(k) 98,311,833 (66,124,735) 32,187,098Deferredfinancingfees (i) 2,539,726 (2,539,726) –Otherfinancialassets (j) 719,380 195,178 914,558

103,144,978 (13,701,951) 89,443,027

Current assetsInventories (d)(g) 50,552 48,369 98,921Prepaidexpenses 531,273 – 531,273Tradeandotherreceivables 9,839,506 – 9,839,506Cashandcashequivalents 46,861,146 – 46,861,146

57,282,477 48,369 57,330,846

160,427,455 (13,653,582) 146,773,873

LiabilitiesCurrent liabilitiesTradeandotherpayables 12,715,381 – 12,715,381Borrowings 147,720 – 147,720

12,863,101 – 12,863,101

Non-current liabilitiesBorrowings (i) 65,525,524 (2,400,681) 63,124,843Provisions 62,322 – 62,322Deferredtaxliabilities (f) 2,346,605 (2,346,605) –Derivativefinancialliability (l) – 27,997,140 27,997,140

67,934,451 23,249,854 91,184,305

80,797,552 23,249,854 104,047,406

79,629,903 (36,903,436) 42,726,467

EquitySharecapital (i)(l) 27,865,874 (3,284,890) 24,580,984Reserves (e)(k) 2,533,532 103,526 2,637,058Retainedearnings(deficit) (a)(c)(d)(e)(g)(h)(j)(k)(l) 49,230,497 (33,722,072) 15,508,425

79,629,903 (36,903,436) 42,726,467



Reconciliation of loss for the year ended 31 December 2006 Effectof Previous transition CGAAP toIFRS IFRS Notes $ $ $

RevenuePetroleumandnaturalgas 3,938,512 – 3,938,512Drillingservices 2,895,727 – 2,895,727

6,834,239 – 6,834,239

ExpensesPetroleumandnaturalgas 723,611 – 723,611Drillingrigoperating 2,291,585 – 2,291,585Generalandadministrative (e) 8,977,345 (349,218) 8,628,127Foreignexchangelosses(gains) (k) 798,194 (171,189) 627,005Depletion,depreciationandamortisation (d)(g) 691,011 660,976 1,351,987Explorationexpenditure (a) – 6,066,977 6,066,977Impairmentofunprovedpetroleumandnaturalgas (a) 986,964 (986,964) –

14,468,710 5,220,582 19,689,292

Finance income (costs)Interestincome (h) 1,767,898 (431,547) 1,336,351Financecosts (h) (5,996,553) 1,354,427 (4,642,126)Lossonderivativeliability (i) – (24,851,295) (24,851,295)Unrealisedgainonotherfinancialassets (j) – 195,178 195,178

(4,228,655) (23,733,237) (27,961,892)

Loss from continuing operations (11,863,126) (28,953,819) (40,816,945)Gain(loss)ondisposalofdiscontinuedoperations (g)(h) 9,950,968 (750,268) 9,200,700Earningsfromdiscontinuedoperations 3,248,490 – 3,248,490

Net loss (f) 1,336,332 (29,704,087) (28,367,755)


Reconciliation of cash flow statement for the year ended 31 December 2006 Effectof Previous transition CGAAP toIFRS IFRS Notes $ $ $

Cash provided by (used in)Operating activitiesNetlossfromcontinuingoperations (a)(d)(e)(g)(h)(i)(k)(l) (11,863,126) (28,953,819) (40,816,945)Itemsnotinvolvingcash Depletion,depreciationandamortisation (d)(g) 691,011 660,976 1,351,987 Financecosts–accretionexpenses (h) 860,895 (213,442) 647,453 Foreignexchangelosses (k) 593,837 (171,189) 422,648 Share-basedcompensation (e) 1,483,945 (66,901) 1,417,044 Impairmentofunprovedpetroleumandnaturalgasproperties (a) 986,964 (986,964) – Gainonotherfinancialassets (j) – (195,178) (195,178) Lossonderivativefinancialinstruments (l) – 24,851,295 24,851,295 Increaseintradeandotherreceivables (972,251) – (972,251) Increaseinprepaidexpenses (312,051) – (312,051) Decreaseininventory 142,809 – 142,809 Increaseintradeandotherpayables 725,738 – 725,738

(7,662,229) (5,075,222) (12,737,451)Discontinuedoperations 3,748,853 – 3,748,853

(3,913,376) (5,075,222) (8,988,598)

Investing activitiesProperty,plantandequipmentexpenditures (a)(b)(h) (33,512,387) 21,247,324 (12,265,063)Intangibleexplorationexpenditures (a)(b)(h) – (16,172,102) (16,172,102)Intangibledevelopmentexpenditures (386,668) – (386,668)

(33,899,055) 5,075,222 (28,823,833)Discontinuedoperations 17,576,116 – 17,576,116

(16,322,939) 5,075,222 (11,247,717)

Financing activitiesSharesissuedforcash 1,318,945 – 1,318,945Convertiblebonds 60,000,000 – 60,000,000Convertiblebondissuecosts (3,000,000) – (3,000,000)Repaymentoflong-termdebt (287,759) – (287,759)

58,031,186 – 58,031,186

Decrease in cash and cash equivalents 37,794,871 – 37,794,871Cash and cash equivalents – beginning of year 8,583,321 – 8,583,321Foreign exchange gains on cash held in foreign currency 482,954 – 482,954

Cash and cash equivalents – end of year 46,861,146 – 46,861,146



Notes to reconciliationsa) Pre-licence costsUnder Canadian GAAP all costs incurred prior to having obtained licence rights were included within property, plant and equipment. Under IFRS, such expenditures are expensed as incurred. The impact on adoption to IFRS at 1 January 2005 is a reduction in property, plant and equipment and retained earnings of $2,162,301.

At 31 December 2005, this adjustment has resulted in a reduction in property, plant and equipment and retained earnings of $5,954,797, an increase in exploration expenditure for the year of $4,517,411, and a decrease in the impairment of unproved petroleum and natural gas interests recognised in the year of $724,915. The income tax impact was in a further reduction of property, plant, and equipment of $2,346,605 and a corresponding decrease in deferred tax liability.

At 31 December 2006, this adjustment has resulted in a reduction in property, plant and equipment and retained earnings at $11,034,810, an increase in exploration expenditure for the year of $6,066,977, and a decrease in the impairment of unproved petroleum and natural gas interests recognised in the year of $986,964.

b) Reclassification of exploration and evaluation costsUnder Canadian GAAP property, plant and equipment included certain exploration and evaluation expenditure incurred within established geographic cost pools. Under IFRS, such exploration and evaluation costs are recognised as tangible or intangible based on their nature.At 31 December 2006, this has resulted in the reclassification from property, plant and equipment to intangible exploration assets of $56,311,426 (1 January 2005: $32,589,744; 31 December 2005: $45,111,919).

c) Capitalisation of property, plant and equipment depreciation of intangible assetsUnder IFRS, depreciation of property, plant and equipment utilised in exploration activities is capitalised as intangible exploration assets. As these assets were classified as property, plant and equipment under Canadian GAAP, depreciation of fixed assets was not included in the balance.

The impact on adoption to IFRS at 1 January 2005 is an increase in intangible exploration assets and retained earnings of $135,898. At 31 December 2005, an increase in intangible exploration assets and retained earnings of $171,728 and a decrease in depreciation expense for the year of $35,830. At 31 December 2006, an increase in intangible exploration assets and retained earnings of $171,728.

d) Reversal of impairmentUnder IFRS, impairment losses previously recorded are reversed if the conditions giving rise to the impairment have reversed. The reversal of impairment losses was not permitted under Canadian GAAP. The impact on adoption to IFRS at 1 January 2005 is an increase in inventory of $24,976, an increase in property, plant and equipment of $1,656,846, and an increase in retained earnings of $1,681,822.

At 31 December 2005, this has resulted in increases in inventory of $35,441, property, plant and equipment of $1,442,748, retained earnings of $1,478,189, and depletion expense for the year of $203,633.

At 31 December 2006, this has resulted in increases in inventory of $26,638, property, plant and equipment of $1,071,212, retained earnings of $1,097,850 and depletion expense for the year of $380,339.

e) Share-based paymentsUnder Canadian GAAP, the Group recognised an expense related to their share-based payments on a straight-line basis through the date of full vesting. Under IFRS, the Group is required to recognise the expense over the individual vesting periods for the graded vesting awards.

At 31 December 2005, this has resulted in increases in general and administrative expenses and share-based payments reserves of $456,747, with a corresponding decrease in retained earnings.

At 31 December 2006, this has resulted in increases in share-based payments reserves of $107,529, with a corresponding decrease in retained earnings. General and administrative expenses for the year decreased by $349,218.

f) Deferred taxUnder Canadian GAAP, the Corporation recognised a deferred tax liability and corresponding increase in property, plant and equipment associated with its acquisition of Russian properties. However, under IFRS deferred tax is only recognised on the initial recognition of an asset if it is acquired through a business combination.

At 31 December 2005 and 31 December 2006, this has resulted in a reduction of property, plant and equipment and deferred tax liability of $2,346,605. There was no impact at 1 January 2005.



g) Depletion policyUpon transition to IFRS, the Corporation adopted a policy of depleting petroleum and natural gas interests on a units of production basis over proved plus probable reserves. The depletion policy under Canadian GAAP was units of production over proved reserves.

The impact on adoption to IFRS at 1 January 2005 is an increase in property, plant and equipment and retained earnings of $789,008. At 31 December 2005, this resulted in increases in property, plant and equipment and retained earnings of $743,642, and depletion expense for the year of $34,734, and a decrease in earnings from discontinued operations of $10,632. At 31 December 2006, this resulted in decreases in property plant and equipment of $233,631, retained earnings of $211,900, and earnings from discontinued operations of $674,905, and increases in inventory of $21,731, and depletion expense for the year of $280,637.

h) Capitalisation of borrowing costsUnder Canadian GAAP all borrowing costs were expensed as incurred. Under IFRS, the Corporation capitalises those borrowing costs incurred for the development of qualifying assets. There was no change as at 1 January 2005.

At 31 December 2006, this has resulted in increases in property, plant and equipment and retained earnings of $847,517, and reductions in interest income of $431,547, finance costs of $1,354,427, and gain on disposal of discontinued operations of $75,363.

i) Deferred financing feesUnder IFRS, loans and receivables are recognised net of transaction costs, with interest expense recognised over the term of the loan using the effective interest method. Under Canadian GAAP prior to 1 January 2007 the Corporation recognised these transaction costs as deferred financing fees in non current assets and amortised them into income on a straight line basis over the term of the loan.

At 31 December 2006, this has resulted in a decrease in deferred financing fees of $2,539,716, borrowings of $2,400,681, and derivative financial liability of $139,045.

j) Held for trading financial assetsIFRS requires held for trading financial assets to be measured at fair value with changes in the fair value to be recorded in income in the period. Under Canadian GAAP, these assets were held at cost. There was no change on adoption of IFRS at 1 January 2005.

At 31 December 2006, this has resulted in increases in other financial assets, retained earnings and unrealised gain on other financial assets of $195,178.

k) Foreign currency translationUnder IFRS, amounts are initially recognised in a subsidiary’s functional currency (the currency of the primary economic environment in which it operates) and are translated into the functional currency of the group in accordance with note 1(t). The assessment of functional currency has resulted in transactions and balances for the Corporation’s Russian subsidiary to be initially recognised in Russian roubles. Under Canadian GAAP, these subsidiaries were considered to be integrated and were translated with only monetary assets and liabilities retranslated using period end rates.

At 31 December 2006, this has resulted in increases in property, plant and equipment of $103,065, intangible exploration assets of $64,121, and retained earnings of $171,189, with decreases in foreign exchange losses of $171,189 and the foreign currency translation reserve of $4,003.

l) Convertible bondsUnder Canadian GAAP, the Corporation’s convertible bonds were initially recognised with an allocation between equity and liability components based on their relative fair values. IFRS requires the recognition of a liability and an embedded derivative liability representing the bond holder’s conversion option. The fair value of the derivative financial liability is subsequently measured at fair value at each period end with changes in fair value being recognised in income.

At 31 December 2006, this has resulted in increases in derivative financial liabilities of $27,997,140 and a loss on derivative financial liabilities of $24,851,951, and decreases in other contributed equity of $3,145,845, and retained earnings of $24,851,295.


$ US dollars unless otherwise stated

“API” a specific gravity scale developed by the American Petroleum Institute for measuring the relative density of various petroleum liquids, expressed in degrees

“bbl” barrel

“bbls” barrels

“bbls/d” or “bopd” barrels per day

“Bcf” billion cubic feet

“boe” barrels of oil equivalent1

“boe/d” or “boepd” barrels of oil equivalent per day

“Company” Heritage Oil Limited a company, incorporated in Jersey on 6 February 2008 and the ultimate holding company of Heritage and the other group subsidiaries

“condensate” low density, high API hydrocarbon liquids that are present in natural gas fields where it condensates out of the raw gas if the temperature is reduced to below the hydrocarbon dew point temperature of the raw gas

“DRC” the Democratic Republic of Congo

“Gj” gigajoules

“Group” the Company and all of its subsidiaries

“Heritage”, “HOC” Heritage Oil Corporation, incorporated in or “Corporation” Canada and a wholly-owned subsidiary of the

Company

“LPG” liquid petroleum gas

“m3” cubic metres

“Mbbls” thousand barrels

“MMbbls” million barrels

“Mboe” thousands of barrels of oil equivalent

“MMboe” millions of barrels of oil equivalent

“Mcf” thousand cubic feet

“Mcf/d” thousand cubic feet per day

“MMBtu” million British thermal units

“MMcf” million cubic feet

“MMcf/d” million cubic feet per day

“MMstb” million stock tank barrels

“NGLs” natural gas liquids

“Petroleum” any mineral, oil or relative hydrocarbon (including condensate and natural gas liquids) and natural gas existing in its natural condition in strata (but not including coal or bituminous shale or other stratified deposits from which oil can be extracted by destructive distillation)

“Possible Reserves” those additional reserves that are less certain to be recovered than Probable Reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated Proved plus Probable plus Possible Reserves

“Probable Reserves” those additional reserves that are less certain to be recovered than Proved Reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated Proved plus Probable Reserves

“Proved Reserves” those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated Proved Reserves

“PSC” or PSA” production sharing contract or production sharing agreement

“psi” pounds per square inch

“psia” pounds per square inch absolute

“SPE” Society of Petroleum Engineers

“psi” pounds per square inch

“Tullow” Tullow Oil PLC

“WTI” West Texas Intermediate

1: Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

ConversionThe following table sets forth standard conversions from Standard Imperial Units to the International System of Units (or metric units).

To Convert From To Multiply By

boes Mcfs 6Mcf m3 28.174m3 Cubic feet 35.494bbls m3 0.159m3 bbls oil 6.290Feet Metres 0.305Metres Feet 3.281Miles Kilometres 1.609Kilometres Miles 0.621Acres Hectares 0.405Hectares (Saskatchewan) Acres 2.471Hectares (Alberta) Acres 2.500

Glossary of Technical Terms


Notes

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Documents

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foreign exchange gains losses

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