ANNUAL REPORT

ANNUAL REPORT 2013 1 AT A GLANCE Reserves & Resources MMbbl Balance Sheet $MM Income Statement $ Million Net Loss Net Loss per share ($/sh) 2011...
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ANNUAL REPORT 2013

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AT A GLANCE Reserves & Resources MMbbl

Balance Sheet $MM

Income Statement $ Million Net Loss Net Loss per share ($/sh)

2011 16.7 -

2012 58.5 2.10

Capital Expenditures $ Million

2013 By Activity

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2013 By Region

2013 185.8 2.04

CONTENTS

4 Chairman’s Message 5 Vision and Values 6 CEO’s Message 8 Our Operations 10 Kurdistan Region of Iraq: Hawler 14 Republic of the Congo: Haute Mer A & B 16 Senegal / Guinea Bissau: AGC 18 Iraq: Wasit Province 20 Nigeria: OML 141 22 Corporate Social Responsibility 24 Kurdistan Children’s Hospital 26 Corporate Governance 28 Board of Directors 30 Organisation 32 Reserves & Resources Advisory 33 Management’s Discussion and Analysis of Financial Condition and Results of Operations 49 Consolidated Financial Statements

This Annual Report contains forward-looking information. By its nature, forward-looking information requires us to make assumptions and is subject to risks and uncertainties. Please refer to the Forward-Looking Information advisory on page 46 for a discussion of such risks and uncertainties and the material factors and assumptions related to the information set forth in this Annual Report.

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A MESSAGE FROM OUR CHAIRMAN

“Following the Sale of Addax Petroleum in 2009, my colleagues and I saw an opportunity to use our experience, relationships and entrepreneurial instincts to build a leading independent exploration, development and production company. We established Oryx Petroleum in late 2010. We instilled in this new company values, ‘ambition, agility and responsibility’, that we believe are keys to success and that reflect the company’s heritage as an entity affiliated with AOG (formerly The Addax and Oryx Group). We decided to focus our efforts on Africa and the Middle East, regions that we know well and that are endowed with a plethora of established hydrocarbon basins. The team has made excellent progress in fulfilling our ambitious vision. We acquired a portfolio of license areas throughout 2011 and 2012, some in special situations reminiscent of how Addax Petroleum acquired its key assets. In 2012, we started drilling, and in 2013, we started to achieve results. Five of the seven exploration wells we drilled in 2013 have resulted in discoveries and we are well on our way to achieving our objective of building a balanced full-cycle exploration, development and production company. Our key focus is currently our operations in the Kurdistan Region of Iraq. It has been a pleasure to watch the Kurdistan Region develop. The positive changes that have occurred since I first visited Kurdistan in 2006 are impressive. It is a source of great satisfaction for me that Oryx Petroleum and previously Addax Petroleum have played a role in developing the energy industry in the Kurdistan Region and in contributing to the well being of its inhabitants. Our commitment to social responsibility is very real. I am proud of the role of Oryx Petroleum and of AOG in funding the construction of the Kurdistan Children’s Hospital. The Hospital will be the premier paediatric facility in Iraq and we expect to see it open its doors in 2014. I would like to thank management and the Board for their efforts, as well as all our shareholders who made our initial public offering in 2013 a success. 2014 will undoubtedly be another year with many achievements, including the expected start of production and an ambitious appraisal and exploration program. It is an exciting time to be a shareholder of Oryx Petroleum.”

Jean Claude Gandur Chairman

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Our vision is simple but ambitious; to become one of the world’s leading independent exploration, development and production oil companies. To achieve this, we are implementing an ambitious exploration and appraisal drilling program across our license areas, capitalising on the breadth of our team’s experience and our extensive knowledge of the regions in which we operate. We combine keen entrepreneurial instinct with a rigorous approach to risk and responsibility. You might say that we are courageous with opportunity, conservative with risk. Our corporate values can be distilled into the following three drivers:

AMBITIOUS

►► quick to seize new opportunities ►► inquisitive, curious and responsive ►► self-motivated, tenacious and intuitive

AGILE

►► open-minded, flexible and innovative ►► dedicated to working with local cultures for shared success ►► versatile and resourceful in exploring fresh solutions

RESPONSIBLE

►► honest, fair, open and tolerant ►► a culture that encourages personal success ►► committed to maintaining the highest standards of civility, decency, dignity and justice

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A MESSAGE FROM OUR CEO

“2013 was a tremendous year for Oryx Petroleum. In the Kurdistan Region of Iraq our drilling activities resulted in discoveries at all four structures in the Hawler license area, and we made our first discovery in West Africa with the Elephant discovery in Congo (Brazzaville). Consequently, Oryx Petroleum has transformed from a pure exploration company to a company with a sizeable reserves and contingent resource base and further exploration upside. In the Kurdistan Region of Iraq we have aggressively progressed appraisal and development of our Demir Dagh discovery with first production expected shortly. Appraisal and development drilling will continue throughout 2014 aiming to convert contingent resources into reserves, and reserves into production. In 2013, the signing of the Energy Framework Agreement between the Kurdistan Region of Iraq and Turkey, the completion of the Khurmala-Faysh Khabur pipeline, and the continuation of serious negotiations between the Erbil and Baghdad governments, all underscore substantive progress in moving towards a resolution of the export situation in Kurdistan. In West Africa, our focus for 2014 will be on growing our reserve base through further exploration, with high impact exploration wells planned in both the AGC and Congo (Brazzaville).

Demir Dagh Discovery Hawler FEBRUARY 2013

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Initial Public Offering MAY 2013

Elephant Discovery Congo (Brazzaville) SEPTEMBER 2013

Ain Al Safra Discovery Hawler SEPTEMBER 2013

In 2013, we also successfully completed an initial public offering to help fund our activities through to mid-2014 and we will seek to further strengthen our capital structure as the year progresses. We continue to evaluate new venture opportunities, particularly add-on acquisitions in our core focus areas, but our primary focus is on maximising the value of our existing properties. As our organisation and operations have grown we have maintained our focus on safety, environmental stewardship and social responsibility. Progress on construction of the Kurdistan Children’s Hospital, which we have helped organise and fund, progressed in 2013 and is expected to open in 2014. Our funding of this project was recognised as the Outstanding Community Initiative of 2013 by the Kurdistan Regional Government. Other important community activities included providing medical support to local communities within our Hawler license area and the funding of school and infrastructure construction upgrades. We are as proud of our achievements in these areas as we are of our operational achievements. As always I would like to thank our management and staff, who in combination with the support of our Board, business partners and shareholders have made our progress in 2013 possible. 2014 promises to be another transformational year for Oryx Petroleum.”

Michael Ebsary CEO

Tie-In Points to Khurmala-Faysh Khabur Pipeline completed Hawler NOVEMBER 2013

Zey Gawra Discovery Hawler DECEMBER 2013

Declaration of Commercial Discovery for Demir Dagh-2 Hawler FEBRUARY 2014

Banan Discovery Hawler MARCH 2014

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OUR OPERATIONS We are rapidly building a diverse portfolio of petroleum license areas, strategically focused in Africa and the Middle East.

Oryx Petroleum is an international oil exploration company focused in Africa and the Middle East. Oryx Petroleum was founded in 2010 by The Addax & Oryx Group (AOG) and key members of the former senior management team of Addax Petroleum, a company founded in 1994 by AOG and acquired in 2009 by Sinopec Corporation. Oryx Petroleum has interests in six license areas within its strategic focus areas of Africa and the Middle East, namely in the Kurdistan Region and the Wasit governorate (province) of Iraq, Nigeria, the AGC administrative area offshore Senegal and Guinea Bissau, and Congo (Brazzaville). Oryx Petroleum is the operator or technical partner in four of the six license areas. As at December 31, 2013, Oryx Petroleum had gross (working interest) proved plus probable oil reserves of 213 MMbbl, best estimate gross (working interest) contingent oil resources of 223 MMbbl and best estimate unrisked gross (working interest) prospective oil resources of 1,167 MMbbl (risked: 209 MMbbl). As at December 31, 2013, the after-tax net present value of the future net revenue for the Corporation’s gross (working interest) proved plus probable oil reserves is $1,287 million and best estimate gross (working interest) contingent oil resources is $697 million, using forecast prices and costs and a 10% discount rate. The Corporation’s oil reserves and resources and associated net present values as at December 31, 2013 are based on evaluations made by NSAI, an independent oil and gas consulting firm providing reserve and resource reports to the worldwide petroleum industry. See Reserves & Resources Advisory on page 32.

Location

Licence

Area (km2)

Water Depth (metres)

W.I. (%)

Operator / Technical Partner

Iraq Kurdistan Region

Hawler

788

Onshore

65.00

ORYX PETROLEUM

Wasit Province

Wasit

3,500

Onshore

40.00

ORYX PETROLEUM

Nigeria

OML141

1,295

0-30

38.67

ORYX PETROLEUM

AGC (Senegal / Guinea Bissau

AGC Shallow

1,700

0-100

80.00

ORYX PETROLEUM

Congo (Brazzaville)

Haute Mer A

488

350-1,100

20.00

CNOOC Ltd

Haute Mer B

402

150-1,050

30.00

TOTAL

Total

8,173

Reserves and Resources (Working Interest) Location

License Oil Reserves(1)

Iraq Kurdistan Region

Proved plus Probable (Working Interest) (MMbbl)

Hawler

($ million)(4)

213

1,287

Gross Oil (Working Interest) Contingent Oil Resources(2) Iraq Kurdistan Region Congo (Brazzaville)(6)

(MMbbl) Hawler Haute Mer A

Total Contingent Oil Resources(7)

($ million)(4)

217

697

6

-

223

697

Gross Oil (Working Interest) Unrisked Prospective Oil Resources(3) Iraq Kurdistan Region Wasit Province Nigeria

Risked (MMbbl)

Hawler

238

50

Wasit

404

77

67

10 38

OML141

AGC

AGC Shallow

267

Congo (Brazzaville)

Haute Mer A

31

4

160

31

1,167

209

Haute Mer B(5) Total Prospective Resources(7)

1. The oil reserves data is based upon evaluations by NSAI, with an effective date at December 31, 2013. 2. The contingent oil resources data is based upon evaluations by NSAI, and the classification of such resources as “contingent oil resources” by NSAI, with an effective date at December 31, 2013. The figures shown are NSAI’s “best estimate”, using deterministic methods. Once all contingencies have been successfully addressed, the probability that the quantities of contingent oil resources actually recovered will equal or exceed the estimated amounts is 50% for the best estimate. Contingent oil resources estimates are volumetric estimates prior to economic calculations. 3. The prospective oil resources data is based upon evaluations by NSAI, and the classification of such resources as “prospective oil resources” by NSAI, with an effective date at December 31, 2013. The figures shown are NSAI’s “best estimate”, using a combination of deterministic and probabilistic methods and are dependent on a petroleum discovery being made. If discovery is made and development is undertaken, the probability that the recoverable volumes will equal or exceed the unrisked and risked estimated amounts is 50% for the best estimate. Prospective oil resources estimates are volumetric estimates prior to economic calculations. 4. After-tax net present value of future net revenue associated therewith using forecast prices and costs and a 10% discount rate. Gross contingent resources estimates used to calculate future net revenue are estimated based on economically recoverable volumes within the development/ exploitation period specified in the PSC, REC or fiscal regime applicable to each license area. 5. Oryx Petroleum’s interest in Haute Mer B is subject to final approval from the government of Congo (Brazzaville). The National Assembly announced on July 25, 2013 that it had approved the award of the Haute Mer B license area. The PSC in respect of the Haute Mer B license area has since been finalised and initialled by all members of the contractor group who are now awaiting formal approval of the PSC by the National Assembly. 6. An economic evaluation has not been performed on the contingent oil resources in the Haute Mer A license area since the field development plan is still under consideration. 7. Individual numbers provided may not add to total due to rounding.

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Our business strategy has been designed to ensure that we capitalise on our strengths and achieve our vision to become one of the world’s leading independent exploration, development and production oil companies.

IRAQ

SENEGAL / GUINEA BISSAU NIGERIA

CONGO (BRAZZAVILLE)

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KURDISTAN REGION OF IRAQ: HAWLER Oryx Petroleum has a 65% participating and working interest in the Hawler license area. Oryx Petroleum has made discoveries on all four identified structures of the Hawler license area: Demir Dagh, Banan, Ain Al Safra and Zey Gawra. First production is expected in the second quarter of 2014.

Oryx Petroleum acquired its 65% working and participating interest in the Hawler license area in August 2011. The Korean National Oil Corporation has a 15% participating interest and the Kurdistan Regional Government (KRG) has a 20% participating interest. Oryx Petroleum is the operator of the Hawler license area. The Hawler license area is characterised by large thrust-bound anticlines. These structures produce both the potential for large trapped hydrocarbon volumes as well as fracturing within the reservoir to aid well productivity. Prior to drilling by Oryx Petroleum, there had been two previous wells drilled in the license area by the Iraqi national oil companies: Demir Dagh-1 in 1960, and Zab-1 (on the currently named Zey Gawra discovery) in 1990 and 1991. Both previous wells encountered oil shows and flowed oil under limited test conditions.

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We identified four structures based on the previous wells drilled and 2D seismic data acquired by the previous operator: Demir Dagh, Zey Gawra, Ain Al Safra and Banan. Drilling commenced in mid-2012. Oryx Petroleum has made discoveries on all four identified structures. A declaration of commercial discovery was submitted to the KRG on February 25, 2014 in respect of the Demir-Dagh 2 discovery. Contemporaneously with this submission, it was agreed with the KRG that Oryx Petroleum would relinquish approximately 850 km2 of the license area, representing that portion of the license area that Oryx Petroleum has determined is not required in connection with the appraisal and/or development of the Demir Dagh, Banan, Ain Al Safra and Zey Gawra fields. Any decision regarding development of the Banan, Ain Al Safra and Zey Gawra fields is subject to further appraisal activity, which must be concluded by June 30, 2015. Following such appraisal, these areas must either be developed or relinquished.

The Demir Dagh Discovery and Development The Demir Dagh discovery was announced in February 2013 after the conclusion of a successful test program that flowed oil from Cretaceous and Jurassic reservoirs. The discovery is estimated to contain 258 MMbbl of gross (100%) proved plus probable oil reserves, as well as 271 MMbbl of best estimate gross (100%) contingent oil resources and 50 MMbbl of best estimate unrisked gross (100%) prospective oil resources (risked: 10 MMbbl). Approximately 92% of the estimated reserves at Demir Dagh consist of 23°API oil in the Shiranish, Kometan and Qamchuqa formations in the Upper Cretaceous. Testing and analysis confirmed matrix porosity. The oil in this reservoir is also very low in gas and hydrogen sulphide content and has good viscosity making it easy to process. The remaining 8% of the estimated reserves at Demir Dagh consist of light oil (37°API to 42°API) from the Mus and Adaiyah formations

A world class asset: Four discoveries with first production expected in 2014

in the Lower Jurassic, with reservoir and liquid properties more similar to other discoveries in Kurdistan. The estimated contingent oil resources at Demir Dagh are comprised of approximately 84% of 23°API oil in the Shiranish, Kometan and Qamchuqa formations in the Upper Cretaceous, with the balance consisting of light oil (29°API to 32°API) from the Naokelekan and Sargelu formations in the Middle Jurassic. The estimated prospective oil resources at Demir Dagh consist entirely of light oil (40+°API) in the Butmah formation in the Lower Jurassic and the Kurra Chine formation in the Triassic.

We are pursuing an aggressive appraisal and development plan for Demir Dagh with three appraisal wells and five development wells planned for 2014. We have recompleted the Demir Dagh-2 discovery well as a producer and have already drilled, tested and completed the Demir Dagh-4 appraisal well as a producer. We are progressing on the installation of an Early Production Facility with a capacity of 40,000 bbl/d. We expect first production in the second quarter of 2014 with production increasing to the full capacity of the Early Production Facility sometime in 2015. We are planning for a Permanent Production Facility with a 100,000 bbl/d of initial capacity that we are targeting to have online in 2016.

We are expecting to sell some of our first production into the domestic market and are building a Truck Loading Facility. Importantly, we have completed construction of tie-ins to the recently built Khurmala-Faysh Khabur pipeline which will accommodate production from all our discoveries once pipeline exports from Kurdistan commence. As we progress our appraisal and development plans we could potentially add to our reserve volumes.

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KURDISTAN REGION OF IRAQ: HAWLER

The Zey Gawra Discovery We announced the Zey Gawra discovery in December 2013 after completion of a successful testing program that flowed light oil from the Shiranish, Kometan and Qamchuqa formations in the Cretaceous. The discovery is more than three times our predrill estimate in terms of volumes and the crude quality was much better than expected. The structure is estimated to contain 71 MMbbl of best estimate gross (100%) proved plus probable oil reserves and 32 MMbbl of best estimate unrisked gross (100%) prospective oil resources (risked: 12 MMbbl). The estimated reserves at Zey Gawra consist entirely of light oil (35°API) in the Shiranish, Kometan and Qamchuqa formations in the Upper Cretaceous. The estimated prospective oil resources at Zey Gawra consist of heavy oil (less than 23°API) in the Pila Spi formation in the Tertiary, light oil in the Alan, Mus and Adaiyah formations in the Middle Jurassic, light oil in the Butmah formation in the Lower Jurassic, and light oil in the Kurra Chine formation in the Triassic. We plan to drill an appraisal well at Zey Gawra as early as mid-2014 and the field will be developed with Demir Dagh and Banan if appraisal is successful.

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The Ain Al Safra Discovery We announced the Ain Al Safra discovery in October 2013 after completing a testing program that flowed oil from the Jurassic. The structure is estimated to contain 22 MMbbl of best estimate gross (100%) contingent oil resources and 49 MMbbl of best estimate unrisked gross (100%) prospective oil resources (risked: 10 MMbbl). The estimated contingent oil resources at Ain Al Safra consist entirely of heavy oil (18°API) in the Alan, Mus and Adaiyah formations in the Middle Jurassic. The estimated prospective oil resources at Ain Al Safra consist of heavy oil in the Butmah formation in the Lower Jurassic and light oil in the Kurra Chine formation in the Triassic. We believe there is large potential at Ain Al Safra and we spudded an appraisal well in March 2014 to further evaluate the Jurassic formations and explore the potential in the Triassic that the first exploration well was not able to assess.

The Banan Discovery We announced the Banan discovery in early March 2014 after a successful testing program that saw oil flowed from Cretaceous and Jurassic formations. Prior to the test results the structure was estimated to contain 40 MMbbl of best estimate gross (100%) contingent oil resources and 235 MMbbl of best estimate unrisked gross (100%) prospective oil resources (risked: 46 MMbbl). The estimated contingent oil resources at Banan consist entirely of light oil in the Shiranish, Kometan and Qamchuqa formations in the Cretaceous. The estimated prospective oil resources at Banan consist of light oil in the Pila Spi formation in the Tertiary, light oil in the Alan, Mus and Adaiyah formations in the Middle Jurassic, light oil in the Butmah formation in the Lower Jurassic, and light oil in the Kurra Chine formation in the Triassic. This first exploration well was drilled downdip of the crest of the structure as planning for drilling commenced before an extension of the Hawler license boundary was agreed with the KRG. The down-dip location impacted Oryx Petroleum’s ability to select the most optimal interval to test in the Cretaceous formations and impacted the volume ascribed to best estimate contingent resources. The large volume ascribed to the high estimate contingent resources reflects the potential of Banan. We plan to drill an appraisal well at Banan in 2014 to better assess this potential. If appraisal is successful Banan would be developed together with the Demir Dagh and Zey Gawra discoveries.

2014 Plans As at December 31, 2013, Oryx Petroleum’s budgeted capital expenditures for the Hawler license area are $366.6 million for 2014. The 2014 budgeted capital expenditures program includes: • the recent successfully completed testing program at BAN-1; • three appraisal wells and five development wells at Demir Dagh; • facilities expenditures related to a 40,000 bbl/d Early Production Facility and initial expenditures related to the Permanent Production Facility; • drilling of appraisal wells at each of Banan, Ain Al Safra and Zey Gawra; • the acquisition of 430 km2 3D seismic data over the Demir Dagh and Banan structures.

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REPUBLIC OF THE CONGO: HAUTE MER A&B Oryx Petroleum’s interests in Congo (Brazzaville) include a 20% participating and working interest in offshore license area Haute Mer A and a 30% participating and working interest in offshore license area Haute Mer B. Haute Mer A and Haute Mer B were created from a relinquished portion of the Haute

Haute Mer A In September 2009, CNOOC was awarded an 85% participating and working interest in, and operatorship of, the Haute Mer A license area. In November 2012, Oryx Petroleum acquired a 20% participating and working interest in the license area from CNOOC Ltd. CPC Corporation, a Taiwanese company also aquired a 20% working and participating interest from CNOOC Ltd. SNPC holds the remaining 15% participating and working interest. CNOOC is the operator of the HMA license area. The Haute Mer A license area is located 80 kilometres offshore Congo (Brazzaville) and covers an area of 488 km2 with water depths ranging from 350 metres to 1,100 metres. Two exploration wells were drilled in 2013 targeting the Elephant and Horse prospects with the well targeting Elephant resulting in a discovery.

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Elephant Discovery We announced the Elephant discovery in September 2013 and a testing program in early 2014 confirmed the discovery. The Elephant discovery lies in the middle of the license area and was previously targeted by the Libonolo Marine-1 (LIBM-1) well drilled in 1997 by Elf (currently Total), and a discovery made over the N5 interval of the Tertiary Miocene turbidites deposits. In August 2013, the exploration well targeting the Elephant prospect (E-1) reached a total depth of 2,497 metres using the Jasper Explorer Drillship in 550 metres of water 80 kilometres offshore Congo (Brazzaville). Primary targets for the E-1 well were the N5 and the N3 turbiditic type reservoir intervals in the Miocene Tertiary. The E-1 well was drilled approximately 4.5 kilometres south-east of the LIBM-1 well. Based on the data from the E-1 well, 30 metres of gross interval (20.3 metres

net) of crude oil and 102 metres of gross interval (58.8 metres net) of natural gas were encountered in the N5 interval and 16 metres of gross interval (9.2 metres net) of crude oil were encountered in the N3 interval. Reservoir quality, crude quality and viscosity were better than pre-drill expectations while the areal extent of the structure was smaller than expected. The Elephant discovery was successfully tested in early 2014 with the oil bearing intervals in the N3 flowing 24° API oil and the N5 flowing 18° API oil. Pressure build up analysis confirmed the excellent porosity and permeability of the respective sand channel complexes. As at December 31, 2013, prior to the test results, the Elephant discovery was estimated to contain best estimate gross (100%) contingent oil resources of 31 MMbbl. The prospects and leads on the license area are estimated to contain best estimate unrisked gross (100%) prospective oil

Exploration for oil adjacent to large producing fields Mer license area operated by Total. The Haute Mer license area has yielded a number of discoveries including N’Kossa (1984), Moho-Bilondo (1995) and Moho Nord (2007). The license areas are also in close proximity to discoveries in adjacent license areas in Angola.

resources of 153 MMbbl (risked: 20 MMbbl). 2014 Plans Our budgeted capital expenditures for the Haute Mer A license area are $31.8 million for 2014 and include the recently successfully completed testing of the E-1 well discovery and an exploration well. We are working with our partners to determine precise timing and location of future exploration drilling. Haute Mer B In April 2012, Oryx Petroleum was awarded a 30% participating and working interest in the Haute Mer B license area. We are waiting on final approval of the production sharing contract by the National Assembly of Congo (Brazzaville). Participating interests in the license area are: Total (34.62%), Oryx Petroleum (30%), Chevron (20.38%) and SNPC (15%). Total is the operator of the Haute Mer B license area. The Haute Mer B license area is located 58

kilometres offshore Congo (Brazzaville) and covers an area of 402 km2 with water depths ranging from 150 metres to 1,050 metres. A large amount of 2D and 3D seismic data has been acquired during successive acquisition campaigns covering the Haute Mer B license area, but no well has yet been drilled in the license area. The principal targets in the Haute Mer B license area are Cretaceous carbonate reservoirs similar to those producing light oil in neighbouring fields, with additional targets in shallower Tertiary deposits. Three prospects in the Cretaceous (Loubossi, Kaki Main and Kaki East), four leads in the Cretaceous and four leads in the Tertiary have been identified in the Haute Mer B license area. The identified prospects and leads collectively are estimated to have total best estimate unrisked gross (working interest) prospective oil resources of 160 MMbbl (risked: 31 MMbbl). The three prospects in the Cretaceous are estimated to have total best

estimate unrisked gross (working interest) prospective oil resources of 93 MMbbl (risked: 19 MMbbl). Oil quality is expected to be light in the Cretaceous and heavy in the Tertiary. 2014 Plans Our budgeted capital expenditures for the Haute Mer B license area are $39.1 million for 2014. An exploration well is planned to be spudded in the second half of 2014.

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SENEGAL / GUINEA BISSAU: AGC An 85% participating interest (80% working interest if the AGC exercises the AGC Back-In Right) in the AGC Shallow license area, one of the two license areas in the AGC region offshore Senegal and Guinea Bissau. The license area is 1,700 km2 in size with water depths up to 100 metres.

In November 2011, Oryx Petroleum was awarded an 85% participating interest in the AGC Shallow license area, with the Agence de Gestion et de Coopération entre le Senegal et la Guinea-Bissau (AGC) holding a 15% carried interest and an option to acquire an additional 5% non-carried interest upon the issuance of an exploitation permit for the license area. The AGC Shallow license area, one of the two license areas in the AGC region offshore Senegal and Guinea Bissau, is 1,700 km2 in size with water depths up to 100 metres. Exploration activities in the region were commenced by Total in 1958. Seismic data and geophysical reconnaissance surveys revealed the presence of several prominent shallow salt domes. The first exploration drilling in the areas adjacent to the north of the AGC commenced in 1966 with four wells drilled on salt domes. The first drilling in what is now the AGC began in 1967 with three exploration wells on Dome Flore. These

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wells all encountered heavy oil and partially delineated the shallow water salt diapir. An additional well found light oil in the Albian sands (Lower Cretaceous).

We have identified two play types in three structures for potential light oil exploration: salt diapir related structural traps and seismic amplitude prospects.

After the initial shallow discoveries of heavy (Tertiary) and light (Cretaceous) oil on Dome Flore and Dome Géa, the license area was held for the last three decades by a series of smaller independent exploration companies whose activities were largely confined to acquiring 3D seismic data. Only two other wells have been drilled in the last 30 years with development of heavy oil being the primary focus. In 1996 an independent exploration company drilled a shallow well that had heavy oil shows. The previous operator of the license area acquired 385 km2 of 3D seismic data in 2003.

Salt Diapir Related Prospects Oil is thought to be trapped in very shallow reservoirs in the Albian associated with salt diapirs where the heavy nature of the crude is thought to be because of degradation. Three structures have been identified: Dome Flore, Dome Gea and Dome Iris. New seismic data technology, such as Pre-stack Depth Migration, developed in recent years has been used to image deeper reservoirs where degradation is less likely to have occurred, but also where the geometries of the salt need to be properly imaged and defined. In 2012 we acquired 840 km2 of 3D seismic data over an area including the three structures and have reprocessed and studied such data in 2013.

Significant light oil potential with hydrocarbon system established by discovered heavy oil

Seismic Amplitude Prospects Based on the seismic data acquired in 2012, we have also identified some seismic amplitude prospects in the Maastrichtian in two of the identified structures: Dome Iris and Dome Gea.

2014 Plans Our 2014 budgeted capital expenditures for the AGC Shallow license area are $44.9 million for 2014 which is primarily related to the drilling of an exploration well. We have recently commenced a tendering process for the planned exploration well.

The light oil prospects and leads are estimated to contain a total of 267 MMbbl of best estimate unrisked gross (working interest) prospective oil resources (risked: 38 MMbbl).

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IRAQ: WASIT PROVINCE A 50% participating interest (40% working interest assuming the Back-In Rights are exercised) in the Wasit license area with rights for oil exploration operated by Oryx Petroleum.

In two transactions in December 2011 and October 2013, Oryx Petroleum acquired a 66.67% shareholding in KPA Western Desert Energy Limited (“KPA”) that has an indirect 75% participating interest in contracts with the government of the Wasit Province of Iraq (the “WPG Contracts”), namely an Asphalt Exploration Contract, a Seismic Option Agreement and a Risk Exploration Contract (“REC”). Oryx Petroleum is the contract operator with regard to all of the WPG Contracts. Assuming that the Wasit Provincial Government (“WPG”) exercises certain BackIn Rights then, as a result of its shareholding in KPA, Oryx Petroleum will have a 40% working interest in the WPG Contracts. The Seismic Option Agreement grants nonexclusive rights to acquire 2D seismic data on behalf of the WPG over any part of the Wasit province up to a total of 7,000 kilometres. The initial term of the Seismic Option Agreement is five years, expiring in September 2016, with an option to extend for an additional five years.

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Pursuant to the Seismic Option Agreement, KPA can nominate non-contiguous areas totalling up to 3,500 km2 to be “Contract Areas” governed by the terms of the REC.

The Asphalt Exploration Contract provides KPA exclusive rights to mine heavy oil, asphalts tar and bitumen (less than 25°API) throughout the Wasit province.

The Wasit REC provides KPA with the right to conduct all exploration, gas marketing, development, production and decommissioning operations relating to petroleum in nominated Contract Areas. At present, no Contract Areas have been nominated by KPA. Each nominated Contract Area would be deemed to be a new REC, and the WPG is granted the WPG Back-In Right to acquire up to a 20% participating interest in each Contract Area so nominated by KPA. Existing producing regions within the Wasit province are excluded from the Wasit REC.

The overall geological profile of the Wasit province appears to be very favourable for hydrocarbon exploration, with a proven active petroleum system (Jurassic and Early Cretaceous source rocks) charging many large discoveries in the province (Ahdab, Dufriyah and Badrah fields) and in the surrounding area, including accumulations such as the super-giant East Baghdad field. Geologically, the Wasit province spans three distinct domains, namely the Arabian Shelf, the Mesopotamian Foredeep, and the Zagros Fold Belt, providing an attractive diversity of charge and trap mechanisms and potential reservoirs.

Unique early stage oil opportunity in under-explored and under-developed province

China National Petroleum Corporation (Ahdab field), OAO Gazprom (Badrah field) and Pakistan Petroleum Limited are already present in the Wasit province under contracts with the Iraqi Federal Government. The Wasit province is under-explored, with only five exploration and appraisal wells drilled to date and limited 2D seismic data coverage. All five exploration and appraisal wells drilled in the Wasit province to date have been successful: two wells on the Badrah field, two wells on the Ahdab field and one well on the Dufriyah field.

The Iraq National Oil Company (INOC) acquired and interpreted 2D seismic data in the 1990s, from which it identified a number of leads in the province. Oryx Petroleum reviewed a small selection of these seismic data lines. Fifteen leads were identified in the Wasit province, from which Oryx Petroleum has chosen to develop a sub-set of five leads into prospects. The five leads to be developed into prospects are Sa’d, Wasit West, Wasit East, Wasit Central, and Dufriyah North. Collectively, the five leads are estimated to have best estimate unrisked gross (working interest) prospective oil resources of 404 MMbbl (risked: 77 MMbbl).

2014 Plans Efforts to secure approvals and preparations for planned seismic data acquisition continued in 2013. Our budgeted capital expenditures for the Wasit province for 2014 are $27 million and include a seismic data acquisition campaign on the Wasit license area.

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NIGERIA: OML141 A 38.67% participating and working interest in OML 141, a shallow water offshore exploration area operated by an indigenous company, with Oryx Petroleum as the technical partner.

In September 2011, Oryx Petroleum acquired a 38.67% participating and working interest in the OML 141 license area through a farm-in transaction. OML 141 is a shallow water offshore exploration area operated by an indigenous company, Emerald Energy Resources Limited, with Oryx Petroleum acting as the technical partner. The OML 141 license area is located partly in the swamp and partly offshore in the central part of the Niger Delta. The modern-day environment consists of coastal mangrove swamp, brackish water within the transition zone, and delta platform to pro-delta slope environments in the offshore marine.

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There has been limited exploration activity in the license area in recent years with only three wells drilled since the 1960s and much of the license area does not have 3D seismic coverage. The Dila-1 exploration well was drilled to a depth of 12,000 feet (3,658 metres) in 2013. Based on logging information 8 feet net pay of natural gas and 14 feet net pay of oil were encountered in one of the targeted sands. We determined that the oil discovered was not in sufficient quantities to be commercially developed on a stand-alone basis and deemed the well unsuccessful.

Since the drilling of the Dila-1 well we have remapped the prospects in the portions of the license area covered by 3D seismic data. Ten of the identified prospects are estimated to contain best estimate unrisked gross (working interest) prospective oil resources of 67 MMbbl (risked: 10 MMbbl). We have also identified a number of stratigraphic plays in the portion of the license area covered only by 2D seismic data and plan to acquire 3D seismic data over such area.

Large under-explored license area within the prolific Niger Delta

2014 Plans We continue to analyse existing 3D seismic data and the results of the Dila-1 well and plan to acquire additional 3D seismic data in 2014 in order to determine the course of future activity in the OML 141 license area. Our budgeted capital expenditures for the OML 141 license area are $19.1 million for 2014 which is comprised primarily of the cost to acquire additional 3D seismic data.

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CORPORATE SOCIAL RESPONSIBILITY Social responsibility is at the forefront of Oryx Petroleum’s thinking and our everyday business practices and is a pillar to our corporate philosophy of being “Ambitious, Agile and Responsible”.

Our Principles We believe that acting in a responsible manner and working closely together with our host communities not only helps us meet our social commitments but also allows us to meet and exceed our business goals. Oryx Petroleum values the principles of accountability, honesty and integrity in all aspects of our business. We are committed to achieving the highest principles of corporate citizenship by safeguarding the environment, protecting the health and safety of our workforce and the communities in which we operate, creating and delivering on opportunities to enhance benefits to society, and respecting all human rights. Fulfilling our social responsibilities is integral to creating value for our shareholders, employees, partners, host governments and host communities.

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In conducting our business, we are guided by the following principles:

• We support and adhere to the principles of the Universal Declaration of Human Rights;

• We carry out our business based on the highest principles of business integrity. Our Code of Conduct expresses this commitment, and should be considered as a guide for everyone who works for, or on behalf of, Oryx Petroleum. Our Code of Conduct is embedded into all contracts and we expect everyone to adhere its principles;

• We expect our suppliers and contractors to abide by our Code of Conduct and AntiBribery and Anti-Corruption Policy.

• We are committed to operating our business in a manner consistent with the laws of the jurisdictions in which we operate; • We are committed to carrying out our business fairly, openly and honestly and condemn corruption in all its forms. Our Anti-Bribery and Anti-Corruption Policy are considered as a guide for everyone who works for, or on behalf of, Oryx Petroleum;

• We do not allow employment of under aged children in our workforce in any of our operations around the globe; • We provide equal employment opportunities to all workers, regardless of race, colour, sex, age, sexual orientation, creed, national origin or disability; and • We do not tolerate any form of workplace harassment, including sexual harassment of an employee, contractor or employment candidate.

Local Communities We believe in proactively engaging the local communities, host governments and civil society to secure a social license to operate. We believe that early, proactive stakeholder consultation is beneficial to both the company and the community and makes for high-impact, sustainable outcomes. We believe in working in partnership with the local communities, host government and civil societies to develop long lasting positive impacts on social development, particularly in the areas of education and health. We carry out assessments of social, economic and environmental potential positive and negative impacts of operations on the communities before establishing any major investment, new projects and potential acquisitions. Once these impacts are identified, we identify mitigation measures for negative impacts and look for methods for enhancing the socio-economic opportunities that flow from positive impacts.

We aim to manage social, environmental and security risks to avoid or minimise risks to stakeholders and to Oryx Petroleum’s operations. We recognise and respect local cultures and develop effective strategies and policies to support the rights of the local communities. We respect and support human rights in all areas that we conduct operations. We aim to mitigate any negative safety, health and environmental effect on the host communities as a consequence of our operations.

2013 Activities Our commitment to social responsibility is backed up with tangible actions. Our team of medical professionals has conducted visits to over 60 communities in the Hawler license area and treated over 3,500 patients most of whom are women and children. In the Hawler license area we have invested in school and village infrastructure construction and upgrades, provided employment to locals and hosted village social events. Our most ambitious project is the funding of the construction of the Kurdistan Children’s Hospital in Erbil.

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KURDISTAN CHILDREN’S HOSPITAL The Kurdistan Children’s Hospital is an ambitious and farsighted new healthcare facility located on the outskirts of Erbil, in the Kurdistan Region of Iraq. Oryx Petroleum is playing a critical role in its construction and development.

The Kurdistan Children’s Hospital is an ambitious and far-sighted new healthcare facility currently under construction on the outskirts of Erbil, in the Kurdistan Region of Iraq. In 2013 Oryx Petroleum provided the most of its $40 million commitment to fund the construction of the Hospital. The Kurdistan Children’s Hospital is owned and operated by the Kurdistan Children’s Hospital Foundation, a United Kingdom registered charitable company, supported by private philanthropy. The Foundation’s charter provides for the not-for-profit management and operation of the hospital and its facilities. Upon completion, the Kurdistan Children’s Hospital will provide a new paediatric healthcare facility that has no peer in Iraq. This is essential, as there are a large number of children and mothers that are currently unable to access suitable medical treatment or surgery inside Iraq. The only option for many children and mothers to date has been to travel to the US, Europe or other neighbouring countries in order to acquire the proper medical assistance that is not currently available in Iraq.

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The Proposed Facilities The Kurdistan Children’s Hospital complex will include a 120-bed main hospital building, 2 support buildings, a warehouse, an oxygen plant, a generator facility and a residential area for medical staff. The main hospital building will include: • 80 single-bed rooms • 20 multi-use rooms • 5 operating rooms • An emergency department • Various specialty clinics • A dedicated dental suite • A paediatric and neonatal ICU (intensive care unit) • A pharmacy and dispensary • Various medical laboratories • A state-of-the-art imaging department (including MRI, CT scanning and ultrasounds) • Education and training facilities • Administration offices • Catering facilities • Suitable retail facilities • Staff accommodation and recreational facilities • Dedicated public and staff car parks • Outdoor facilities for patients and their families

Status Construction of the Kurdistan Children’s Hospital commenced in Late 2010 and a soft opening is targeted for mid-2014. In addition to funding we have provided legal advice, helped facilitate a third party engineering audit, assisted with recruiting senior management and we provide ongoing advice and governance through membership on the Foundation`s Board of Directors.

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WE ARE COMMITTED TO STRONG CORPORATE GOVERNANCE

Our Board is comprised of eight directors, six of whom are independent. Our independent directors bring a wealth of experience in operations, finance, law and accounting. There is clear separation of the roles of the Chairman and the Chief Executive Officer to ensure an appropriate balance of responsibility and accountability. The Board has also established detailed charters to enable it to function independently of management and to facilitate open and candid discussion among the independent directors. The Board holds in-camera independent director meetings through the Corporate Governance Committee at every scheduled Board meeting, and otherwise as deemed necessary and upon the request of independent directors.

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CHAIRMAN

CHIEF EXECUTIVE OFFICER

The Chairman, Jean Claude Gandur, is responsible for the effective running of the Board, ensuring that the Board plays a full and constructive part in the development and determination of our strategy, and acts as guardian and facilitator of the Board’s decision-making process.

The Chief Executive Officer, Michael Ebsary, is responsible for managing Oryx Petroleum’s business, proposing and developing the company’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. In addition, the Chief Executive Officer is responsible for maintaining regular dialogue with shareholders as part of Oryx Petroleum’s overall investor relations program.

LEAD INDEPENDENT DIRECTOR The Lead Independent Director is Richard Alexander. Mr. Alexander is an independent director and, in his role as Lead Independent Director, acts in a leadership role facilitating the functioning of the Board independently of management and providing independent leadership to the Board as required.

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BOARD OF DIRECTORS Oryx Petroleum’s Board of Directors* is comprised of accomplished individuals with a diversity of skills and experience relevant to our operations.

Richard Alexander

David Codd

Michel Contie

Richard Alexander has a breadth of experience in the energy sector. From May 2006 to June 2011, he held various positions at AltaGas Ltd., including the position of President. Mr. Alexander was also the Vice President, Finance and Chief Financial Officer of Niko Resources Ltd. from September 2003 to April 2006 and the Vice President, Investor Relations and Communications of Husky Energy Inc. from July 2000 to August 2003.

David Codd is a retired solicitor and has over 32 years’ experience in the international oil industry. He was Chief Legal Officer of Addax Petroleum from February 2005 until his retirement in 2011. After qualifying with a major U.K. law firm, Mr Codd worked from 1980 to 1984 for Burmah Oil Company Ltd. In 1984 he joined Britoil PLC as Senior Legal Adviser. Following two years with ConocoPhillips Company in the U.K., in 1990 he was appointed General Counsel to Texaco’s integrated operations in the U.K. From 1999 to 2001, Mr Codd was Managing Director of Texaco in the U.K., being Texaco’s senior corporate representative in the U.K. with business responsibility for Texaco’s regional upstream business development. Following Texaco’s merger with Chevron, Mr. Codd was Chairman of a start-up company engaged in project development work in the Middle East until he joined Addax Petroleum in February 2005.

Michel Contie has a wide-range of experience in the oil and gas sector. Mr Contie has acted as a non-executive director at John Wood Group PLC since February 2010. Prior to this, Mr Contie started a consultancy practice, Mentorca (SARL), where he was a director from January 2010 to November 2011. Through Mentorca (SARL), Mr Contie negotiated contracts with John Wood Group PLC and Expro International Holdings Ltd. From May 2006 to December 2009, Mr Contie acted as the Vice President, Europe for Total.

Mr Alexander is currently a director of Global Water Resources Corp., Marquee Energy Ltd. and Parallel Energy Trust, and the President & CEO of Parallel Energy Trust. Mr Alexander is a citizen of Canada and received a B.B.M. from Ryerson Polytechnical Institute in Toronto, Canada.

Mr Codd is a citizen of the United Kingdom and has an MA (Jurisprudence) and a BCL, both from Oxford University.

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Mr Contie is a citizen of France and obtained an engineering degree in fluid mechanics from the University of Toulouse, France and also holds a degree as a petroleum engineer from École Nationale Supérieure du Pétrole in Paris, France.

*including Jean Claude Gandur and Michael Ebsary

Evan Hazell

Gerald Macey

Peter Newman

Evan Hazell is an engineer and has experience in both the financial and energy sectors. From 1998 to 2011 Mr Hazell acted as a managing director at several financial institutions including HSBC Global Investment Bank and RBC Capital Markets. Mr Hazell was granted the designation of P.Eng from the Association of Professional Engineers and Geoscientists of Alberta in 1983.

Gerald Macey has over 40 years of oil and gas industry experience. In particular, from 2002 to April 2004, he served as Executive Vice President and President, International New Ventures Exploration Division, of EnCana Corporation, and from 1999 to 2002, he served as Executive Vice President, Exploration, of PanCanadian Petroleum Corporation. He is also a director and Chairman of PanOrient Energy Corp. and a director of Gran Tierra Energy Inc. He was previously a director of Addax Petroleum.

Peter Newman was a partner at Deloitte LLP in London where he led the firm’s oil and gas sector practice globally from 2002 until his retirement in 2009. Prior to that, Mr Newman joined the oil and gas group at Arthur Andersen LLP in London in 1984, became a partner in 1989 and led the firm’s oil sector practice across Europe, the Middle East, India and Africa. Mr Newman also worked with Mobil Corporation from 1980 to 1984 as an auditor in several countries across Europe, Africa and the Far East. Mr Newman is nonexecutive director of AOG and Chairman of its audit committee.

Mr Hazell is a Canadian citizen and received a B.A. (Sc) from Queen’s University in Kingston, Canada, a M. Eng from the University of Calgary, Canada and an M.B.A. from the University of Michigan in Ann Arbour, U.S.

Mr Macey is a Canadian citizen and holds a Bachelor of Science degree in geotechnical science from the University of Montreal (Loyola College) and a Master of Science degree in geology from Carleton University in Ottawa.

Mr Newman is a citizen of the United Kingdom, and studied geography at the University of Oxford before qualifying as a Chartered Accountant in England.

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ORGANISATION Our senior management team is shrewd, resourceful and focused. They are supported by teams of technical, financial and legal experts, whose expertise in all aspects of the

Jean Claude Gandur Chairman

Michael Ebsary Chief Executive Officer

Henry Legarre Chief Operating Officer

Jean Claude Gandur founded The Addax and Oryx Group in 1987 with three associates from the energy industry, and focused on Africa. With an instinctive ability to recognise new opportunities, he rapidly diversified the group’s activities from oil trading, to downstream storage and distribution, before launching into upstream exploration and production in 1994, and a pioneering bioenergy project in 2008. Following the sale of Addax Petroleum in 2009, he initiated the creation of Oryx Petroleum.

Michael Ebsary helped found Oryx Petroleum in September 2010, when he was appointed Chief Executive Officer.

Henry Legarre helped found Oryx Petroleum in September 2010, when he was appointed Chief Operating Officer.

Prior to this he had worked as Chief Financial Officer of Addax Petroleum for eleven years after having held various positions in project finance and treasury with Elf and Occidental Petroleum, both in France and the United Kingdom. He began his working life in multinational banking institutions in Canada and the UK.

Prior to joining Oryx Petroleum, he was with Addax Petroleum for four years, where he was Managing Director, Middle East Business Unit, and Acting General Manager for the TaqTaq Operating Company in the Kurdistan Region of Iraq. He had previously worked with Chevron for 20 years, in various positions, including projects in the United States, West Africa, Latin America and the Middle East.

He has a degree in law and political science from the University of Lausanne, Switzerland.

He is a graduate of Queen’s University in Canada.

A member of the American Association of Petroleum Geologists and the Society of Petroleum Engineers, he is published in geochemistry, petrophysics, reservoir modelling and simulation and has served on the steering committee of a number of Joint Industrial Projects. He has a degree in geological sciences from the University in San Diego, California.

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upstream energy industry give Oryx Petroleum the unique blend of capabilities it needs to operate effectively, efficiently and profitably in all license areas.

Craig Kelly Chief Financial Officer Craig Kelly helped found Oryx Petroleum in September 2010, when he was appointed Chief Financial Officer. Before joining Oryx Petroleum, he was Head of Corporate Finance for Addax Petroleum for four years. Prior to this he had been a director in the Energy Group of RBC Capital Markets where he developed an expertise in advisory work for clients involved in mergers, acquisitions and financing in the energy industry. A graduate of Queen’s University in Canada, he is a member of the Alberta Institute of Chartered Accountants and earned his Chartered Accountant designation while with Ernst & Young in Hong Kong, Toronto and Vancouver, Canada.

Paul Shillington Chief Legal Officer and Corporate Secretary Paul Shillington joined Oryx Petroleum as Chief Legal Officer and Corporate Secretary in May 2011. Prior to this, he had spent the previous six years as an independent legal consultant, based in Paris, France and Perth, Australia, serving clients in the energy industry. His clients included ExxonMobil and Addax Petroleum. From 1999 to 2004 he was Asia Pacific legal counsel for Technip, after having commenced his legal career as a commercial and litigation lawyer in Australia with Freehill Hollingdale & Page and Phillips Fox. He is a graduate of the University of Western Australia.

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RESERVES & RESOURCES ADVISORY

Oryx Petroleum’s reserves and resource estimates have been prepared and evaluated in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook as at December 31, 2013. Proved oil reserves are those reserves which are most certain to be recovered. There is at least a 90% probability that the quantities actually recovered will equal or exceed the estimated proved (1P) oil reserves. Probable oil reserves are those additional reserves that are less certain to be recovered than proved oil reserves. There is at least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable (2P) oil reserves. Possible oil reserves are those additional reserves that are less certain to be recovered than probable oil reserves. There is a 10% probability that the quantities actually

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recovered will equal or exceed the sum of proved plus probable plus possible (3P) oil reserves. Contingent oil resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. There is no certainty that it will be commercially viable to produce any portion of the contingent oil resources. Prospective oil resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective oil resources have both a chance of discovery and a chance of development. There is no certainty that any portion of the prospective resources

will be discovered. The risked prospective oil resources reported in this document are partially risked resources that have been risked for chance of discovery, but have not been risked for chance of development. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources. Use of the word “gross” to qualify a reference to reserves or resources means, in respect of such reserves or resources, the total reserves or resources prior to the deductions specified in the Production Sharing Contract, Risked Exploration Contract or fiscal regime applicable to each license area. Reference to 100% indicates that the applicable reserves, resources or production are volumes attributed to the discovery or prospect as a whole and do not represent Oryx Petroleum’s working interest in such reserves, resources or production.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2013

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The following should be read in conjunction with the consolidated financial statements of Oryx Petroleum Corporation Limited (“OPCL”) for year ended December 31, 2013, which have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). The date of this Management’s Discussion and Analysis is March 12, 2014. On May 5, 2013, OPCL announced the filing of a supplemented PREP prospectus with the securities regulatory authorities in each of the provinces of Canada, other than Quebec, in connection with its initial public offering of 16,700,000 common shares, at a price of CAD$15.00 per common share (the “Offering”) for total gross proceeds of CAD$250.5 million ($249.4 million). The Offering closed on May 15, 2013. Immediately prior to closing, a corporate re-organisation occurred whereby OPCL became the parent company of Oryx Petroleum Holdings PLC (formerly Oryx Petroleum Company PLC and Oryx Petroleum Company Limited). All comparative balances dated before May 15, 2013 included in the consolidated financial statements for the year ended December 31, 2013 and these documents were originally reported by Oryx Petroleum Holdings PLC. Such balances have been prepared in accordance with IFRS as issued by the IASB. Unless otherwise noted, tabular amounts are in thousands of U.S. dollars and amounts in commentary are in millions of U.S. dollars. Investors should read the “ForwardLooking Information” advisory on page 46. Additional information relating to OPCL is on SEDAR at www.sedar.com.

Executive Summary The following table summarises the results of OPCL and its subsidiaries (“Oryx Petroleum”) for the year ended December 31, 2013 compared to the year ended December 31, 2012: Year ended

General and administrative expense Pre-license costs Impairment of oil and gas assets

Dec 31, 2013 ($ thousand)

Dec 31, 2012 ($ thousand)

40,131

22,612

6,383

6,608

82,948

29,017

728

361

54,314

142

184,504

58,740

Depreciation and amortisation expense Other

(1)

Loss before income tax Income tax expense / (benefit)

1,319

(203)

185,823

58,537

1,424

2,542

Total comprehensive loss

187,247

61,079

Cash surplus

306,034

64,944

248,482

137,399

Net Loss Remeasurement of defined benefit obligation(2)

Capital expenditure

(3)

Notes: 1. Includes finance (income) / expense, foreign exchange (gains) / losses and other operating expenses 2. In the current year, the Group has applied IAS 19 Employee Benefits (as revised in 2011) and the related consequential amendments for the first time. The impact on the opening retained earnings as at January 1, 2012 and the 2012 and 2013 financial statements are summarised in the consolidated financial statements for the year ended December 31, 2013: 3. Refer to “Capital Expenditure” below.

Net loss increased by $127.3 million to $185.8 million for the year ended December 31, 2013 compared to 2012 mainly due to an upward revision to the fair value of the Hawler license area’s contingent consideration ($56.9 million), as further described below, as well as the net impairment expense recorded during the period ($82.9 million), mainly relating to the Dila-1 well in the OML 141 license area ($21.7 million), the Sindi Amedi license relinquishment ($45.2 million) and the Horse well in the Haute Mer A license area ($17.3 million). The remaining increase in the net loss relates to a $17.5 million increase in general and administrative expense, partially offset by net foreign exchange gains of $2.6 million. A cash surplus of $64.9 million as at 31 December 2012 increased to $306.0 million at the end of the 2013 fiscal year. The increase in cash is mainly due to additional equity funding of $234.8 million received from The Addax and Oryx Group Limited (“AOG”) in January 2013 as well as net proceeds received upon the closing of the Offering on May 15, 2013 of CAD $239.0 million (gross proceeds CAD $250.5 million). The following table summarises the $248.5 million in capital expenditure incurred during the year ended December 31, 2013 compared to 2012.

License Area

Location

Year ended Dec 31, 2013

Dec 31, 2012

($ thousand)

($ thousand)

Hawler

Iraq - Kurdistan Region

146,560

74,694

Sindi Amedi

Iraq - Kurdistan Region

4,006

11,305

Wasit

Iraq – Wasit province

4,119

5,603

AGC Shallow

Senegal and Guinea Bissau

2,830

19,303

OML 141

Nigeria

47,416

11,129

Congo Haute Mer A

Congo (Brazzaville)

41,464

14,092

Corporate

2,087

1,273

Total capital expenditure

248,482

137,399

The capital expenditure in the Hawler license area during the year ended December 31, 2013 includes $105.4 million in drilling expenditure. This expenditure is comprised of exploration drilling, appraisal and testing activities conducted during the year. Drilling of the Demir Dagh-

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2 well, which was completed in the first quarter of 2013, incurred $1.8 million in drilling expenditure. A further $11.1 million in costs relating to testing on this well were also incurred during the year. Three additional exploration wells were drilled and tested in 2013; Ain-Al-Safra, Zey Gawra and Banan which incurred a total of $61.7 million in drilling costs. Testing was completed on the Ain-Al-Safra and Zey Gawra wells during 2013 incurring a total of $16.7 million in costs. The Demir Dagh-4 appraisal well spudded in late December 2013 and incurred $2.1 million in capital expenditure before year end. During the year, the Demir Dagh-3 appraisal well was spudded incurring $12.0 million in costs.

million in capital expenditure relates to capitalised general and administrative costs for the year.

In addition to the drilling costs, $8.6 million in costs were capitalised relating to the Hawler Early Production Facility (EPF). The facility is expected to facilitate first production from Demir Dagh which is planned for Q2 2014. The EPF may also be utilised for the appraisal of other prospects in the Hawler license area.

During 2013, Oryx Petroleum carried out exploration, appraisal and development activities in its license areas. Oryx Petroleum had no commercial production during 2013 and, accordingly, did not book any revenue from continuing operations.

A further $17.6 million was capitalised during the year relating to an upward revision in fair value of the contingent payment on the Hawler license area, acquired as part of the business combination with OP Hawler Kurdistan Ltd (formerly Norbest Ltd) in 2011. Finally, $5.0 million in costs were incurred during the year relating to the 2D seismic campaign on the Banan area and the 3D seismic campaign on the Demir Dagh area. The remaining capital expenditure of $10.0 million relates to indirect capitalised general and administrative costs.

The actual costs incurred in 2013 for all license areas, other than Hawler and OML 141, were lower than the amounts budgeted. However this was more than offset by higher than budgeted costs in the Hawler license area due to accelerated exploration and development activities. There are no trends or events that have been identified that will have a material adverse effect on the financial performance of Oryx Petroleum. The Company is planning to commence production at Demir Dagh in the Kurdistan region of Iraq in the second quarter of 2014. It is currently uncertain if the oil produced will be able to be sold on the international market. This uncertainty could affect the future price of oil sold and thus OPCL’s cash flow. In addition, Oryx Petroleum is not currently aware of any official allocation on the pipeline in the region and how commercial terms for international sales would be established. The political instability in the regions in which Oryx Petroleum operates and other risk factors identified in the Forward Looking Information section could have an adverse effect on Oryx Petroleum’s performance; however this has not affected Oryx Petroleum’s business, results of operations or financial conditions to date.

Summary of Reserves and Resources The following is a summary of NSAI’s evaluation as at December 31, 2013 with comparatives to NSAI’s evaluation as at March 31, 2013: Oil reserves (1) Location

License

The $4.1 million of capital expenditure relating to the Wasit license area in 2013 relates to $1.3 million in seismic acquisition costs and $2.8 million in capitalised general and administrative expense. The OML 141 license area in Nigeria incurred $47.4 million in capital expenditure in 2013. This amount mainly relates to $42.3 million in drilling costs (including carried costs) relating to the Dila exploration well. However the well was deemed unsuccessful and $21.7 million in costs, representing OPCL’s share of well costs, were written off during the second quarter of 2013. Two wells were drilled in the Haute Mer A license area offshore Congo (Brazzaville) in 2013. Drilling on the Horse prospect (formerly Ma) incurred $17.3 million of exploration drilling costs and the Elephant prospect incurred $15.6 million in drilling costs. Testing on the Horse prospect was completed during the year but was deemed unsuccessful and an impairment charge of $17.3 million was recognised. Testing on the Elephant discovery began in December 2013 and was not completed at the time of issuance of this document; $5.5 million in testing costs were incurred prior to year end. The remaining $3.0

March 31, 2013

Proved plus Probable Gross Oil (Working interest) (2)

Iraq Kurdistan region Seismic acquisition and studies expenditure of $4.7 million was incurred in the Sindi Amedi license area during the 2013 fiscal year. A further $0.9 million in capital expenditure was incurred relating to PSC compliance costs and capitalised general and administrative expense. These amounts were offset by $1.6 million in drilling costs that were recovered from the operator during the period. However, all capital expenditure relating to this license area was written off in 2013 ($44.0 million) following the relinquishment of the license area to the Kurdistan Regional Government.

December 31, 2013

Hawler

Total oil reserves

Reserves

Future Net Revenue(3)

Reserves

Future Net Revenue(3)

(MMbbl)

($ million)

(MMbbl)

($ million)

213

1,287

164

815

213

1,287

164

815

Notes: 1. The oil reserves data is based on evaluations by NSAI, with effective dates as at March 31, 2013 and December 31, 2013 as indicated. Volumes are based on commercially recoverable volumes within the life of the production sharing contract. 2. Use of the word “gross” to qualify a reference to reserves or resources means, in respect of such reserves or resources, the total reserves or resources prior to the deductions specified in the production sharing contract, risk exploration contract or fiscal regime applicable to each license area. 3. After-tax net present value of related future net revenue using forecast prices and costs assumed by NSAI and a 10% discount rate. Gross proved plus probable oil reserve estimates used to calculate future net revenue are estimated based on economically recoverable volumes within the development/production period specified in the production sharing contract, risk exploration contract or fiscal regime applicable to each license area. The estimated values disclosed do not represent fair market value.

Contingent oil resources (1) Location

License

March 31, 2013

December 31, 2013

Best Estimate 2C Gross Oil (Working interest) (2)

Iraq Kurdistan region

Hawler

Congo (Brazzaville)

Haute Mer A(4)

Total contingent oil resources

Resources

Future Net Revenue(3)

Resources

Future Net Revenue(3)

(MMbbl)

($ million)

(MMbbl)

($ million)

217

697

200

1,451

6

-

-

-

223

697

200

1,451

Notes: 1. The contingent oil resource data is based on evaluations by NSAI, and the classification of such resources as “contingent oil resources” by NSAI, with effective dates as at March 31, 2013 and December 31, 2013 as indicated. The figures shown are NSAI’s best estimate using deterministic methods. Once all contingencies have been successfully addressed, the probability that the quantities of contingent oil resources actually recovered will equal or exceed the estimated amounts is 50% for the best estimate. Contingent oil resources estimates are volumetric estimates prior to economic calculations. 2. Use of the word “gross” to qualify a reference to reserves or resources means, in respect of such reserves or resources, the total reserves or resources prior to the deductions specified in the production sharing contract, risk exploration contract or fiscal regime applicable to each license area. 3. After-tax net present value of related future net revenue using forecast prices and costs assumed by NSAI and a 10% discount rate. Gross contingent oil resource estimates used to calculate future net revenue are estimated based on economically recoverable volumes within the development/production period specified in the production sharing contract, risk exploration contract or fiscal regime applicable to each license area. The estimated values disclosed do not represent fair market value. 4. An economic evaluation has not been performed by NSAI on the contingent oil reserves in Haute Mer A because the field development plan is still under construction.

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Prospective Oil Resources (1) Location

License

December 31, 2013

March 31, 2013

Best Estimate Gross(2) Oil (Working interest)

Iraq Kurdistan region

Hawler

Iraq Kurdistan region

Sindi Amedi

Iraq Wasit province

Unrisked

Risked

Unrisked

Risked

(MMbbl)

(MMbbl)

(MMbbl)

(MMbbl)

238

50

321

107

-(4)

-(4)

110

8

Wasit

404

78

404

77

AGC AGC Shallow

AGC Shallow

267

38

243

31

Nigeria

OML 141

67

10

153

42

Congo (Brazzaville)

Haute Mer A

31

4

56

12

Congo (Brazzaville)

Haute Mer B

160

31

104

23

1,167

209

1,391

299

Total prospective oil resources(3)

$33.5 million of the exploration drilling costs in 2013 relate to the Zey Gawra well (“ZEG1”), representing $21.8 million in drilling costs and $11.7 million in testing. The ZEG-1 well reached a total depth of 4,398 metres in early August 2013. The Company announced the successful discovery of oil at Zey Gawra in December 2013 based on a successful flow test from the Cretaceous reservoirs. The Company is conducting further analysis of the ZEG-1 well and intends to drill an appraisal well at Zey Gawra in 2014 as part of the multi-well appraisal and development drilling program in the Hawler license area. Depending upon the ultimate size of the Zey Gawra discovery, the field could be tied into the Company’s planned development at Demir Dagh or developed on a standalone basis.

Notes: 1. The prospective oil resource data is based on evaluations by NSAI, and the classification of such resources as “prospective oil resources” by NSAI, with effective dates as at March 31, 2013 and December 31, 2013 as indicated. The figures shown are NSAI’s best estimate using a combination of deterministic and probabilistic methods and are dependent on a petroleum discovery being made. If discovery is made and development is undertaken, the probability that the recoverable volumes will equal or exceed the risked estimates is 50% for the best estimate. Prospective oil resources estimates are volumetric estimates prior to economic calculations. 2. Use of the word “gross” to qualify a reference to reserves or resources means, in respect of such reserves or resources, the total reserves or resources prior to the deductions specified in the production sharing contract, risk exploration contract or fiscal regime applicable to each license area. 3. Individual numbers provided may not add to total due to rounding. 4. The Sindi Amedi license area was relinquished in October 2013.

Capital Expenditure The following table summarises the components of Oryx Petroleum’s capital expenditure per region for the periods indicated: Year ended Dec 31, 2013

Dec 31, 2012

($ thousand)

($ thousand)

85,919

37,346

Middle East Exploration drilling Seismic acquisition

9,618

2,900

Studies and capitalised G&A

11,072

11,355

License acquisition costs

17,575

40,000

Property, plant & equipment

30,501

-

Sub-Total Middle East

154,686

91,601

49,564

4,233

West Africa Exploration drilling Seismic acquisition

834

18,273

Studies and capitalised G&A

10,556

15,324

License acquisition costs

30,672

6,695

Property, plant & equipment

83

98

Sub-Total West Africa

91,709

44,623

Corporate

2,087

1,175

Total Capital Expenditure

248,482

137,399

Middle East Exploration drilling costs of $85.9 million in 2013 relate to drilling and testing in the Hawler license area on the Zey Gawra, Ain Al Safra, Banan and Demir Dagh wells. This is a $48.6 million increase from the exploration drilling costs incurred in 2012. The increase from 2012 relates solely to an expanded drilling program in 2013 compared to the prior year.

36

The Ain Al Safra well (“AAS-1”), which incurred $27.9 million in exploration drilling and testing costs in 2013, reached target depth in the third quarter of 2013 and the oil discovery was announced by the Company in October 2013. AAS-1 was originally scheduled to drill to a total depth of 3,700 meters in Q4 2013. Drilling was suspended and the well secured at the 3,039 metre depth as heavy losses of drilling fluids caused the bottom hole assembly to become stuck. The well was logged down to the lowermost Jurassic and there was evidence of oil shows in the Cretaceous, Jurassic and lower Jurassic of varying quality. The Cretaceous reservoir was deemed wet and not tested. In the lower Jurassic reservoirs, free oil on the shakers and sizable losses of drilling fluids were observed with significant quantities of oil flowing to the surface while drilling. Testing was completed in 2013. Oryx Petroleum is conducting further analysis of the AAS-1 well and intends to drill an appraisal well at Ain Al Safra in 2014. Oryx Petroleum spudded the BAN-1 well, also in the Hawler license area, late in the third quarter of 2013, targeting oil potential in the Cretaceous, Jurassic and Triassic. Drilling depth of 4,000 meters was reached at the end of 2013 with a planned total depth of 4,153 metres to be reached in Q1 2014. A total of $18.4 million in drilling expenditure was incurred. In January 2014, the drilling program concluded and hydrocarbons were encountered in the Cretaceous, Upper and Lower Jurassic and Triassic. The well experienced a significant pressure kick while drilling at approximately 4,000 meters in a fractured section of the Kurra Chine. During the following well control operation, light oil from the Kurra Chine formation was burned at the flare. As the well had not been designed for conditions encountered

in the Triassic, the well was plugged back to 3,400 meters in preparation for testing operations in the shallower Cretaceous and Jurassic formations. A future appraisal well with modified well design, if pursued, should enable evaluation of the Kurra Chine formation in the Banan structure. The Company’s testing program for BAN-1 consists of five casedhole drill stem tests and one contingent cased-hole drill stem test. It is expected that the testing program will conclude in March 2014. Should the testing be successful, the Company is considering accelerating plans to drill an appraisal well on the crest of the Banan structure. The first well in the Demir Dagh Appraisal program (DD-3) was spudded in midNovember and drilling reached 2,875 meters as at December 31, 2013. The DD-3 well is on schedule and is expected to reach a total depth of 4,115 meters in Q2 2014.

reach gross (100%) production capacity of 25,000 bbl/d in Q4 2014. With further development drilling, Oryx Petroleum expects to achieve the full gross (100%) production design capacity of 40,000 bbl/d in 2015. The Company plans to transport production by truck or through export pipelines. The EPF may also be utilised for the appraisal of the other prospects in the Hawler license area. The timing of the start of production is dependent on the timing of the installation of the facilities and completion of wells drilled.

the AGC Shallow license area. An additional adjustment of $0.5 million was recorded on the OML 141 license area. This amount has decreased by $4.7 million compared to $15.3 million in expenditure for the year ended in 2012. This decrease is related to pre-drilling activity on the OML 141 license area in 2012 that was not performed in 2013. All costs relating to the Dila well in the OML 141 license area were impaired during the year. The license acquisition costs incurred in 2013 relate solely to the cost of farming-in to the OML 141 license area.

West Africa

Seismic acquisition expenditure increased by $6.7 million to $9.6 million from 2012 to 2013. This amount includes $4.0 million in expenditure on the Sindi Amedi license area, $4.4 million on the Hawler license area and $1.3 million in the Wasit license area. Studies and capitalised general and administrative expenditure of $11.1 million remained consistent with prior year. The acquisition costs recognised in 2013 relate to an upward revision in fair value of $17.6 million to the contingent payment on the Hawler license area, acquired as part of the business combination with OP Hawler Kurdistan Ltd (formerly Norbest Ltd) in 2011. In September, 2013, Oryx Petroleum and its partner relinquished the Sindi Amedi license area resulting in an impairment charge of $45.2 million. The $30.5 million expenditure in property plant & equipment (“PP&E”) during 2013 relates to the development of the Demir Dagh area. The discovery on this license area was announced in the first quarter of 2013 therefore there were no costs in PP&E associated with this development in 2012. Subsequent to year end, the Company determined the discovery at the Demir Dagh area to be commercial pursuant to the terms of the Hawler Production Sharing Contract. Oryx Petroleum is currently undertaking an extensive appraisal program in relation to the full Demir Dagh field, and will continue to undertake such appraisal activities through 2014. During 2013 Oryx Petroleum agreed to lease an early production facility (“EPF”) from Expro, an international oilfield services company specialising in well flow management. The facility will have multiple trains with the ability to process light, heavy, sweet or sour crude types. The EPF will have an initial capacity of 25,000 bbl/d and will be re-engineered to a capacity of 40,000 bbl/d. The Company expects the appraisal program to be largely complete by mid-2014 with first production targeted for Q2 2014 from the Demir Dagh-2 well and the Demir Dagh-4 appraisal well with gross (100%) production totalling approximately 7,000 to 9,000 bbl/d. It is expected that following the drilling of Demir Dagh-3, an additional appraisal well and three development wells, the EPF will

In West Africa, exploration drilling for the year ended December 31, 2013 of $49.6 million relates to drilling on the E-1 exploration well targeting the Elephant (formerly Xiang) prospect and the H-1 well targeting the Horse prospect (formerly Ma) in the Haute Mer A license area in Congo (Brazzaville), as well as drilling on the Dila well in OML 141 in Nigeria. On the E-1 exploration well, Oryx Petroleum discovered natural gas and crude oil. The Elephant discovery will be tested in early 2014 as part of the multi-well drilling and testing program in the Haute Mer A license area. The H-1 well spudded during the third quarter of 2013, and drilling was completed in the fourth quarter. Although the H-1 well encountered both Tertiary and Cretaceous reservoirs with good porosity, the reservoirs were water bearing and the Company considers the well unsuccessful. An impairment charge of $17.3 million was recognised during the fourth quarter of 2013. During 2013, drilling expenditure of $17.6 million related to the Dila well in OML 141 in Nigeria. The costs for this well were impaired in the second quarter of 2013 as no commercially viable reserves were discovered. Seismic acquisition expenditure of $0.8 million for the year ended December 31, 2013 relates mainly to the AGC Shallow license area. This amount has decreased by $17.4 million compared to the same period in 2012 as activity was mainly focused on data evaluation during the current year. Studies and capitalised general and administrative expenditure of $10.6 million for the year ended December 31, 2013 includes $9.1 million of expenditure on the Haute Mer A license area and $2.0 million on

37

2014 Budgeted Capital Expenditure The following table summarises Oryx Petroleum’s 2014 annual budgeted capital expenditure programs.

Location

License ($ million)

Kurdistan region

Hawler

Wasit Province

Wasit

Nigeria

Acquisition & Special Permits

Drilling

Facilities

Seismic & Studies

Other

Total

($ million)

($ million)

($ million)

($ million)

($ million)

($ million)

-

217.0

81.0

45.6

23.0

366.6

1.6

-

-

18.7

6.7

27.0

OML 141

-

-

-

14.6

4.6

19.1

AGC

AGC

-

40.0

-

0.3

4.6

44.9

Congo

HMA

-

27.3

-

1.4

3.1

31.8

HMB

-

34.8

-

0.8

3.5

39.1

Corporate

-

-

-

-

1.3

1.3

1.6

319.1

81.0

81.4

46.7

529.8

Corporate Capex Total

Budgeted capital expenditures include 14 wells to be completed in 2014 – 3 exploration (Banan on Hawler, HMB and AGC), 6 appraisal (5 wells on Hawler and 1 on HMA) and 5 development (all on Hawler). Budgeted seismic expenditures include seismic campaigns on Hawler, Wasit and OML141 license areas. Budgeted facilities expenditures relate to the installation of an Early Production Facility and expenditures on the Permanent Production Facility on the Hawler license area.

Exploration and Evaluation Assets Oryx Petroleum invested further in exploration and evaluation assets, transferred a portion of costs to property, plant and equipment relating to discovered reserves and impaired a portion of costs related to unsuccessful exploration during 2013.

Net book value Exploration and Evaluation Assets

At December 31, 2013

At December 31, 2012

($ thousand)

($ thousand)

199,900

478,302

Following a reserve report from Netherland, Sewall & Associates Inc. (NSAI), effective March 31, 2013, indicating the discovery of reserves at Demir Dagh within the Hawler license area in Kurdistan, a portion of the exploration and evaluation costs relating to this license area were transferred to property, plant and equipment (PP&E). As a result, $373.2 million of costs associated with the license were transferred from intangible assets to oil and gas assets classified as PP&E as of December 31, 2013. A subsequent NSAI report, effective December 31, 2013 included the discovery of reserves at Zey Gawra within the Hawler license area. As a result, $33.5 million of costs associated with Zey Gawra were transferred to PP&E from intangible oil and gas assets during 2013. A total of $82.9 million in impairment expense was recorded during 2013. This impairment expense is comprised of $21.7 million relating to the Dila prospect in the OML 141 license area in Nigeria, $17.3 million relating to the Horse prospect (formerly Ma) in the Haute Mer A license area offshore Congo (Brazzaville), and $43.9 million relating to the relinquishment of the Sindi Amedi license. The net reduction in intangible assets during the year ended December 31, 2013 of $278.4 million reflects the transfer to PP&E of $406.7 million due to the successful drilling on the Hawler license area at Demir Dagh and Zey Gawra, and the impairment charge of $82.9 million, offset by additions of $211.3 million.

38

Property Plant and Equipment The property plant and equipment balance comprises oil and gas assets relating to the Hawler license area, as well as furniture and fixtures.

Oil and gas assets Furniture and fixtures Property plant and equipment

At December 31, 2013

At December 31, 2012

($ thousand)

($ thousand)

441,767

-

2,057

575

443,824

575

Oil and gas assets as at December 31, 2013 includes $406.7 million in expenditure transferred from intangible E&E assets following the discovery of reserves at Demir Dagh ($373.2 million) and Zey Gawra ($33.5 million), both within the Hawler license area. A further $35.0 million in additions were incurred during the year which relate to the development of the Hawler license area.

Financial Results General and Administrative Expense The following table summarises the component parts of general and administrative expense for the 2013 and 2012 financial years. Year ended

General and administrative costs

Dec 31, 2013

Dec 31, 2012

($ thousand)

($ thousand)

15,084

10,883

(1)

25,047

11,729

Total General and administrative expense

40,131

22,612

Stock-based compensation Notes:

1. Includes cash and non-cash expenses related to the OPCL Long Term Incentive Plan (“OPCL LTIP”).

General and administrative expense increased by $17.5 million to $40.1 million during the year ended December 31, 2013 compared to the previous year (2012: $22.6 million). The increase was primarily due to the increase in stock-based compensation expense in the second quarter due to the share grant to employees and management in conjunction with the Offering ($13.7 million). The increase in other general and administrative costs was mainly due to additional staff numbers (average headcount for 2013 of 71 compared to 39 in 2012). Exploration Expense Pre-license costs in 2013 were at a similar level to those in 2012. Impairment of oil and gas assets includes the impairment of unsuccessful exploration wells during the year. Year ended Dec 31, 2013

Dec 31, 2012

($ thousand)

($ thousand)

Pre-license costs

6,383

6,608

Impairment of oil and gas assets

82,948

29,017

Total Exploration Expense

89,331

35,625

The $53.9 million increase in impairment of oil and gas assets in 2013 compared to 2012 relates to an increase in wells written off during the current year. In 2012, the impairment expense solely relates to the Mateen-1 well drilled in conjunction with the operator of the Sindi Amedi license area. This impairment charge was adjusted downward in the second quarter of 2013 by $1.2 million based on new information from the operator. During 2013, the drilling on the Dila prospect in the OML 141 license area was impaired as the well was considered unsuccessful, resulting in an impairment charge of $21.7 million. A further impairment charge of $17.3 million was recognised relating to the H-1 well in the Horse prospect of Haute Mer A license area offshore Congo (Brazzaville). The remaining impairment expense of $45.2 million relates to the relinquishment of the Sindi Amedi license area.

39

Depreciation and Amortisation Expense The following table summarises the component parts of depreciation and amortisation expense for years ended December 31, 2013 and December 31, 2012. Year ended Dec 31, 2013

Dec 31, 2012

($ thousand)

($ thousand)

Intangible assets: amortisation expense

437

271

Property, Plant and Equipment assets: depreciation expense

291

90

Total Depreciation and Amortisation Expense

728

361

Other Expenses The following table summarises the components of other operating expense for the years ended December 31, 2013 and December 31, 2012. Year ended Dec 31, 2013

Dec 31, 2012

($ thousand)

($ thousand)

Other operating expense

56,887

-

Financial (income) / expense - net

(2,573)

142

Other expenses

54,314

142

During 2013, total other operating expense increased to $56.9 million due to the reevaluation of contingent consideration arising from the acquisition of OP Hawler Kurdistan Ltd in 2011. In accordance with the terms of the agreement for the acquisition of OP Hawler Kurdistan Ltd, which holds the interest in the Hawler license area, Oryx Petroleum is obliged to provide additional consideration upon a declaration of commercial discovery as outlined in the Hawler production sharing contract (“PSC”). The aggregate fair value of the contingent consideration, based on the estimated probability of success, was initially evaluated by the directors of Oryx Petroleum Corporation Limited at $46.3 million in total and $27.7 million of this amount was recognised in Oryx Petroleum’s statement of financial position at December 31, 2012 with

the remaining amount included as an increase in intangible E&E assets. In addition, the net assets and liabilities acquired with OP Hawler Kurdistan Ltd included a contingent payment to the Kurdistan Regional Government in relation to the first commercial discovery. The total potential liability is $50.0 million, the fair value of which was initially evaluated by the directors of Oryx Petroleum Corporation Limited at $32.4 million and recognised in the fair values of identifiable assets and liabilities acquired. Following the discovery of reserves at Zey Gawra and Demir Dagh, the fair value of the contingent consideration was re-evaluated and estimated at $134.6 million, resulting in

increases in fair value recorded for contingent consideration and the contingent payment, amounting to $74.5 million, of which $56.9 million in relation to contingent consideration was recognised in the statement of comprehensive income and $17.6 million in relation to the contingent payment was capitalised and then transferred from intangible assets to property, plant and equipment oil and gas assets. A portion of the contingent consideration is expected to be paid within one year. A payment of $50.0 million was made to the Kurdistan Regional Government in February 2014 in full settlement of the contingent payment due.

Income Tax Expense The following table summarises the component parts of income tax expense for the 2013 and 2012 fiscal years. Year ended

40

Dec 31, 2013

Dec 31, 2012

($ thousand)

($ thousand)

Current income tax expense

1,361

667

Deferred tax benefit

(42)

(870)

Total Income Tax Expense / (Benefit)

1,319

(203)

Summary of Quarterly Results The following table sets forth a summary of Oryx Petroleum’s results for the quarterly periods indicated. 2012 Mar 31

Jun 30

2013 Sept 30

Dec 31

Mar 31

($ thousand)

Jun 30

Sept 30

Dec 31

($ thousand)

Net (Income) Loss from Continuing Operations before Income Taxes is Comprised of: Oil and Gas (1)

1,189

32,652

95

1,689

1,672

21,934

47,040

18,685

Corporate and Other(2)

2,363

3,003

7,025

10,724

45,237

16,062

17,855

16,019

Net loss before income tax

3,552

35,655

7,120

12,413

46,909

37,996

64,895

34,704

Income Tax Expense / (Benefit)

(205)

65

7

(70)

67

494

252

506

Net loss

3,347

35,720

7,127

12,343

46,976

38,490

65,147

35,210

per share

0.19

1.99

0.13

0.23

0.59

0.44

0.66

0.35

Net loss attributable to owners of OPCL (excluding noncontrolling interests)

3,285

35,685

7,046

12,343

46,815

38,457

65,109

35,183

Per share

0.18

1.99

0.27

0.23

0.59

0.43

0.65

0.35

Remeasurement of defined benefit obligation

-

-

-

2,542

-

-

-

1,424

Total comprehensive loss

3,347

35,720

7,127

14,885

46,976

38,490

65,147

36,634

per share

0.18

1.99

0.27

0.28

0.59

0.43

0.65

0.37

Total comprehensive loss attributable to owners of OPCL (excluding noncontrolling interests)

3,285

35,685

7,046

14,885

46,815

38,457

65,109

36,607

Per share

0.18

1.99

0.27

0.28

0.59

0.43

0.65

0.37

Capital expenditure

11,728

13,689

30,507

81,475

54,430

48,946

69,241

75,865

Notes: 1. Oil and gas expense includes pre-license and impairment expense 2. Corporate and other expense includes general and administrative expense, depreciation and amortisation expense and other operating expense

The net loss of $35.2 million for the three months ended December 31, 2013 includes the $17.3 impairment expense relating to the Horse prospect (formerly Ma) in the Haute Mer A license area offshore Congo (Brazzaville). Drilling on this well was completed in the fourth quarter of 2013. Although the H-1 well encountered both Tertiary and Cretaceous reservoirs with good porosity, the reservoirs were water bearing. The Company considers the well unsuccessful. The loss for the quarter also includes $2.3 million recorded as interest expense relating to accrued interest on contingent consideration arising from the acquisition of OP Hawler Kurdistan Ltd. A further $7.8 million was expensed due to the re-evaluation of the fair value of the contingent consideration relating to Hawler. The remaining costs consist of $2.3 million in stock-based compensation and $3.7 million in general and administrative costs.

The net loss of $65.1 million for the three months ended September 30, 2013 includes the impairment expense relating to the relinquishment of the Sindi Amedi license during the period ($45.2 million). In addition $9.8 million was expensed due to the reevaluation of the contingent consideration relating to Hawler by moving a portion of the payment from long-term to short-term as well as changes to the risking based on recent drilling results. A stock-based compensation expense of $4.5 million was also recorded in the third quarter of 2013. The net loss of $38.5 million for the three months ended June 30, 2013 includes the impairment of the Dila-1 well in the OML 141 license area of $21.7 million and the share gift granted to employees and management in conjunction with the IPO of $13.7 million. The net loss of $47.0 million for the three months ended March 31, 2013 includes the change in fair value of contingent

consideration for Hawler of $39.3 million following the discovery of reserves at Demir Dagh-2. The increase in the fourth quarter 2012 net loss of $12.3 million compared to the third quarter 2012 net loss of $7.1 million was due to bonus payments in December of $1.2 million, IPO preparation costs of $1.7 million and additional LTIP costs for new employees and costs for directors of $1.8 million. Net loss from continuing oil and gas operations comprises pre-license costs and, in June 2012, the impairment of the Mateen well in the Sindi Amedi license area of $31.1 million and in June 2013, the impairment of the Dila-1 well in the OML-141 license area of $21.7 million. The impairment charge for Sindi Amedi was subsequently reviewed and adjusted in September 2012 based on new information, resulting in a write-back of $2.1 million and an additional write-back in the second quarter of 2013 of $1.2 million.

41

Annual Information The following table sets forth a summary of Oryx Petroleum’s results for the years indicated. Year ended Dec 31, 2013

Dec 31, 2012

Dec 31, 2011

($ thousand)

($ thousand)

($ thousand)

Net (Income) Loss from Continuing Operations before Income Taxes is Comprised of: 89,331

35,625

1,894

(2)

95,173

23,115

14,458

Oil and Gas (1) Corporate and Other

Net loss before income tax

184,504

58,740

16.352

Income Tax Expense / (Benefit)

1,319

(203)

348

Net loss

185,823

58,537

16,700

per share

2.05

2.10

2.72

Net loss attributable to owners of OPCL (excluding non-controlling interests)

185,564

58,359

16,700

Per share

2.04

2.10

2.72

Remeasurement of defined benefit obligation

1,424

2,542

-

Total comprehensive loss

187,247

61,079

16,700

per share

2.06

2.19

2.72

Total comprehensive loss attributable to owners of OPCL (excluding non-controlling interests)

186,988

60,901

16,700

Per share

2.06

2.19

2.72

Capital expenditure

248,482

137,399

371,581

Total assets

976,212

576,265

401,142

Long term debt

-

-

16,599

Notes: 1. Oil and gas expense includes pre-license and impairment expense 2. Corporate and other expense includes general and administrative expense, depreciation and amortisation expense and other operating expense

The company has not distributed cash dividends during the 2013, 2012 or 2011 financial years.

Liquidity and Capital Resources The following table summarises the components of Oryx Petroleum’s consolidated change in cash flow for the periods indicated: Year ended Dec 31, 2013

Dec 31, 2012

($ thousand)

($ thousand)

Funds flow absorbed by operations

(77,273)

(17,850)

Decrease / (Increase) in non-cash Working Capital

68,541

(5,906)

Net cash used in operating activities

(8,732)

(23,756)

Net cash used in investing activities

(234,079)

(92,900)

Net cash generated by financing activities

476,120

164,100

Net Increase in Cash and cash equivalents

233,309

47,444

The net change in cash for the year ended December 31, 2013 of $233.3 million is primarily due to $476.1 million from financing activities which is offset by cash used in investing activities of $234.1 million. The cash received from financing activities includes funding received from AOG ($234.8 million) and the net proceeds received from the IPO ($230.5 million) and other investors ($10.8 million). The net investing activities for year

42

ended December 31, 2013 of $234.1 million comprises mostly of $136.8 million on the Hawler license area, $38.1 million on the OML-141 license area, $45.0 million on the Congo Haute Mer A license area, $5.3 million on the Sindi Amedi license area, $4.9 million on the Wasit license area and $2.8 million on the AGC Shallow license area.

Oryx Petroleum meets its day to day working capital requirements through the funding received from the IPO and the balance of $723 million in equity funding provided by AOG and other investors. AOG’s equity funding ($700 million) was fully invested in shares by the end of the first quarter 2013. Oryx Petroleum entered into an uncommitted bond facility agreement in 2013 whereby up to a maximum of US$15 million may be used by Oryx Petroleum for bank guarantees. As of December 31, 2013, no guarantees were issued under this agreement. This agreement was extended for an additional twelve months in February 2014. Oryx Petroleum’s business requires significant capital expenditures for the foreseeable future with respect to the exploration, appraisal, development and maintenance of its oil and gas assets. There can be a long lead time between discovery and production of oil and gas, particularly for gas. During this lead time, Oryx Petroleum will continue to incur significant costs at a level which may be difficult to predict, but may not have any earnings from oil or gas production. Oryx Petroleum intends to fund these planned capital expenditures from its cash reserves in the short term and, in the longer term, from new equity financing and, if successful in its

exploration and development efforts, from operating cash flow and new debt. The ability of Oryx Petroleum to arrange such financing in the future will depend in part upon prevailing market conditions, as well as the business performance of Oryx Petroleum. OPCL has a substantial capital expenditure program, budgeted to be approximately $529.8 million in 2014. This capital expenditure program is expected to fund three exploration wells (Banan on Hawler, HMB and AGC), six appraisal wells (five wells on Hawler and one on HMA) and five development wells (all on Hawler). In addition, the program is funding two separate 2-D seismic acquisition programs covering over 350 square kilometres, one 3-D seismic acquisition program and general corporate expenditures. Of the total budgeted capital expenditure program for 2014 ($529.8 million), $141.1 million is committed at December 31, 2013 to be spent within one year. Refer to Contractual Obligations section for additional details. Oryx Petroleum has no debt and a considerable degree of control over both the extent and timing of expenditure under its future capital investment program.

Changes in Working Capital The following table summarises the components of Oryx Petroleum’s consolidated change in working capital for the periods indicated ($ thousand): 2012 Mar 31

Jun 30

2013 Sept 30

Dec 31

Mar 31

($ thousand)

Jun 30

Sept 30

Dec 31

($ thousand)

Trade and other receivables

(983)

995

2,291

4,238

(37)

(6,282)

(804)

(1,432)

Inventories

577

1,694

2,545

712

432

3,114

(755)

4,073

Trade and other payables

260

(1,594)

(3,356)

(1,473)

(38,222)

4,553

(16,296)

(16,885)

Total Change in Non-Cash Working Capital

(146)

1,095

1,480

3,477

(37,827)

1,385

(17,855)

(14,244)

Change in Cash and Cash equivalents

3,673

10,809

96,769

(63,807)

172,770

191,979

(60,041)

(71,399)

Total Change in Net Working Capital

3,527

11,904

98,249

(60,330)

134,943

193,364

(77,896)

(85,643)

Short term debt

46,096

(29,209)

188,976

(100)

7,781

-

-

-

Long term debt

-

2,704

13,895

-

-

-

-

-

Equity attributable to owners of OPCL

(60,092)

34,229

(322,520)

11,094

(198,172)

(218,826)

60,805

25,889

Non-controlling interests

62

35

81

-

161

33

38

8,377

43

Use of Proceeds from IPO The following table compares the planned use of proceeds from the prospectus offering to the position at December 31, 2013: As at May 15, 2013

As at Dec 31, 2013

Variance

($ million)

($ million)

($ million)

483

306

(177)

The remainder of the 2013 capital expenditure program

284(1)

-

(284)

The remainder of 2013 pre-license and G&A costs

16(1)

-

(16)

The estimated expenditures of 1H 2014 capital expenditure program

124

201

77

The estimated pre-license and G&A costs for 1H 2014

Cash to fund the following:

12

9

(3)

(2)

47

96

49

Total

483

306

(177)

General corporate purposes

Notes: 1. Estimated as at March 31, 2013. 2. Including contingent acquisition payments, if any, and acquisitions, if any.

Cash has reduced by $177 million due to the expenditure between the IPO date and December 31, 2013. Capital expenditure for the remainder of 2013 has reduced by $284 million between the IPO date and December 31, 2013 due to expenditure between the two dates and the relinquishment of the Sindi Amedi license area in which Oryx Petroleum had expected to drill an exploration well. Pre-license costs and general and administrative costs for the remainder of 2013 have decreased by $16 million due to expenditure between the IPO date and December 31, 2013. None of the variances will impact OPCL’s ability to achieve its business objectives and milestones. The estimated expenditures of the 1H 2014 capital expenditure program, and pre-license costs and general administrative costs for 1H 2014, have increased to reflect OPCL’s 2014 capital budget as announced in November 2013. The major changes between the estimated and budget amounts are the removal of exploration and appraisal wells in Sindi Amedi, Wasit and OML 141 which have been more than offset by two additional rigs drilling appraisal and development wells, together with expenditure on early production facilities, at Demir Dagh in the Hawler license area and an appraisal well in the Haute Mer A license area in Congo (Brazzaville).

Non-IFRS Measures OPCL defines “Cash surplus / (Net debt)” as long-term debt and short-term borrowings less cash and cash equivalents. OPCL uses net debt as a key indicator of its leverage and to monitor the strength of its balance sheet. Net debt is directly tied to OPCL’s operating cash flow and capital investment. Net debt is not recognised under IFRS as issued by IASB. Readers are cautioned that these measures should not be construed as an alternative to net income or cash flow from operating activities determined in accordance with IFRS or as an indication of OPCL’s performance. OPCL’s method of calculating this measure may differ from other companies and accordingly, it may not be comparable to measures used by other companies. The following table summarises the components of Oryx Petroleum’s consolidated change in “Cash surplus / (Net debt)” for the periods indicated: As at Dec 31, 2013

As at Dec 31, 2012

($ thousand)

($ thousand)

Borrowings

44

Current

-

7,781

Non- current

-

-

Total Borrowings

-

7,781

Less: Cash and cash equivalents

306,034

(72,725)

Cash surplus

(306,034)

(64,944)

Equity Security Repurchases There were no repurchases of OPCL’s equity securities during the three months or year ended December 31, 2013.

Outstanding Share Data The number of common shares outstanding at as at the date of this document is 99,885,635. There are no securities convertible into or exercisable or exchangeable for voting shares. There are LTIP awards that have been granted pursuant to the OPCL LTIP which, upon vesting in accordance with the OPCL LTIP, will result in the issuance of up to an aggregate of 865,954 shares over 2014 and 2015.

Off Balance Sheet Arrangements In order to hedge foreign currency transactions in the ordinary course of business, Oryx Petroleum entered into a forward exchange contract with Credit Suisse in December 2012 to purchase CHF 1,500,000 per month for the 12 months of 2013. There are no forward currency contracts outstanding as at December 31, 2013. Refer to Financial Instruments and Other Instruments section.

On May 9, 2013, Oryx Petroleum sold CAD $150 million and purchased $149.4 million at the forward rate of CAD $1.0043 per $1, with delivery on May 21, 2013. A foreign exchange gain of $3.1 million was realised on this transaction. Other than the above transactions, Oryx Petroleum was not party to any off-balance sheet arrangements during the year ended December 31, 2013 that will have, or is reasonably likely to have, an effect on the performance or financial condition of Oryx Petroleum. Further, on the date of this MD&A, Oryx Petroleum is not party to any such off-balance sheet arrangements.

Contractual Obligations The table below sets forth information relating to Oryx Petroleum’s contractual obligations and commitments as at December 31, 2013. The other long term obligations include the lease signed during the third quarter of 2013 for the Early Production Facility relating to the Hawler license area. Within One Year

From 1 to 5 Years

More than 5 Years

Total

($ thousand)

($ thousand)

($ thousand)

($ thousand)

Operating leases(1)

677

139

-

816

Other long term obligations(2)

141,110

36,821

-

177,931

Total

141,787

36,960

-

178,747

Notes: 1. Operating leases primarily relate to property and computer hardware 2. Consists principally of obligations related to PSC commitments and capital expenditure commitments. The main purpose of these commitments is to develop oil and gas assets in Oryx Petroleum’s various exploration areas.

Financial Instruments and Other Instruments

Transactions with Related Parties

OPCL operates internationally and has foreign exchange risk arising from various currency exposures, notably the Swiss franc. In order to hedge against this exposure, OPCL entered into a forward exchange contract in December 2012 to sell U.S. dollars and buy Swiss francs. By entering into this contract, OPCL has the right and the obligation to sell U.S. dollars and buy Swiss francs at a predetermined time and at a predetermined U.S. dollar / Swiss franc exchange rate if either the spot exchange rate trades at or below the lower exercise price or at or above the upper exercise price. This contract expired in December 2013 and no forward currency exchange contracts were outstanding as at December 31, 2013. Any gains or losses arising from the application of this contract have been charged to the statement of comprehensive income.

For the year ended December 31, 2013, OPCL incurred $4.2 million for goods and services provided by related parties, all of which are subsidiaries of AOG (2012: $4.6 million). Those costs mainly concerned trademark license fees, parent company guarantees, management service fees, furniture and fixtures, and have been incurred under agreements between OPCL and AOG that continue to be in place. Additional information relating to such agreements is available in OPCL’s Supplemented PREP Prospectus dated May 8, 2013, which is available on SEDAR at www.sedar.com.

In addition to the forward exchange contract above, OPCL entered into a second forward exchange contract in the second quarter of 2013 that settled in the same period. Oryx Petroleum sold CAD $150 million at a forward rate of CAD $1.0043. A foreign exchange gain of $3.1 million was realised on this transaction.

In addition, during the third quarter of 2013, OPCL made a donation to The Addax and Oryx Foundation for $0.5 million. The Addax and Oryx Foundation is an independently governed, Swiss registered charitable foundation dedicated to support initiatives in the provision of medical, educational and food security needs in Africa and Asia. In January 2013, AOG subscribed for shares to the value of $234.8 million. In May 2013, AOG subscribed for shares through the IPO to the value of $20.0 million, which brings total funding from AOG to $720.0 million. In addition, certain directors of OPCL subscribed in the IPO in the aggregate amount of $2.0 million.

Proposed Transactions There are no planned asset or business acquisitions or dispositions that would have a material effect on the financial condition, financial performance and cash flows of Oryx Petroleum.

New Accounting Pronouncements Oryx Petroleum has adopted all of the new and revised standards and interpretations issued by the IASB and IFRIC that are relevant to its operations and effective for accounting periods beginning on or after January 1, 2013 as described in Note 2 of the consolidated financial statements for the year ended December 31, 2013. The adoption of these standards and interpretations has not had a material effect on OPCL, except for the adoption of IAS 19 (2011) Employee Benefits. Implementation of this standard resulted in an additional expense of $2.1 million for the year ended December 31, 2013 (2012: $3.6 million).

During the third quarter of 2013, the directors of OPCL were awarded, in aggregate, 12,882 common shares ($0.1 million) and $0.1 million in cash as remuneration for services provided in the first and second quarter of 2013. In January 2014, the directors were awarded 12,446 common shares ($0.1 million) and $0.2 million in cash as remuneration for services provided in the third and fourth quarters of 2014.

45

Financial Controls and Risk Management

Forward-Looking Information

Disclosure Controls and Procedures

Certain statements in this MD&A constitute “forward-looking information”, including statements related to the nature, timing and effect of Oryx Petroleum’s future capital expenditures and budget, financing and capital activities, business and acquisition strategy and goals, opportunities, reserves and resources estimates and potential, drilling plans, development plans and schedules and chance of success, future seismic activity, results of exploration activities, declarations of commercial discovery, contingent liabilities and government approvals, the ability to gain access to exterior facilities or build necessary facilities to sell future oil production, if any, future drilling of new wells, ultimate recoverability of current and longterm assets, future royalties and tax levels, access to future financing and liquidity, future debt levels, availability of committed credit facilities, possible commerciality of our projects, expected operating capacity, expected operating costs, estimates on a per share basis, future foreign currency exchange rates, future expenditures, changes in any of the foregoing and statements that contain words such as “may”, “will”, “would”, “could”, “should”, “anticipate”, “believe”, “intend”, “expect”, “plan”, “estimate”, “budget”, “outlook”, “propose”, “potentially”, “project”, “forecast” or the negative of such expressions and statements relating to matters that are not historical fact, constitute forward-looking information within the meaning of applicable Canadian securities legislation.

Disclosure Controls and Procedures (“DC&P”) have been designed under the supervision of the Chief Executive Officer (“CEO”) and the Chief Financial Officer (“CFO”), with the participation of other management, to provide reasonable assurance that information required to be disclosed is recorded, processed, summarised and reported within the time periods specified in applicable securities legislation, and include controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to management, including the CEO and CFO, as appropriate to allow timely decisions regarding required disclosure. An evaluation of the design and operation of OPCL’s DC&P was carried out during 2013 under the supervision of, and with the participation of management including its certifying officers. Based on that evaluation, the certifying officers concluded that the design and operation of the DC&P were effective as at December 31, 2013. Internal Control Over Financial Reporting Internal Controls over Financial Reporting (“ICFR”) have been designed under the supervision of the CEO and the CFO, with the participation of other management, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with IFRS. ICFR can only provide reasonable assurance and may not prevent or detect misstatements. Projections of an evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate due to changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate. An evaluation of the design and operation of OPCL’s ICFR was carried out during 2013 under the supervision of, and with the participation of management, including its certifying officers. Based on that evaluation, the certifying officers concluded that the design and operation of the ICFR were effective as at December 31, 2013.

46

In addition, information and statements in this MD&A relating to reserves and resources are deemed to be forward-looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and that the reserves and resources described can be profitably produced in the future. See “Reserves and Resources Advisory” below. Although Oryx Petroleum believes these statements to be reasonable, the assumptions upon which they are based may prove to be incorrect. In making certain statements in this MD&A, Oryx Petroleum has made assumptions with respect to the following: the general continuance of the current or, where applicable, assumed industry conditions, the continuation of assumed tax, royalties and regulatory regimes, forecasts of capital expenditures and the sources of financing thereof, timing and results of exploration activities, access to local and international markets for future crude oil production, if any and future crude oil prices, Oryx Petroleum’s ability to obtain and retain qualified staff, contractors and personnel and equipment in a timely and cost-efficient manner, the political situation and stability in jurisdictions in which Oryx Petroleum has licenses, the ability to renew its licenses on attractive terms, Oryx Petroleum’s future production levels, the applicability of technologies for the recovery and production of Oryx Petroleum’s oil reserves and resources, the amount, nature, timing and effects of capital expenditures, geological and engineering estimates in respect of Oryx Petroleum’s reserves and resources, the geography of the areas in which Oryx Petroleum is conducting exploration and development activities,

operating and other costs, the extent of Oryx Petroleum’s liabilities, and business strategies and plans of management and Oryx Petroleum’s business partners. Forward-looking information is subject to known and unknown risks and uncertainties which may cause actual results or events to differ materially from those anticipated in the forward-looking information and statements if the assumptions underlying them prove incorrect, or if one or more of the uncertainties or risks described below materialises. The risks and uncertainties affecting Oryx Petroleum include, but are not limited to, imprecision of reserves and resources estimates; ultimate recovery of reserves, ability to commercially develop its oil reserves and/or its prospective and contingent oil resources; commodity prices; general economic, market and business conditions; industry capacity; competitive action by other companies; refining and market margins; the ability to produce and transport crude oil and natural gas to markets; weather and climate conditions; results of exploration and development drilling and other related activities; fluctuation in interest rates and foreign currency exchange rates; ability of suppliers to meet commitments; actions by governmental authorities, including increases in taxes; decisions or approvals of administrative tribunals, renewal or granting of licenses; changes in environmental and other regulations; international political events; renegotiations of contracts; reliance on key managers and personnel; dry wells may lead to a downgrading of Oryx Petroleum’s licenses or contracts or require further funds to continue exploration work; future foreign currency exchange rates; risks related to the actions and financial circumstances of our agents and contractors, counter-parties and joint venture partners; political uncertainty, including actions by terrorists, insurgent or other groups, or other armed conflict, including conflict between states; and expected rates of return. More specifically, future production may be affected by exploration success, start-up timing and success, facility reliability, reservoir performance and natural decline rates, water handling and drilling progress, restrictions on ability to access necessary infrastructure, equipment and services, including but not limited to, those sourced from third party providers. Capital expenditures may be affected by cost pressures associated with new capital projects, including labour and material supply, project management, drilling rig rates and availability and seismic costs. Risk factors are discussed in greater detail in filings made by OPCL with Canadian securities commissions. Any forward-looking information concerning prospective exploration, results of operations, financial position, production, expectations of capital expenditures, cash flows and future cash flows or other information described above that is based upon assumptions about future results, economic conditions and courses of action are presented for the purpose of providing readers with a more complete perspective on Oryx Petroleum’s present and planned future operations and such information may not be appropriate for other purposes and actual results may differ

Reserves and Resource Advisory

materially from those anticipated in such forward-looking information. In addition, included herein is information that may be considered financial outlook and/or futureoriented financial information. Its purpose is to indicate the potential results of Oryx Petroleum’s intentions and may not be appropriate for other purposes. Readers are strongly cautioned that the above list of factors affecting forward-looking information is not exhaustive. Although OPCL believes that the expectations conveyed by the forward-looking information are reasonable based on information available to it on the date such forward-looking information was made, no assurances can be given as to future results, levels of activity and achievements. Readers should not place undue importance or reliance on the forwardlooking information and should not rely on the forward-looking information as of any date other than the date hereof. Further, statements including forward-looking information are made as at the date they are given and, except as required by applicable law, Oryx Petroleum does not intend, and does not assume any obligation, to update any forward-looking information, whether as a result of new information or otherwise. If OPCL does update one or more statements containing forward-looking information, it is not obligated to, and no inference should be drawn that it will make additional updates with respect thereto or with respect to other forward-looking information. The forward-looking information contained in this MD&A is expressly qualified by this cautionary statement.

Oryx Petroleum’s reserves and resource estimates have been prepared and evaluated in accordance with National Instrument 51101 - Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook. Proved oil reserves are those reserves which are most certain to be recovered. There is at least a 90% probability that the quantities actually recovered will equal or exceed the estimated proved oil reserves. Probable oil reserves are those additional reserves that are less certain to be recovered than proved oil reserves. There is at least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable oil reserves. Possible oil reserves are those additional reserves that are less certain to be recovered than probable oil reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible oil reserves. Contingent oil resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. Contingent oil resources entail additional commercial risk than reserves and adjustments for commercial risks have not been incorporated in the summaries of contingent oil set forth in this news release. There is no certainty that it will be commercially viable to produce any portion of the contingent oil resources. Moreover, the volumes of contingent oil resources reported herein are sensitive to economic assumptions, including capital and operating costs and commodity pricing. Prospective oil resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective oil resources have both a chance of discovery and a chance of development. Prospective oil resources entail more commercial and exploration risks than those relating to oil reserves and contingent resources. There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources. Use of the word “gross” to qualify a reference to reserves or resources means, in respect of such reserves or resources, the total reserves or resources prior to the deductions specified in the production sharing contract, risk exploration contract or fiscal regime applicable to each license area.

47



48

CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED DECEMBER 31, 2013 Table of Contents 50 51 52 53 54 55

Independent auditor’s report to the members of Oryx Petroleum Corporation Limited Consolidated statement of comprehensive income Consolidated statement of financial position Consolidated statement of changes in equity Consolidated statement of cash flows Notes to the consolidated financial statements

49

INDEPENDENT AUDITOR’S REPORT To the Shareholders of Oryx Petroleum Corporation Limited We have audited the accompanying consolidated financial statements of Oryx Petroleum Corporation Limited, which comprise the consolidated statement of financial position as at December 31, 2013 and 2012, and the consolidated statement of comprehensive income, consolidated statement of changes in equity and consolidated statement of cash flows for the years then ended, and a summary of significant accounting policies and other explanatory information. Management’s Responsibility for the Consolidated Financial Statements Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error. Auditor’s Responsibility Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion. Opinion In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Oryx Petroleum Corporation Limited as at December 31, 2013 and 2012, and its financial performance and its cash flows for the years then ended in accordance with International Financial Reporting Standards.

Signed by Deloitte SA Chris Jones Will Eversden Geneva, Switzerland March 12, 2014

50

Consolidated Statement of Comprehensive Income

Note

General and administrative expense Pre-licence costs Impairment of oil and gas assets Depreciation and amortization expense Other operating expense

11 11, 12 32

Loss from operations Interest (expense) / income - net Foreign exchange gains / (losses)

7, 8 9

Finance income / (expense) - net Loss before income tax Income tax (expense) / benefit

Year ended December 31 2013 $'000

Year ended December 31 2012 $'000 (restated)

(40,131) (6,383) (82,948) (728) (56,887)

(22,612) (6,608) (29,017) (361) -

(187,077)

(58,598)

(60) 2,633

89 (231)

2,573

(142)

(184,504) 10

Net loss for the year

(1,319)

(58,740) 203

(185,823)

(58,537)

(1,424)

(2,542)

(187,247)

(61,079)

(185,564) (259)

(58,359) (178)

(185,823)

(58,537)

(186,988) (259)

(60,901) (178)

(187,247)

(61,079)

(2.04)

(2.10)

Other comprehensive loss, net of income tax (items that will not be subsequently reclassified to profit and loss) Remeasurement of the defined benefit obligation

27

Total comprehensive loss for the year Net loss for the year attributable to: Owners of the company Non-controlling interests

28

Total comprehensive loss attributable to: Owners of the company Non-controlling interests

Loss per share (basic and diluted)

28

23

51

Consolidated Statement of Financial Position Note

December 31 2013 $'000

December 31 2012 $'000 (restated)

Non-current assets Intangible assets Property, plant and equipment Deferred tax assets

11 12 17

200,720 443,824 911

479,162 575 870

645,455

480,607

12,465 6,606 5,652 306,034

5,601 12,361 4,971 72,725

330,757

95,658

976,212

576,265

138,608 463 -

83,121 870 7,781

139,071

91,772

66,271 3,492 1,346

37,687 2,469 -

71,109

40,156

210,180

131,928

1,009,684 5,186 (3,966) (261,585)

499,311 771 5,846 (2,542) (84,371)

749,319

419,015

16,713

25,322

Total equity

766,032

444,337

Total equity and liabilities

976,212

576,265

Current assets Inventories Trade and other receivables Prepaid charges Cash and cash equivalents

13 14 15 16

Total assets Current liabilities Trade and other payables Current income tax liabilities Borrowings

18 19 21

Non-current liabilities Trade and other payables Retirement benefit obligation Decommissioning obligation

18 27 20

Total liabilities Equity Share capital Share premium Other reserves Remeasurement of defined benefit obligation Accumulated deficit

22 22 24 27

Equity attributable to owners of the company Non-controlling interests

28

The financial statements were approved by the Board of Directors and authorized for issue on March 12, 2014. They were signed on behalf of the Board of Directors by

52

(signed)

(signed)

Jean Claude Gandur Director

Peter Newman Director

Consolidated Statement of Changes in Equity Attributable to equity holders of the company

Note Balance at January 1, 2012 Net loss for the year Shares issued Share based payment expense Shares issued for long-term incentive plan Remeasurement of defined benefit obligation

22 26 26 27

Balance at December 31, 2012 (restated) Net loss for the year Shares issued prior to initial public offering Shares issued through initial public offering Issuance costs Warrants exercised Share based payment expense Shares issued for long-term incentive plan Shares issued for Directors' compensation Increase in participating interest in subsidiary(1) Remeasurement of defined benefit obligation Balance at December 31, 2013(2)

22 22 26 26 26 26 26 27

Remeasurement of defined Accumulated benefit deficit obligation $'000 $'000

Total $'000

Noncontrolling interests $'000

Total equity $'000

-

81,726

25,500

107,226

(58,359) -

(2,542)

(58,359) 394,929 11,729 (8,468) (2,542)

(178) -

(58,537) 394,929 11,729 (8,468) (2,542)

5,846

(84,371)

(2,542)

419,015

25,322

444,337

4,531 (5,302) -

25,047 (25,533) (174) -

(185,564) 8,350

-

(185,564) 265,137 247,344 (16,838) 10,515 25,047 (22,263) 8,350

(259) (8,350)

(185,823) 265,137 247,344 (16,838) 10,515 25,047 (22,263) -

-

-

-

-

(1,424)

(1,424)

-

(1,424)

1,009,684

-

5,186

(261,585)

(3,966)

749,319

16,713

766,032

Share capital $'000

Share premium $'000

Other reserves $'000

105,153

-

2,585

(26,012)

394,158 -

771 -

11,729 (8,468) -

499,311

771

260,606 247,344 (11,536) 10,515 3,270 174 -

1. During the fourth quarter of 2013, Oryx Petroleum Middle East Ltd increased its participating interest in KPA Western Desert Energy Ltd to 66.67% from 50% (Note 28). 2. All outstanding shares of Oryx Petroleum Holdings PLC (“OPHP”) were acquired by Oryx Petroleum Corporation Limited (“OPCL”) immediately prior to the closing date of the initial public offering in exchange for new shares in OPCL. All share capital balances prior to May 15, 2013 relate to shares held by OPHP.

53

Consolidated Statement of Cash Flows Year ended December 31 2013 $'000

Year ended December 31 2012 $'000 (restated)

(9,148) (1,768) 2,184

(23,715) (130) 89

(8,732)

(23,756)

Acquisition of property, plant and equipment Acquisition of intangible assets

(10,710) (223,369)

(633) (92,267)

Net cash used in investing activities

(234,079)

(92,900)

Proceeds from issuance of ordinary shares Proceeds from issuance of convertible loan notes Proceeds from borrowings Share issuance costs

492,959 (16,838)

251 284 163,565 -

Net cash generated from financing activities

476,121

164,100

Net increase in cash and cash equivalents

233,309

47,444

72,725

25,281

306,034

72,725

Note

Cash flows from operating activities Net cash used in operations Income tax paid Interest received

25

Net cash used in operating activities Cash flows from investing activities

Cash flows from financing activities

Cash and cash equivalents at beginning of the year Cash and cash equivalents at end of the year

16

NOTES TO THE FINANCIAL STATEMENTS   1. General information Oryx Petroleum Corporation Limited (‘the Company’) is a public company incorporated in Canada under the Canada Business Corporation Act on December 31, 2012, and is the holding company for the Oryx Petroleum Group of companies (together “the Group”). The address of the registered office of Oryx Petroleum Corporation Limited is 3400 First Canadian Centre 350, 7th Avenue Southwest, Calgary, Alberta, Canada T2J 2M2. The Group’s indirect majority shareholder is The Addax and Oryx Group Ltd (“AOG”) (incorporated in Malta). The majority of AOG’s outstanding shares are owned by Samsufi Trust, an irrevocable discretionary charitable trust created at the suggestion of Jean Claude Gandur. Mr. Gandur is not one of the beneficiaries of the Samsufi Trust. The Group’s principal activities are to acquire and develop exploration and production assets in order to produce hydrocarbons and to increase oil and gas reserves. On May 5, 2013, Oryx Petroleum Corporation Limited announced the filing of a supplemented PREP prospectus with the securities regulatory authorities in each of the provinces of Canada, other than Quebec, in connection with its initial public offering of 16,700,000 common shares, at a price of CAD$15.00 per common share (the “IPO”) for total gross proceeds of CAD$250.5 million ($249.4 million). The IPO closed on May 15, 2013. Immediately prior to closing the IPO, a corporate restructuring occurred whereby Oryx Petroleum Corporation Limited became the parent company of Oryx Petroleum Holdings PLC (OPHP) (formerly Oryx Petroleum Company PLC and Oryx Petroleum Company Limited). Although the consolidated financial information has been released in the name of the parent, Oryx Petroleum Corporation Limited, it represents an in-substance continuation of the pre-existing Group, headed by OPHP and the following accounting treatment has been applied to account for the restructuring: •

the consolidated assets and liabilities of the subsidiary OPHP were recognised and measured at the pre-restructuring carrying amounts, without restatement to fair value;



the retained earnings and other equity balances recognised in the consolidated statement of financial position reflect the consolidated retained earnings and other equity balances of OPHP, as at May 9, immediately prior to the restructuring, and the results of the period from January 1, 2013 to May 9, 2013, the date of the restructuring, are those of OPHP as the Company was not active prior to the restructuring. Subsequent to the restructuring, the equity structure reflects the applicable movements in equity of Oryx Petroleum Corporation Limited.



Comparative numbers presented in the consolidated financial statements are those of OPHP, except for the per-share amounts, which have been restated to reflect the change in the nominal value of the common shares resulting from the restructuring as if the Company had been the parent company during such periods.

The consolidated financial statements were authorised for issue by the Board of Directors on March 12, 2014.

54

2. Summary of significant accounting policies a.

Basis of preparation

The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB) and the IFRS Interpretations Committee (IFRIC). The consolidated financial statements have been prepared under the historical cost convention, as modified by the revaluation of financial assets and liabilities (including derivative instruments) at fair value through profit and loss. The preparation of financial statements in conformity with IFRS, requires the use of critical accounting estimates. It also requires management to exercise its judgment in the process of applying the Group’s accounting policies. The areas involving a higher degree of judgment or complexity, or areas where assumptions and estimates are significant to the consolidated financial statements are disclosed in Note 4: Critical accounting estimates and judgments. These estimates are based on management’s best knowledge of current events and actions; actual results ultimately may differ from those estimates.   New and amended standards adopted by the Group The Group has adopted all of the new and revised standards and interpretations issued by the IASB and IFRIC that are relevant to its operations and effective for accounting periods beginning on or after January 1, 2013 as follows: Amendments to Standards IFRS 10 Consolidated financial statements IFRS 11 Joint arrangements IFRS 12 Disclosure of interests in other entities IAS 1 Presentation of financial statements IAS 27 (2011) Separate financial statements IAS 28 (2011) Investments in associates and joint ventures IFRS 13 Fair value measurement IAS 19 (2011) Employee Benefits IFRS 7 Financial Instruments: Disclosures

Effective for annual periods beginning on or after January 1, 2013 January 1, 2013 January 1, 2013 January 1, 2013 January 1, 2013 January 1, 2013 January 1, 2013 January 1, 2013 January 1, 2013

The above new or amended standards and interpretations do not have a material impact for the Group, other than to enhance certain disclosures, except for the adoption of IAS 19 (2011) Employee Benefits. At the date of authorisation of these financial statements, the following new or further amended standards and interpretations applicable to the Group were issued but not yet effective: New and Amended Standards Financial Instruments: Presentation (Offsetting) IAS 32 IAS 36 Impairment of Assets (Disclosures re non-financial assets) IFRS 10, IFRS 12 and IAS 27 Consolidated Financial Statements (Investment entities) IFRS 9 Financial Instruments: classification and measurement Additions to IFRS 9 for financial liability accounting

Effective for annual periods beginning on or after January 1, 2014 January 1, 2014 January 1, 2014 January 1, 2015 January 1, 2015

Management has considered the impact of these additional new or further amended standards and interpretations but do not anticipate that their adoption in future periods will have a material impact on the financial statements of the Group. In the current year, the Group has applied IAS 19 Employee Benefits (as revised in 2011) and the related consequential amendments for the first time. The impact on accumulated deficit at January 1, 2012 was an increase of $24 thousand and an increase of $3.6 million in restating the previously reported total comprehensive loss for 2012. The elements of this application are detailed as follows:

55

Impact on total comprehensive loss for the year of the application of IAS 19 (as revised in 2011)

Year ended

Year ended

December 31

December 31

2013

2012

$'000

$'000 (restated)

Impact on loss for the year General and administrative expense

(411)

(1,482)

(72)

(75)

Income tax (expense) / benefit

(168)

501

Increase in loss for the year

(651)

(1,056)

(1,424)

(2,542)

Foreign exchange losses

Impact on other comprehensive loss for the year Remeasurement of defined benefit obligation Income tax (expense) / benefit

-

-

Increase in other comprehensive loss for the year

(1,424)

(2,542)

Increase in total comprehensive loss for the year

(2,075)

(3,598)

(651)

(1,056)

-

-

(2,075)

(3,598)

-

-

December 31

IAS 19

December 31

2012

adjustments

2012

$'000

$'000

$'000

Net loss attributable to: Owners of the company Non-controlling interests Total comprehensive loss attributable to: Owners of the company Non-controlling interests

Impact on assets, liabilities and equity as at December 31 2012 for the application of IAS 19 (as revised in 2011)

(restated) Retirement benefit asset / (obligation) Prepaid charges Deferred tax assets

67

(2,536)

(2,469)

6,534

(1,563)

4,971

369

Total effect on net assets Remeasurement of defined benefit obligation Accumulated deficit Total effect on equity

56

501

870

(3,598) (83,315)

(2,542)

(2,542)

(1,056)

(84,371)

(3,598)

Impact on assets, liabilities and equity as at December 31, 2013 for the application of IAS 19 (as revised in 2011) IAS 19 Adjustments $'000 Retirement benefit obligation

(1,995)

Prepaid charges

(4,011)

Deferred tax assets

333

Total effect on net assets

(5,673)

Remeasurement of defined benefit obligation

(3,966)

Accumulated deficit

(1,707)

Total effect on equity

(5,673)

b. Going concern The Group presently meets its day to day working capital requirements, and funds its current and planned exploration projects through the funding received from the IPO and the balance of equity funding from AOG and other investors that is remaining. Prior to the IPO, the Group met its day to day working capital requirements through $723 million in equity funding provided by AOG and other investors. The Group has no debt and a considerable degree of control over both the extent and timing of expenditure under its future capital investment program. The directors have a reasonable expectation that the Company and the Group have adequate resources to continue in operational existence for the foreseeable future and, therefore, continue to adopt the going concern basis in preparing the consolidated financial statements. Notes 3.1 and 3.2 of the consolidated financial statements set out the Group’s objectives, policies and processes for managing its capital; its financial risk management objectives; and its exposure to credit risk and liquidity risk. c. Consolidation i. Subsidiaries Subsidiaries are all entities (including special purpose entities) over which the Group has obtained control. Control is achieved when the Company has power over the investee, is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to use its power to affect its returns. The Group also assesses existence of control where it does not have more than one half of the voting power but is able to govern the financial and operating policies by virtue of de-facto control. De-facto control may arise in circumstances where the size of the Group’s voting rights relative to the size and dispersion of holdings of other shareholders give the Group the power to govern the financial and operating policies. Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are deconsolidated from the date that control ceases.

The Group applies the acquisition method to account for business combinations. The consideration transferred for the acquisition of a subsidiary is the fair value of the assets transferred, the liabilities incurred to the former owners of the acquiree and the equity interests issued by the Group. The consideration transferred includes the fair value of any asset or liability resulting from a contingent consideration arrangement. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at the fair values at the acquisition date. The Group recognises any non-controlling interest in the acquiree on an acquisition-byacquisition basis, either at fair value or at the non-controlling interest’s proportionate share of the recognised amounts of the acquiree’s net assets. If the business combination is achieved in stages, the acquisition date fair value of the acquirer’s previously held equity interest in the acquiree is remeasured to fair value at the acquisition date through profit or loss. Any contingent consideration to be transferred by the Group is recognised at fair value at the acquisition date. Subsequent changes to the fair value of the contingent consideration that is deemed to be an asset or liability is recognised in profit or loss. Goodwill is initially measured as the excess of the aggregate of the consideration transferred and the fair value of the noncontrolling interest over the net identifiable assets acquired and liabilities assumed. If the consideration is lower than the fair value of the net assets of the subsidiary acquired, the difference is recognised in profit or loss. Inter-company transactions, balances, income and expenses on transactions between Group companies are eliminated. Profits and losses resulting from intercompany transactions that are recognised in assets are also eliminated. ii. Changes in ownership interests in subsidiaries without loss of control Changes in the Group’s interests in subsidiaries that do not result in a loss of control are accounted for as equity transactions – that is, as transactions with the owners in their capacity as owners. The carrying amounts of the Group’s interests and the non-controlling interests are adjusted to

reflect the changes in their relative interests in the subsidiaries. Any difference between the amount by which the non-controlling interests are adjusted and the fair value of any consideration paid or received is recorded directly in equity. iii. Disposal of subsidiaries When the Group ceases to have control, any retained interest in the entity is remeasured to its fair value at the date when control is lost, with the change in carrying amount recognised in profit or loss. The fair value is the initial carrying amount for the purposes of subsequently accounting for the retained interest as an associate, joint venture or financial asset. In addition, any amounts previously recognised in other comprehensive income in respect of that entity are accounted for as if the Group had directly disposed of the related assets or liabilities. This may mean that amounts previously recognised in other comprehensive income are reclassified to profit or loss. iv. Interest in joint operations A joint operation is a joint arrangement whereby the Group has rights to assets, and obligations for the liabilities relating to the arrangement. Where the Group undertakes its activities under joint operation arrangements directly, the Group’s proportionate share of jointly controlled assets and any liabilities incurred jointly with others are recognised in the financial statements. Liabilities and expenses incurred directly in respect of interests in joint operations are accounted for on an accrual basis. Income from the sale or use of the Company’s share of the output of joint operations and its share of the joint operation expenses are recognised when it is probable that the economic benefit associated with the transactions will flow to/ from the Company and the amount can be reliably measured. d. Foreign currency translation i.

Functional and presentation currency

Items included in the financial statements of each of the Group’s entities are measured using the currency of the primary economic environment in which the entity operates (the functional currency). The consolidated financial statements are presented in US Dollars (USD), which is the functional and presentation currency of the Company and the presentation currency of the Group.

57

ii. Transactions and balances Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions or valuation where these items are remeasured. 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 statement of comprehensive income, except when deferred in other comprehensive income as qualifying cash flow hedges and qualifying net investment hedges. Changes in the fair value of monetary securities denominated in foreign currency classified as available-for-sale are analysed between translation differences resulting from changes in the amortised cost of the security, and other changes in the carrying amount of the security. Translation differences are recognised in profit or loss, and other changes in carrying amount are recognised in other comprehensive income. Translation differences on non-monetary financial assets and liabilities such as equities held at fair value through profit or loss are recognised in profit or loss as part of the fair value gain or loss. Translation differences on non-monetary financial assets such as equities classified as available-forsale, are included in other comprehensive income. iii. Group companies The results and financial position of all the Group entities (none of which has the currency of a hyper-inflationary economy) that have a functional currency different from the presentation currency are translated into the presentation currency as follows: •

assets and liabilities are translated at the closing rate at the end of each reporting period;



income and expenses are translated at average exchange rates (unless this average is not a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the dates of the transactions); and



all resulting exchange differences are recognised in other comprehensive income.

Goodwill and fair value adjustments arising on the acquisition of a foreign entity are treated as assets and liabilities of the foreign entity and translated at the closing exchange rate. e. Exploration and evaluation assets and property, plant and equipment i. Cost Oil and gas properties and other property, plant and equipment are recorded at cost including expenditures which are directly attributable to the purchase or development of an asset. ii. Exploration and evaluation (“E&E”) costs Exploration and evaluation costs incurred following the acquisition of a license are initially capitalised as intangible E&E assets. Payments to acquire the legal rights to explore, costs of technical work, seismic acquisition, education and training fund, production

58

sharing contract costs, exploratory and appraisal drilling, general technical support and directly attributable administrative and overhead costs are capitalised as E&E assets. E&E costs are not amortised prior to the conclusion of appraisal activities. E&E assets related to each exploration license/prospect are carried forward until the existence (or otherwise) of commercial reserves has been determined subject to certain limitations including review for impairment. If commercial reserves have been discovered, the carrying value, less any impairment loss, of the relevant E&E assets is then reclassified to property, plant and equipment. If, however, commercial reserves have not been found, the related capitalised costs are charged to expense after conclusion of appraisal activities. Costs incurred prior to having obtained the legal rights to explore an area are expensed in the period in which they are incurred. iii. Development costs Expenditures on the construction, installation and completion of infrastructure facilities and drilling of development wells are capitalised as oil and gas properties. Costs incurred to operate and maintain wells and equipment to lift oil and gas to the surface are expensed as production and operating expenses.   iv. Other property, plant and equipment Property, plant and equipment (PP&E) assets are stated at historical cost, less any accumulated depreciation and any provision for impairment. Cost includes expenditures that are directly attributable to the acquisition of the assets. Subsequent costs are included in the asset’s carrying amount or recognised as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item will flow to the Group and the cost of the item can be measured reliably. Where such subsequent expenditure is to replace previously capitalised equipment, the remaining carrying amount of the replaced part is derecognised. Repairs and maintenance are charged to expense as incurred. v. Depreciation and amortisation All expenditure within each license area is depleted from the commencement of production on a unit of production basis, which is the ratio of oil and gas production in the period to the estimated quantities of commercial reserves at the end of the period plus the production in the period, generally on a license area-by-license area basis. Costs used in the unit of production calculation comprise the net book value of capitalised costs plus the estimated future field development costs. Changes in the estimates of commercial reserves are dealt with prospectively. Depreciation on other assets is calculated using the straight-line method to allocate the cost of each asset to its residual value over its estimated useful life, as follows: •

Fixtures and equipment: 3 - 5 years



Computer equipment: 3 years

reporting period. An asset’s carrying amount is written down immediately to its recoverable amount if the asset’s carrying amount is greater than its estimated recoverable amount. Gains and losses on disposals are determined by comparing proceeds with the carrying amount. These are included in the statement of comprehensive income as ‘Other income’ or ‘Other expense’. vi. Intangible assets other than oil and gas assets Intangible assets, other than oil and gas assets, have finite useful lives and are measured at cost and amortised over their expected useful economic lives on a straight line basis as follows: • Computer software: 3 years f. Impairment of non-financial assets Assets that have an indefinite useful life, such as goodwill or intangible assets not ready to use, are not subject to amortisation and are tested annually for impairment. Assets that are subject to amortisation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying value may not be recoverable. E&E assets are assessed for impairment when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Such indicators include but are not limited to: • the period for which the Group 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; • substantive expenditure on further exploration for and evaluation of mineral resources in the specific area is neither budgeted or planned; • exploration for and evaluation of resources in the specific area have not led to the discovery of commercially viable quantities of mineral resources and a decision has been taken to discontinue such activities in the specific area; • sufficient data exists to indicate that, although a development in the specific area is likely to proceed, the carrying amount of the E&E asset is unlikely to be recovered in full from successful development or sale; • extended decreases in prices or margins for oil & gas commodities or products; • a significant downwards revision in estimated volumes of reserves or resources or an upward revision in future development costs. For the purpose of impairment testing the assets are aggregated in cash-generating unit (CGU) cost pools based on their ability to generate largely independent cash flows. An impairment loss is recognised for the amount by which the asset’s carrying amount exceeds its recoverable amount. The recoverable amount of a CGU is the greater of its fair value less costs to sell and its value in use. Non-financial assets other than goodwill that suffered impairment are reviewed for possible reversal at each reporting date. g. Financial assets

Residual values and useful lives are reviewed, and adjusted if appropriate, at the end of each

The Group classifies its financial assets in the following categories: at fair value through

profit or loss, loans and receivables, and available-for-sale. The classification depends on the purpose for which the financial assets were acquired. Management determines the classification of its financial assets at initial recognition. i. Financial assets at fair value through profit or loss Financial assets at fair value through profit or loss are financial assets held for trading. A financial asset is classified in this category if acquired principally for the purpose of selling in the short term. Derivatives are also categorised as ‘held for trading’ unless they are designated as hedges. ii. Loans and receivables Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. They are included in current assets, except for maturities greater than twelve months after the end of the reporting period. These are classified as non-current assets. Loans and receivables are included in ‘Trade and other receivables’ in the statement of financial position. iii. Available-for-sale financial assets Available-for-sale financial assets are nonderivatives that are either designated in this category or not classified in any of the other categories. They are included in non-current assets unless the investment matures or management intends to dispose of it within twelve months of the end of the reporting period. Regular purchases and sales of investments are recognised on the trade-date – the date on which the Group commits to purchase or sell the asset. Investments are initially recognised at fair value plus transaction costs for all financial assets not carried at fair value through profit or loss. Financial assets carried at fair value through profit or loss are initially recognised at fair value, and transaction costs are expensed. Financial assets are derecognised when the rights to receive cash flows from the investments have expired or have been transferred and the Group has transferred substantially all risks and rewards of ownership. Available-for-sale financial assets and financial assets at fair value through profit or loss are subsequently carried at fair value. Loans and receivables are subsequently carried at amortised cost using the effective interest method. Gains and losses arising from changes in the fair value of the ‘financial assets at fair value through profit or loss’ category are included in the statement of comprehensive income in the period in which they arise. Changes in the fair value of monetary and non-monetary securities classified as ‘available-for-sale’ are recognised in other comprehensive income. When securities classified as ‘available-forsale’ are sold or impaired, the accumulated fair value adjustments recognised in equity are included in the statement of comprehensive income as part of ‘Other income’. Dividends on available-for-sale equity instruments are recognised in the statement of comprehensive income as part of ‘Other income’ when the Group’s right to receive payments is established.

h. Offsetting financial instruments Financial assets and liabilities are offset and the net amount reported in the statement of financial position when there is a legally enforceable right to offset the recognised amounts and there is an intention to settle on a net basis or realise the asset and settle the liability simultaneously. i.

Impairment of financial assets

i.

Assets carried at amortised cost

The Group assesses at the end of each reporting period whether there is objective evidence that a financial asset or group of financial assets is impaired. A financial asset or a group of financial assets is impaired and impairment losses are incurred only if there is objective evidence of impairment as a result of one or more events that occurred after the initial recognition of the asset (a ‘loss event’) and that loss event (or events) has an impact on the estimated future cash flows of the financial asset or group of financial assets that can be reliably estimated. Evidence of impairment may include indications that the debtors or a group of debtors is experiencing significant financial difficulty, default or delinquency in interest or principal payments, the probability that they will enter bankruptcy or other financial reorganisation, and where observable data indicate that there is a measurable decrease in the estimated future cash flows, such as changes in arrears or economic conditions that correlate with defaults. For loans and receivables category, the amount of the loss is measured as the difference between the asset’s carrying amount and the present value of estimated future cash flows (excluding future credit losses that have not been incurred) discounted at the financial asset’s original effective interest rate. The carrying amount of the asset is reduced and the amount of the loss is recognised in the statement of comprehensive income. If a loan or held-to-maturity investment has a variable interest rate, the discount rate for measuring any impairment loss is the current effective interest rate determined under the contract. As a practical expedient, the Group may measure impairment on the basis of an instrument’s fair value using an observable market price. If, in a subsequent period, the amount of the impairment loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognised (such as an improvement in the debtor’s credit rating), the reversal of the previously recognised impairment loss is recognised in the statement of comprehensive income.

less any impairment loss on that financial asset previously recognised in profit or loss, is removed from equity and recognised in profit or loss. Impairment losses recognised on equity instruments in the statement of comprehensive income are not reversed through the statement of comprehensive income. If, in a subsequent period, the fair value of a debt instrument classified as available-for-sale increases and the increase can be objectively related to an event occurring after the impairment loss was recognised in profit or loss, the impairment loss is reversed through the statement of comprehensive income. j. Inventories Inventories relating to materials acquired for use in exploration activities are stated at the lower of cost and net realisable value. Net realisable value is the estimated selling price in the ordinary course of business, less estimated costs of completion and estimated costs necessary to make the sale. The cost of inventories comprises all costs of purchase, costs of conversion and other costs incurred in bringing the inventories to their present location and condition. k. Trade and other receivables Trade and other receivables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method, less provision for impairment. A provision for impairment of trade receivables is established when there is objective evidence that the Group will not be able to collect all amounts due according to the original terms of the receivables. l.

Cash and cash equivalents

Cash and cash equivalents includes cash in hand, deposits held at call with banks, and other highly liquid investments with original maturities of three months or less. Bank overdrafts are shown within borrowings in current liabilities. m. Borrowings Borrowings are recognised initially at fair value, net of transaction costs incurred. Borrowings are subsequently carried at amortised cost; any difference between the proceeds (net of transaction costs) and the redemption value is recognised in the statement of comprehensive income over the period of the borrowings using the effective interest method. Borrowings are classified as current liabilities unless the Group has an unconditional right to defer settlement of the liability for at least twelve months after the end of the reporting period.

ii. Assets classified as available-for-sale

n. Compound financial instruments

The Group assesses at the end of each reporting period whether there is objective evidence that a financial asset or a group of financial assets is impaired. For debt securities, the Group uses the criteria referred to in (i) above. In the case of equity investments classified as available-for-sale, a significant or prolonged decline in the fair value of the security below its cost is also evidence that the assets are impaired. If any such evidence exists for available-for-sale financial assets, the cumulative loss, which is measured as the difference between the acquisition cost and the current fair value,

Compound financial instruments issued by the Group comprise convertible notes that can be converted to share capital at the option of the directors of the Company, and the number of shares to be issued does not vary with changes in their fair value. The liability component of a compound financial instrument is recognised initially at the fair value of a similar liability that does not have an equity conversion option. The equity component is recognised initially at the difference between the fair value of the compound financial instrument as a whole

59

and the fair value of the liability component. Any directly attributable transaction costs are allocated to the liability and equity components in proportion to their initial carrying amounts. Subsequent to initial recognition, the liability component of a compound financial instrument is measured at amortised cost using the effective interest method. The equity component of a compound financial instrument is not re-measured subsequent to initial recognition except on conversion or expiry. Compound financial instruments are classified as current liabilities unless the Group has an unconditional right to defer settlement of the liability for at least twelve months after the end of the reporting period. o. Taxation The tax expense for the period represents tax currently payable and deferred tax. Tax is recognised in the statement of comprehensive income, except to the extent that it relates to items recognised in other comprehensive income or directly in equity. In this case, the tax is also recognised in other comprehensive income or directly in equity, respectively. The current income tax charge is calculated on the basis of the tax laws enacted or substantively enacted at the end of the reporting period in the countries where the Group’s subsidiaries operate and generate taxable income. Management periodically evaluates positions taken in tax returns with respect to situations in which applicable tax regulation is subject to interpretation and establishes provisions where appropriate on the basis of amounts expected to be paid to the tax authorities. Deferred income tax is the tax recognised in respect of temporary differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases and is accounted for using the balance sheet liability method. Deferred income tax liabilities are generally recognised for all taxable temporary differences and deferred income tax assets are recognised to the extent that it is probable that taxable profits will be available against which deductible temporary differences can be utilised. Deferred income tax is not recorded if it arises from the initial recognition of an asset or liability in a transaction other than a business combination that, at the time of the transaction, affects neither the accounting profit nor loss. Deferred income tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries and associates and interests in joint ventures except where the Group is able to control the reversal of the temporary difference and it is probable that the temporary difference will not reverse in the foreseeable future. The carrying amount of deferred tax assets is reviewed at the end of each reporting period and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered. Deferred income tax is calculated at the tax rates that are expected to apply in the year

60

when the deferred tax liability is settled or the asset is realised. Deferred tax is charged or credited in the statement of comprehensive income except when it relates to items charged or credited directly to equity in which case the deferred tax is also recognised directly in equity. Deferred tax assets and liabilities are offset when there is a legally enforceable right to offset current tax assets against current tax liabilities and when they relate to income taxes levied by the same taxation authority and the Group intends to settle its current tax assets and liabilities on a net basis. p. Employee benefits i.

Pension obligations

The Group operates two defined benefit pension plans. Typically defined benefit plans define an amount of pension benefit that an employee will receive on retirement, usually dependent on one or more factors such as age, years of service and compensation. The Group’s Swiss pension plans are accounted for as defined benefit schemes in accordance with the requirements of IFRS. The pension assets within these Swiss plans consist entirely of investments held by the insurance company that fully reinsures the Group’s pension liabilities. The liability recognised in the statement of financial position in respect of defined benefit pension plans is the present value of the defined benefit obligation at the end of the reporting period less the fair value of plan assets. The defined benefit obligation is calculated annually by independent actuaries using the projected unit credit method. The present value of the defined benefit obligation is determined by discounting the estimated future cash outflows using interest rates of high quality corporate bonds that are denominated in the currency in which the benefits will be paid, and that have terms to maturity approximating to the terms of the related pension obligation. The retirement benefit obligation recognised in the consolidated statement of financial position represents the actual deficit or surplus in the Group’s defined benefit plans. Any surplus resulting from this calculation is limited to the present value of any economic benefits available in the form of refunds from the plans or reductions in the future contributions to the plans. ii. Share-based compensation The Group issues equity-settled sharebased payments to employees under a Long Term Incentive Plan (LTIP). Such payments are measured at the fair value of the equity instruments at the grant date. The fair value excludes the effect of any service and nonmarket performance vesting conditions. The fair value of equity-settled share-based payments determined at the grant date is expensed on a straight-line basis over the vesting period, based on the Group’s estimate of equity instruments that will eventually vest. At the end of each reporting period, the Group revises its estimate of the number of equity instruments expected to vest as a result of the effect of non-market vesting conditions. The impact of the revision of the original estimates, if any, is recognised in profit or loss such that the cumulative expense reflects the revised estimate, with a corresponding adjustment to equity.

q. Trade and other payables Liabilities for trade and other amounts payable are stated initially at their fair value and subsequently at amortised cost using the effective interest method. r. Provisions Provisions are recognised 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 can be reliably estimated. Provisions are measured at the present value of management’s best estimate of the expenditure required to settle the present obligation at the reporting date and are discounted to present value where the effect is material. Provisions for decommissioning costs represent management’s best estimate of the Group’s liability for restoring the sites of drilled wells to their original status, discounted where the effect is material. A decommissioning asset is also established, since the future cost of decommissioning is regarded as part of the total investment to gain access to future economic benefits. The amount recognised is reassessed each reporting period in accordance with local conditions and requirements. Changes in the estimated timing or cost of decommissioning are dealt with prospectively. The unwinding of any discount on the decommissioning provision is included as a finance cost. s. Interest income Interest income is recognised using the effective interest method. When a loan or receivable is impaired, the Group reduces the carrying amount to its recoverable amount, being the estimated future cash flow discounted at original effective interest rate of the instrument, and continues unwinding the discount as interest income. Interest income on impaired loans and receivables is recognised using the original effective interest rate. t. Leases Leases where the lessor retains substantially all the risks and rewards of ownership are classified as operating leases. Payments made under operating leases (net of any incentives received from the lessor) are charged to the statement of comprehensive income on a straight-line basis over the period of the lease. Assets held under finance leases are initially recognised as assets of the Group at their fair value at the inception of the lease or, if lower, at the present value of the minimum lease payments. The corresponding liability to the lessor is included in the consolidated statement of financial position as a finance lease obligation.  

3. Financial risk management 3.1 Financial risk factors The Group’s activities expose it to a variety of financial risks: market risk (including currency risk, fair value interest rate risk, cash flow interest rate risk and price risk), credit risk and liquidity risk. The Group’s overall risk management objective is to decrease volatility in earnings, financial position and cash flow while securing effective and competitive financing. In order to address the impact of these risks, the Group has developed various risk management policies and strategies. a. Market risk i.

Foreign exchange risk

The Group operates internationally and has foreign exchange risk arising from various currency exposures. Foreign exchange risk arises when future commercial transactions or recognised assets and liabilities are denominated in a currency that is not the entity’s functional currency. The Group’s reporting currency is the US Dollar; being the currency in which the majority of the Group’s expenditure is transacted. The US Dollar is also the functional currency of all Group companies. Less material elements of general and administrative expenses are transacted in other currencies. The majority of balances are held in US Dollars with transfers to Swiss Francs and other local currencies as required to meet local needs. A forward exchange contract was signed in December 2012 to purchase 1,500,000 Swiss Francs per month for the subsequent twelve months. The contract was a zero cost collar hedging instrument. The collar rates included in the contract were 0.8805 CHF : 1 USD and 0.9660 CHF : 1 USD. Any gains or losses arising from the application of the collar have been charged to the statement of comprehensive income. There were no forward exchange rate contracts in place at December 31, 2013. During 2013, if the Swiss Franc had strengthened/weakened by 10% against the US Dollar throughout the year with all other variables held constant, the total comprehensive loss for the year would have been $2.9 million lower/ higher, mainly as the result of Swiss Franc-denominated general and administrative expenses and foreign exchange gains/losses on the translation of Swiss Franc-denominated monetary assets and liabilities. ii. Commodity price risk The market prices for crude oil and natural gas are subject to significant fluctuations resulting from a variety of factors affecting demand and supply globally. As the Group’s activities are currently at exploration and development stage, there is no sales revenue and consequently no income statement exposure to commodity price risk. iii. Interest rate risk The Group’s income and operating cash flows are substantially independent of changes in market interest rates with the exception of interest income from bank deposits, with variable interest rates which are exposed to cash flow interest rate risk as market rates change. The interest expense on the contingent consideration (note 8) is also exposed to interest rate risk as market rates

change. The funding provided by AOG and others, prior to 2013, was interest-free and converted into equity in September 2012 and January 2013. The objective of the Group’s interest rate risk management is to balance the returns received on interest bearing assets with an acceptable level of access to those assets. Based on the exposure to the interest rates for cash and cash equivalents, and the interest expense on the contingent consideration, at the reporting date, a 0.5% rate increase or decrease would not have a material impact on the Group’s loss for the year. A change in rate of 0.5% is used as it represents management’s assessment of the reasonably possible changes in interest rates. b. Credit risk Credit risk is managed on a Group basis. Credit risk arises from cash and cash equivalents and deposits with banks and financial institutions, as well as credit exposures to oil and gas property license partners and customers, including outstanding receivables and committed transactions. For cash and cash equivalents, the Group invests in products that are rated investment grade and above. The credit risk on liquid funds is assessed as limited because the counterparties are banks with good credit-ratings assigned by international credit-rating agencies. The Group does not have any significant trade or other receivables outstanding from any one debtor at the reporting date. Management does not believe that there is significant exposure to credit risk on receivables from related parties. Where a Group company undertakes its activities under joint venture arrangements, its joint venture partners are obligated to make cash contributions to fund joint venture operations and have historically done so. The balance of joint venture receivables (Note 14) arises from timing differences between cash calls and the expenditure incurred on behalf of joint venture partners. While there is no “due date” for these receivables, based on historical experience of funding through regular cash calls with a limited group of joint venture partners, management does not believe that there is significant exposure to credit risk on these receivables. c. Liquidity risk Prudent liquidity risk management implies maintaining sufficient cash and marketable securities and being able to secure sufficient funding on a timely basis to meet capital and operating expenditure obligations. Management uses budgets and cash flow models, which are regularly updated, to monitor liquidity risk. The Group manages liquidity risk through its corporate treasury function using sources of financing from other entities and investing excess liquidity. The table below details the remaining contractual maturity for non-derivative financial liabilities of the Group. The amounts disclosed in the table are the contractual undiscounted cash flows.

61

Less than 1 year $'000

Between 1 and 2 years $'000

Between 2 and 5 years $'000

Over 5 years $'000

At December 31, 2012 Trade and other payables Borrowings

83,121 7,781

37,687 -

-

-

138,608

66,271

-

-

At December 31, 2013 Trade and other payables 3.2 Capital risk management The Group’s objectives when managing capital are to safeguard the Group’s ability to continue as a going concern in order to provide returns for shareholders and benefits for the other stakeholders and to maintain an optimal capital structure to reduce the cost of capital. The capital structure of the Group consists of issued capital and reserves less accumulated deficits. There is no indebtedness. A substantial proportion of net equity at the reporting date is held as cash and cash equivalents.

4. Critical accounting and judgments

estimates

In the process of applying the Group’s accounting policies 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 for which ultimate actual outcomes have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities are discussed below. a. Carrying value of intangible exploration and evaluation assets The outcome of ongoing exploration, and therefore whether the carrying value of intangible exploration and evaluation assets will ultimately be recovered, is inherently uncertain. Management makes the judgments necessary to implement the Group’s policy with respect to exploration and evaluation assets and considers these assets for impairment at least annually with reference to the indicators set out in IFRS 6. Assets are aggregated into Cash Generating Units (“CGUs”) for the purpose of calculating impairment based on their ability to generate largely independent cash flows and giving consideration to the geography, geology, production profile and infrastructure of its assets. The allocation of assets into CGUs requires significant judgment and interpretations with respect to the integration between assets, the existence of active markets, similar exposure to market risks, shared infrastructures and the way in which management monitors the operations.   b. Acquisition of subsidiaries Due to the inherently uncertain nature of the oil and gas industry, the assumptions underlying the fair values of identifiable assets and liabilities of OP Hawler Kurdistan Limited (formerly Norbest Limited) and KPA Western Desert Energy Limited, which were acquired on August 10, 2011 and December 21, 2011 respectively, and the probability of exploration success that could result in paying contingent consideration, and quantification thereof, are judgemental in nature. Further details on the measurement of the contingent consideration are disclosed in Note 32. c. Fair value An assessment of fair value of assets and liabilities is required in accounting for derivative instruments and other items, principally available-for-sale financial assets and disclosures related to fair values of financial assets and liabilities. In such instances, fair value measurements are estimated based on the amounts for which

62

the assets and liabilities could be exchanged at the relevant transaction date or reporting period end, and are therefore not necessarily reflective of the likely cash flow upon actual settlements. Where fair value measurements cannot be derived from publicly available information, they are estimated using models and other valuation methods. To the extent possible, the assumptions and inputs used take into account externally verifiable inputs. However, such information is by nature subject to uncertainty, particularly where comparable market based transactions may not exist. d. Pension benefits The present value of the pension obligations depends on a number of factors that are determined on an actuarial basis using a number of assumptions, as disclosed in Note 27. The assumptions used in determining the net cost (income) for pensions include the discount rate. Any changes in these assumptions will impact the carrying amount of pension obligations and the charge to the statement of comprehensive income. e. Decommissioning obligation The decommissioning obligation is calculated using the current estimated costs to decommission the asset. Liabilities for decommissioning are adjusted every reporting period for changes in estimates. Estimating the decommissioning obligation requires significant judgment as restoration technologies and costs are constantly changing, as are regulatory, political, environmental and safety considerations. Inherent in the calculation of the obligation are numerous assumptions including the ultimate settlement amounts, future third-party pricing, inflation factors, risk free discount rates, credit risk, timing of settlement and changes in the legal, regulatory and environmental and political environments. Future revisions to these assumptions may result in material changes to the decommissioning obligation. Adjustments to the estimated amounts and timing of future decommissioning cash flows are a regular occurrence in light of the significant estimates and judgments involved.  

5. Segment information The Group has a single class of business which is to acquire, explore, develop and produce oil from oil and gas assets. The Group operates in a number of geographical areas based on the location of operations and assets. The Group’s reporting segments comprise each separate geographical area in which it operates.

Middle East

West Africa

Corporate

Total

$'000

$'000

$'000

$'000

(501)

(239)

(39,391)

(40,131)

For the year ended December 31, 2013 General and administrative expense Pre-license costs Impairment of oil and gas assets

(960)

(5,423)

-

(6,383)

(43,992)

(38,956)

-

(82,948)

Depreciation and amortization Other operating expense Segment result

-

(29)

(56,887) (102,340)

(699)

(44,647)

(40,090)

Interest expense (net)

(184,504)

Income tax expense

(1,319)

Net loss for the year

Segment liabilities

(187,077) 2,633

Loss before income tax

Segment assets

(56,887)

(60)

Foreign exchange gains

Capital additions

(728)

(185,823) 154,686

91,709

2,087

248,482

645,708 Middle East (188,624) $'000

242,905 West Africa (6,290) $'000

87,599 Corporate (15,266) $'000

976,212 Total (210,180) $'000

(570)

(50)

(21,992)

(22,612)

(1,526)

(5,082)

-

(6,608)

(29,017)

-

-

(29,017)

For the year ended December 31, 2012 (restated) General and administrative expense Pre-license costs Impairment of oil and gas assets Depreciation and amortization Segment result

(31,113)

(1)

(360)

(361)

(5,133)

(22,352)

(58,598)

Interest income

89

Foreign exchange losses

(231)

Loss before income tax

(58,740)

Income tax benefit

203

Net loss for the year Capital additions

Segment assets Segment liabilities

(58,537) 91,601

44,623

485,348

74,382

(111,086)

(6,079)

1,175

137,399

16,535

576,265

(14,763)

(131,928)

63

6. Staff Costs Year ended

Year ended

December 31

December 31

2013

2012

$'000

$'000 (restated)

Wages and salaries

22,407

9,749

Social security costs

2,959

1,186

24,852

11,569

2,603

1,091

455

311

53,276

23,906

Employee share awards Pension costs Other costs

A portion of the Group’s staff costs and associated overheads are recharged to the joint venture partners, expensed as pre-license expenditure or capitalised where they are directly attributable to on-going capital projects. Amounts are stated gross of recharges. The average number of employees of the Group (including Executive Directors) was:

Year ended

Year ended

December 31

December 31

2013

2012 (restated)

West Africa

4

2

Middle East

14

6

Geneva office

53

31

71

39

7. Interest income Year ended

Year ended

December 31

December 31

2013

2012

$'000

$'000 (restated)

Bank interest

2,202

89

2,202

89

8. Interest expense Year ended

Year ended

December 31

December 31

2013

2012

$'000

$'000 (restated)

Interest expense

(2,262)

-

(2,262)

-

Interest expense relates to accrued interest on contingent consideration arising from the acquisition of OP Hawler Kurdistan Ltd. (Note 32). The acquisition terms included the payment of interest on additional consideration contingent upon the outcome of future drilling activities. Interest is calculated at the rate of LIBOR plus 0.25% per annum, compounded on an annual basis.  

64

9. Foreign exchange gains/losses

Year ended

Year ended

December 31

December 31

2013

2012

$'000

$'000 (restated)

Realized foreign exchange gains / (losses) Unrealized foreign exchange losses

2,924 (291) 2,633

(49) (182) (231)

On May 9, 2013, the Group sold CAD$150 million and purchased $149.4 million at the forward rate of CAD$1.0043 per $1, with delivery on May 21, 2013. A foreign exchange gain of $3.1 million was realised on this transaction.

10. Income tax expense Year ended

Year ended

December 31

December 31

2013

2012

$'000

$'000 (restated)

Current tax: Current income tax expense Adjustments in respect of prior years Total current income tax

(1,321) (40) (1,361)

(797) 130 (667)

Deferred tax: Deferred tax on long-term incentive plan

(91)

369

Deferred tax on defined benefit obligation

133

501

42

870

Total deferred tax Income tax (expense) / benefit

(1,319)

203

The Group is subject to income taxes in certain territories in which it owns licenses or has taxable operations. The current income tax expense relates to tax on profit from operations of the Group’s Swiss and Maltese subsidiaries. The deferred tax represents tax on unvested shares issued for the long-term incentive plan and on defined benefit obligations following the adoption of the amendments to IAS 19 – Employee Benefits.  

65

10. Income tax expense (continued) The charge for the year can be reconciled to the loss per the statement of comprehensive income as follows:

Year ended

Year ended

December 31

December 31

2013

2012

$'000

$'000 (restated)

Loss before income tax Combined Canadian federal and provincial income tax credit at the statutory rate / Maltese rate* Effect of income exempt from taxation Effect of unused tax losses unrecognized in deferred tax assets

(184,504)

(58,740)

50,817

20,559

4,761

5,527

(11,111)

Utlization of previously unrecognized tax losses

-

Effect of tax rates of subsidiaries operating in other jurisdictions Effect of non-deductible expenses Income tax (expense) / benefit

(378) 4,457

(117)

(229)

(45,669)

(29,733)

(1,319)

203

* The tax expense for the nine months ended December 31, 2013 was calculated using the combined Canadian federal and provincial tax rates, being 25%. The tax expense for the three months ended March 31, 2013 and the year ended December 31, 2012 was calculated using the Maltese tax rate, being 35%. Deferred tax assets have been recognised for unvested amounts relating to the long-term incentive plan of the Group’s Maltese subsidiary and defined benefit obligations relating to the Group’s Swiss subsidiary. No other deferred tax assets have been recognised for the benefit of tax deductions and tax losses because realisation of the deferred tax assets in the foreseeable future is not sufficiently probable. Cumulative unused tax losses unrecognised in deferred tax assets amount to $50.1 million at December 31, 2013 (December 31, 2012: $5.4 million (restated)).  

11. Intangible assets Note

Explor at ion & Evaluat ion costs $'000

Com pute r Soft war e $'000

Total $'000

371,122

645

371,767

136,124 73

642 -

136,766 73

507,319

1,287

508,606

211,266 (406,720)

397 -

211,663 (406,720)

311,865

1,684

313,549

156

156

Cost At January 1, 2012 Additions Transfers and reclassifications

12

At December 31, 2012 (restated) Additions Transfers and reclassifications (1)(2) At December 31, 2013

12

Accumulated amortization and impairment At January 1, 2012

-

Amortization Impairment charge(3)

29,017

271 -

271 29,017

At December 31, 2012 (restated)

29,017

427

29,444

Amortization

82,948

437 -

437 82,948

111,965

864

112,829

478,302 199,900

860 820

479,162 200,720

(4)(5)(6)

Impairment charge

At December 31, 2013 Net book value At December 31, 2012 (restated) At December 31, 2013

66

1. In March 2013, a portion of the Hawler license area E&E costs in Kurdistan was transferred from intangible assets to property, plant and equipment (PP&E) following a reserve report, effective March 31, 2013, from Netherland, Sewell & Associates, Inc. (NSAI) confirming the discovery of reserves at Demir Dagh within the license area. As a result, $373.2 million of costs associated with the license area were transferred from intangible E&E assets to Oil and Gas assets classified as PP&E. 2. Following a further reserve report from NSAI, effective December 31, 2013, confirming the discovery of reserves at Zey Gawra within the Hawler license area, $33.5 million of costs associated with Zey Gawra were transferred from intangible E&E assets to Oil and Gas assets classified as PP&E. Please refer to Note 33 for further information. 3. Mateen-1 was drilled by the operator of the Sindi Amedi block, with technical support provided by Oryx Petroleum. The understanding of the structure did not support a working petroleum system on Mateen. The impairment charge of $29.0 million recorded in 2012 was reviewed and adjusted downwards by $1.2 million in the second quarter of 2013, based on new information received from the operator. 4. Drilling on the Dila prospect, one of several identified prospects in the OML 141 license area offshore Nigeria was completed in the second quarter of 2013. Oil was encountered during the drilling, but the estimated quantities of oil were not sufficient to be considered commercial. The Group considered the well unsuccessful and an impairment charge of $21.7 million was recorded during the second quarter of 2013. 5. On April 25, 2013, in conjunction with the operator, Oryx Petroleum relinquished 34% of the Sindi Amedi license area to the Kurdistan Regional Government in exchange for the replacement of an exploration well commitment with the acquisition of 180km of seismic data in the retained license area. Following acquisition of this seismic data, during the third quarter of 2013, the Company decided to relinquish its remaining interest in the Sindi Amedi license area upon expiry of the initial exploration period on October 2, 2013. An impairment charge of $45.2 million was recorded during the second half of 2013. 6. In conjunction with the operator, drilling on the Horse prospect (formerly Ma) in the western portion of the Haute Mer A license area offshore Congo (Brazzaville) was completed in the fourth quarter of 2013. Although the H-1 well encountered both Tertiary and Cretaceous reservoirs with good porosity, the reservoirs were water bearing. The Company considers the well unsuccessful. An impairment charge of $17.3 million was recorded during the fourth quarter of 2013. The carrying amounts of intangible E&E assets relate to:

December 31

December 31

2013

2012

$'000

$'000 (restated)

Middle East West Africa

95,930 103,970

427,003 51,299

199,900

478,302

The net reduction to intangible E&E assets during the year ended December 31, 2013 reflects the transfer to PP&E of $406.7 million due to the successful drilling at Demir Dagh and Zey Gawra in the Hawler license area and the impairment charges of $82.9 million relating to the Sindi Amedi license area, the Dila-1 well in OML 141 and the H-1 well in the Haute Mer A license area. These amounts are offset by additions of $211.3 million. The amounts for intangible assets represent costs incurred on active exploration projects. These amounts remain capitalised, provided there are no indications of impairment, until the process is completed to determine whether reserves are established. At that stage the relevant costs are either transferred to PP&E or written-off to the statement of comprehensive income as exploration expense. The National Assembly of Congo (Brazzaville) announced on July 25, 2013 that it had approved a one year extension to the initial exploration period of the Haute Mer A license area to September 2014. One of the two subsequent three year extension periods will be shortened to two years.

67

12. Property, plant and equipment Note Cost At January 1, 2012 Additions Transfers and reclassifications

11

At December 31, 2012 (restated) Transfers and reclassifications (1)(2) Additions

11

At December 31, 2013

Oil and Gas Assets $'000

Fixtures and Equipment $'000

Total $'000

-

111

111

-

633 (73)

633 (73)

-

671

671

406,720

-

406,720

35,047

1,773

36,820

441,767

2,444

444,211

Accumulated depreciation At January 1, 2012

-

6

6

Depreciation

-

90

90

At December 31, 2012 (restated)

-

96

96

Depreciation

-

291

291

At December 31, 2013

-

387

387

441,767

575 2,057

575 443,824

Net book value At December 31, 2012 (restated) At December 31, 2013

1. In March 2013 a portion of the Hawler costs in Kurdistan was transferred from intangible E&E assets to PP&E following a reserve report from NSAI, effective March 31, 2013, confirming the discovery of reserves at Demir Dagh within the license area. As a result, $373.2 million of E&E costs associated with the license area were transferred from intangible E&E assets to Oil and Gas assets classified as PP&E. 2. Following a further reserve report from NSAI, effective December 31, 2013, confirming the discovery of reserves at Zey Gawra within the Hawler license area, $33.5 million of costs associated with Zey Gawra were transferred from intangible E&E assets to Oil and Gas assets classified as PP&E. Please refer to Note 33 for further information. During the third quarter of 2013, the Kurdistan Regional Government gave its consent to lease an Early Production Facility for the Demir Dagh area of the Hawler license. Refer to Note 31 for further information on the increase in capital commitments due to the finalisation of the Early Production Facility lease contract. No assets have been pledged as security.

13. Inventories December 31

December 31

2013

2012

$'000

$'000 (restated)

Exploration materials

No inventories have been recognised as an expense during the year (2012: $nil). No inventories have been pledged as security.

68

12,465

5,601

12,465

5,601

14. Trade and other receivables December 31

December 31

2013

2012

$'000

$'000 (restated)

Advances paid on contracts

5,500

4,000

Receivables from joint venture partners

717

7,197

Receivables from related parties

116

-

Other receivables

273

1,164

6,606

12,361

Trade and other receivables are denominated in the following currencies:

December 31

December 31

2013

2012

$'000

$'000 (restated)

US Dollar

6,239

11,752

306

362

Euro

28

241

Central African Franc

33

6

6,606

12,361

Swiss Franc

The carrying amounts of trade and other receivables presented above are reasonable approximations of the fair value and not past due or impaired as of the date of issuance of these financial statements. The balance of joint venture receivables arises from timing differences between cash calls and the expenditure incurred on behalf of joint venture partners. Cash calls are normally due within 15 days.

15. Prepaid charges December 31

December 31

2013

2012

$'000

$'000 (restated)

Prepaid charges

5,652

4,971

5,652

4,971

16. Cash and cash equivalents December 31

December 31

2013

2012

$'000

$'000 (restated)

Cash at bank and in hand

306,034

72,725

306,034

72,725

69

16. Cash and cash equivalents (continued) Cash and cash equivalents are denominated in the following currencies:

December 31

December 31

2013

2012

$'000

$'000 (restated)

US Dollar

304,848

72,256

Swiss Franc

736

408

Euro

242

13

Central African Franc

49

47

Canadian Dollar

28

-

116

-

15

1

306,034

72,725

Nigerian Naira Iraqi Dinar

Cash and cash equivalents comprise cash and short-term deposits with an original maturity of three months or less, substantially held in interestbearing accounts. The carrying amounts presented above are reasonable approximations of the fair value. AOG provided additional equity funding to the Group amounting to $234.8 million in January 2013. As a result of the initial public offering, the Group received a total of $236.0 million (CAD$238.9 million) which represents the total offering of $249.4 million (CAD$250.5 million), net of underwriters’ fees.

17. Deferred tax assets The analysis of deferred tax assets is as follows:

December 31

December 31

2013

2012

$'000

$'000 (restated)

Deferred tax assets to be recovered after twelve months

911

870

Deferred tax assets

911

870

The movement in deferred tax assets during the year is as follows:

70

Defined benefit

Long-term

plan

incentive plan

Total

$'000

$'000

$'000

At December 31, 2012 (restated)

501

369

870

Credited / (debited) to the income statement

132

(91)

41

At December 31, 2013

633

278

911

18. Trade and other payables December 31

December 31

2013

2012

$'000

$'000 (restated)

Trade accounts payable

14,033

8,381

Payables to joint venture partners

12,213

6,349

1,120

2,608

136,807

60,087

40,706

43,383

204,879

120,808

Less : Non-current portion

(66,271)

(37,687)

Current portion

138,608

Payables to related parties Contingent costs Other payables and accrued liabilities

83,121

Included in Other payables and accrued liabilities is $0.7 million due by way of a direct contribution towards the construction of a hospital for children in Erbil in Kurdistan (December 31, 2012: $40.0 million). Trade and other payables are denominated in the following currencies:

December 31

December 31

2013

2012

$'000

$'000 (restated)

192,811

117,680

Swiss Franc

9,734

2,358

Euro

1,790

272

349

152

26

22

166

284

3

40

204,879

120,808

US Dollar

UK Pound Central African Franc Canadian Dollar Nigerian Naira

Trade and other payables comprise current amounts outstanding for trade purchases and ongoing costs. Contingent costs relate to the acquisition of OP Hawler Kurdistan Ltd (Note 32). The carrying amounts of trade and other payables presented above are reasonable approximations of their fair value.

19. Current income tax liabilities

December 31

December 31

2013

2012

$'000

$'000 (restated)

Corporation tax payable

463

870

463

870

71

20. Decommissioning obligation The Group has an obligation to decommission the drilled wells upon ultimate future cessation of operations. The estimated net present value of the decommissioning obligation at December 31, 2013 is $1.3 million (December 31, 2012 – nil), based on a total undiscounted liability of $22.9 million. The decommissioning obligation was discounted using a rate of 12.0% at December 31, 2013.

Year ended December 31 2013 $'000

Year ended December 31 2012 $'000 (restated)

-

Decommissioning obligation, beginning of the year

-

Property acquisition and development activity

1,346

-

Decommissioning obligation, end of the year

1,346

-



21. Borrowings December 31

December 31

2013

2012

$'000

$'000 (restated)

Convertible loan notes - unsecured

-

7,781

Current portion

-

7,781

The fair value of borrowings equalled their carrying amount, as the impact of discounting was not significant. All borrowings were denominated in US Dollars. At December 31, 2012, the Group had 7,681 loan notes convertible at par value of $1,000 and 80 loan notes convertible at $1,250 being $7,781 convertible loan notes in total. During the first quarter of 2013, the loan notes were fully converted into equity. Furthermore, the Group entered into an uncommitted bond facility agreement on March 26, 2013 whereby up to a maximum of US$15 million may be used by OPHP for bank guarantees. As of December 31, 2013, no guarantees were issued under this agreement.

22. Share capital and share premium Issued and fully paid

Number

Share

Share

of shares

capital

premium

$'000

$'000

At January 1, 2012

105,153

105,153

-

Issue of shares

394,158

394,158

771

At December 31, 2012 (restated)

499,311

499,311

771

Issue of shares

260,606

260,606

4,531

At May 15, 2013

759,917

759,917

5,302

OPCL share capital upon incorporation Issue of shares

1 99,854,917

1,009,684

-

At December 31, 2013

99,854,918

1,009,684

-

The Company has unlimited authorised share capital outstanding as at December 31, 2013. Prior to the Company’s initial public offering, OPHP had authorised two classes of ordinary shares which carried no right to fixed income. The holders of ordinary ‘A’ shares were entitled to appoint all the directors of the Company. Otherwise, both classes of shares ranked pari passu. Prior to the IPO, AOG International Holdings Ltd held 699,900 ordinary ‘A’ shares and its parent, AOG, which was the ultimate parent company of the Company, held 100 ordinary ‘B’ shares. Additionally, 42,540 ordinary ‘B’ shares were held by directors of AOG, persons connected to AOG, Group management and employees of the Group via the Long Term Incentive Plan and investments in the Company. Immediately prior to the closing of the initial public offering, the Group, AOG and its affiliates, as well as other shareholders of the Company, engaged in certain transactions whereby the Company acquired all of the issued and outstanding shares of OPHP in exchange for 81,762,377 common shares of the Company. These shares acquired include 10,920 shares of OPHP issued prior to closing to the employees and executive officers of OPHP, as well as 6,457 shares of OPHP issued to employees and executive officers of OPHP under previously issued awards pursuant to the OPHP long term incentive plan.

72

On May 5, 2013, the Company announced the filing of a supplemented PREP prospectus with the securities regulatory authorities in each of the provinces of Canada, other than Quebec, in connection with its initial public offering of 16,700,000 common shares, at a price of CAD$15.00 per common share for total gross proceeds of CAD$250.5 million ($249.4 million). The IPO closed on May 15, 2013. Immediately prior to closing, a corporate restructuring occurred whereby the Company became the parent company of OPHP. Although the consolidated financial information has been released in the name of the Company it represents in-substance continuation of the pre-existing Group, headed by OPHP. Holders of 21,155 ordinary ‘B’ shares of OPHP had the right to purchase an additional half share at par value for every share held (warrants). Warrant holders could exercise the right to purchase shares at any time once completing three years’ service, or on the occurrence of an exit event, such as an offering of the Company’s shares to the public. Accordingly, prior to closing of the IPO, the warrants, which represented an entitlement to acquire 10,515 shares of OPHP, were cancelled in exchange for 1,131,349 warrants issued by the Company that entitled the holder to acquire, for each warrant held, one common share of the Company at $9.29 per share for a period of 10 business days following the closing. All warrants were exercised on or before June 13, 2013 resulting in an issuance of 1,131,349 common shares for net proceeds to the Company of $10,515,000. Subsequent to the IPO, during 2013, the Group issued 239,703 shares to employees and executive offers under the Group’s long term incentive plan and 8,607 shares to employees and executive officers as a share gift. In addition, 12,881 shares were issued to Directors of the company as remuneration.

Common shares outstanding at January 1, 2013

1

OPHP shares acquired by the Company immediately prior to the IPO

81,762,377

Initial public offering

16,700,000

First stage investors options exercised

1,131,349

Share gift

8,607

Long term incentive plan

239,703

Directors' compensation

12,881 99,854,918

Common shares outstanding at December 31, 2013  

23. Basic and diluted loss per share The loss and weighted average number of ordinary shares used in the calculation of the basic and diluted loss per share are as follows:

December 31

December 31

2013

2012

$'000

$'000 (restated)

Loss for the year attributable to equity holders Weighted average number of ordinary shares for basic and diluted loss per share*

Basic and diluted loss per share

(185,564)

(58,359)

90,797,365

27,832,823

$

$

(2.04)

(2.10)

* For 2012, warrants, convertible loan notes, treasury shares and unvested LTIP shares were excluded as they were then anti-dilutive. For 2013, the unvested LTIP shares are excluded as they are anti-dilutive. There were no warrants, convertible loan notes or treasury shares at December 31, 2013. The weighted average number of shares of OPHP for the year ended December 31, 2012 is presented as if they were shares of the Company (refer to Note 22).

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24. Other reserves

Treasury shares $'000

Share based payments $'000

Total $'000

(864)

3,449

2,585

(8,468) 9,332

11,729 (9,332)

11,729 (8,468) -

At December 31, 2012 (restated)

-

5,846

5,846

Share based payment transactions* Issue of shares for long-term incentive plan Issue of shares for Directors' compensation

-

25,047 (25,533) (174)

25,047 (25,533) (174)

At December 31, 2013

-

5,186

5,186

At January 1, 2012 Share based payment transactions Issue of shares for long-term incentive plan Release of shares for long-term incentive plan

*Share based payments for the year ended December 31, 2013 include a share grant to employees and executive officers of $13.7 million immediately prior to the Company’s initial public offering.  

25. Net cash used in operations

December 31

December 31

(184,504)

(58,740)

728 (4) 60 25,047 82,948 (1,964)

361 10 (89) 11,729 29,017 (97)

Operating cash flows before movements in working capital

(77,689)

(17,809)

Increase in inventories (Increase)/decrease in trade and other receivables Increase in trade and other payables

(6,864) 8,555 66,850

(5,528) (6,541) 6,163

Net cash used in operations

(9,148)

(23,715)

2013 $'000

Net loss before income tax

2012 $'000 (restated)

Adjustments for: Depreciation and amortization Foreign exchange (gains) / losses Interest expense / (income) - net Share based payment expense Impairment of intangible assets Decrease in retirement benefit obligation, net of remeasurement

26. Share based payments Initial share gift An initial share gift comprising common shares of Oryx Petroleum Company PLC was granted to officers and employees who commenced employment before the end of January 2011. An initial share gift of 50 common shares of OPHP was granted to each non-executive director of the Company on their appointment in 2012, totalling 300 shares of OPHP. These shares vested immediately. Long term incentive plan The long term incentive plan (LTIP) was introduced in 2010 to provide a long-term incentive scheme which motivates all employees and provides a longer-term perspective to the total remuneration package. Annual awards under the LTIP comprised common shares, originally of Oryx Petroleum Company PLC and now of the Company. These shares vest in three equal tranches with one-third vesting immediately on date of grant, one-third on July 1 the following year and the balance vesting on July 1 the year after. 2,628 shares of OPHP relating to the 2011 LTIP, 3,705 shares of OPHP relating to the 2012 LTIP and 232,387 shares of the Company relating to the 2013 LTIP vested during the year ended December 31, 2013. (2012: 2,150 shares of OPHP relating to the 2010 LTIP, 2,831 shares of OPHP relating to the 2011 LTIP and 3,620 shares of OPHP relating to the 2012 LTIP vested). Immediately prior to the initial public offering 6,457 shares of OPHP were issued to employees and executive officers of OPHP under previously issued awards pursuant to the OPHP long term incentive plan (Note 22).

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The following shares have been awarded under the 2011, 2012 and 2013 schemes:

LTIP Number of shares

Share gift Number of shares

Total Number of shares

772,631

-

772,631

46,050 1,159,108 (231,327) (304,598) (389,490)

32,278 -

46,050 32,278 1,159,108 (231,327) (304,598) (389,490)

At December 31, 2012 (restated)

1,052,374

32,278

1,084,652

Shares Shares Shares Shares Shares Shares

5,100 711,998 (282,756) (419,292) (240,994)

1,174,923 -

5,100 1,174,923 711,998 (282,756) (419,292) (240,994)

826,430

1,207,201

2,033,631

At January 1, 2012 Shares Shares Shares Shares Shares Shares

granted for 2011 LTIP granted for 2012 share gift granted for 2012 LTIP issued for 2010 LTIP issued for 2011 LTIP issued for 2012 LTIP

granted for 2012 LTIP granted for 2013 share gift granted for 2013 LTIP issued for 2011 LTIP issued for 2012 LTIP issued for 2013 LTIP

At December 31, 2013

The number of shares granted and issued of OPHP prior to the initial public offering are presented as if they were shares of the Company (see Note 22) The amount of share based payments in respect of officers and employees charged to the statement of comprehensive income for the year ended December 31, 2013 was $24.9 million (2012: $11.6 million). Prior to the initial public offering, the fair value of the shares granted under the long term incentive plan was determined by management in the absence of readily available market value and was calculated based on asset values of the Group. The fair value of the shares of OPHP granted in 2011 was $1.00 thousand per OPHP share and $1.25 thousand per OPHP share for 2012. For the 2013 LTIP plan, the shares have been granted at a range between $12.33 and $14.01 per share (CAD $13.22 and CAD $14.49 per share). Subsequent to the initial public offering, the fair value of the shares of the Company granted under the long term incentive plan has been determined based on the volume weighted average price of the shares issued for the five days prior to the grant date.

27. Retirement benefit obligation The Group operates a defined benefit pension plan for all employees of Oryx Petroleum Holdings PLC and its subsidiary, Oryx Petroleum Services SA. The plan is funded by the payment of contributions to separately administered pension funds. The disclosures set out below are based on calculations carried out as at December 31, 2013 by a qualified independent actuary and have been prepared in accordance with IAS 19 – Employee Benefits. The principal actuarial assumptions used at the reporting date were:

Discount rate Expected return on plan assets Expected rate of salary increases Future pension increases Inflation

December 31 2013

December 31 2012 (restated)

2.20% 2.20% 2.00% - 2.50% 0.00% 1.00%

2.00% 2.00% 2.00% - 2.50% 0.00% 1.00%

The following table reconciles the funded status of defined benefit plans to the amounts recognised in the consolidated statement of financial position:

December 31 2013 $'000

December 31 2012 $'000 (restated)

Fair value of plan assets Present value of defined benefit obligation

20,605 24,097

15,553 18,022

Defined benefit obligation

(3,492)

(2,469)

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The change in the defined benefit obligation is as follows:

December 31 2013 $'000

December 31 2012 $'000 (restated)

Opening defined benefit obligation Current service cost Interest cost Remeasurement losses Translation difference Other

(2,469) (2,607) (397) (1,424) (72) 3,477

Defined benefit obligation

(3,492)

(739) (1,169) (309) (2,542) (74) 2,364 115 (2,469)

The change in the fair value of plan assets is as follows:

December 31 2013 $'000s

December 31 2012 $'000s (restated)

Opening fair value of plan assets Interest income Return on plan assets Employer contributions Benefits deposited Translation difference

15,553 353 (468) 2,929 1,611 627

11,720 337 (304) 2,085 809 906

Fair value of plan assets

20,605

15,553

The fair value of the plan assets are comprised of investments held by the insurance company that fully reinsures the Group’s pension liabilities. The amounts recognised in comprehensive income are determined as follows:

December 31 2013 $'000s

December 31 2012 $'000s (restated)

Current service cost Net interest expense / (income) Other

2,607 45 9

1,169 (28) 40

Defined benefit cost recognized in profit or loss

2,661

1,181

The following table summarises the present value of the defined benefit obligation with certain changes in the actuarial assumptions used:

Decrease in discount rate of 0.25% Increase in discount rate of 0.25% Decrease in salary increases of 0.25% Increase in salary increases of 0.25% Decrease in life expectancy of one year Increase in life expectancy of one year

December 31 2013 $'000s

December 31 2012 $'000s (restated)

25,444 23,271 24,047 24,581 24,144 24,499

18,753 17,281 17,815 18,172 17,817 18,164

Defined benefit costs of $2.7 million recognised in the statement of comprehensive income have been included in general and administrative expenses. The Group expects to make contributions of $1.9 million to the defined benefit plan during the next financial year. The actual contributions for 2013 amounted to $2.9 million (2012: $2.1 million).

76

28. Subsidiaries Details of the Company’s subsidiaries at December 31, 2013 are as follows: Country of Principal Proportion of Name of subsidiary incorporation activity interest/voting rights Oryx Petroleum Holdings PLC(1) Malta Intermediate holding company 100% Oryx Petroleum Services SA Switzerland Administrative/technical services 100% Oryx Petroleum Middle East Ltd BVI Intermediate holding company 100% Oryx Petroleum Africa Ltd BVI Intermediate holding company 100% OP OML 141 Nigeria Ltd Nigeria Exploration for oil and gas 100% OP AGC Shallow Ltd BVI Exploration for oil and gas 100% OP Sindi Amedi Kurdistan Ltd BVI Exploration for oil and gas 100% OP Hawler Kurdistan Ltd(2) BVI Exploration for oil and gas 100% Oryx Petroleum Congo SA Congo Exploration for oil and gas 100% BVI Exploration for oil and gas 100% OP (TBA) Ltd(4) OP Iraq Ltd BVI Exploration for oil and gas 100% KPA Western Desert Energy Ltd(3) Cyprus Intermediate holding company 66.67% AmiraKPO Ltd(3) Cyprus Exploration for oil and gas / 66.67% Mining of bitumen Cyprus Exploration for oil and gas 66.67% AmiraKPO Exploration Ltd(3) AmiraKPO Petroleum Company Ltd(3) Cyprus Mining of bitumen 66.67% AmiraKPO Middle East Ltd Malta Intermediate holding company 60% Sandhill Petroleum Operations Ltd Anguilla Exploration for oil and gas 60% Desert Hill Petroleum Operations Ltd Anguilla Exploration for oil and gas 60% Damsel Petroleum Operations Ltd Anguilla Exploration for oil and gas 60% Black Hills Petroleum Operations Ltd Anguilla Exploration for oil and gas 60% Raval Petroleum Operations Ltd Anguilla Exploration for oil and gas 60% 1. Held directly by Oryx Petroleum Corporation Limited. All others are held through subsidiary undertakings. 2. OP Hawler Kurdistan Ltd was formerly known as Norbest Ltd. 3. In the fourth quarter of 2013, Oryx Petroleum Middle East Ltd increased its participating interest in KPA Western Desert Energy Ltd., and its subsidiary undertakings, from 50% to 66.67%. 50 million additional shares of KPA Western Desert Energy Ltd. were purchased for $0.001 per share. 4. OP (TBA) Ltd was formerly known as OP Taoudeni Mauritania Ltd A material non-controlling interest in the Group’s activities is held through the following subsidiary:

Subsidiary

Ownership Interest

AmiraKPO Ltd

66.67%

Loss allocated to non-controlling interests during 2013 $'000s

Accumulated non-controlling interests at December 31, 2013 $'000s

-

16,954

Summarised financial information for AmiraKPO Ltd is provided below

Total assets Total liabilities Net loss for the year

December 31 2013 $'000s

December 31 2012 $'000s (restated)

45,293 3,788 -

40,369 14,937 (661)

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29. Related party transactions The Group’s indirect majority shareholder is AOG (incorporated in Malta). The majority of AOG’s outstanding shares are owned by Samsufi Trust, an irrevocable discretionary charitable trust created at the suggestion of Jean Claude Gandur, a director and the Chairman of the Company. Mr. Gandur is not one of the beneficiaries of the Samsufi Trust. The following transactions were carried out with related parties, which are all subsidiaries of AOG. (a) Purchases of goods and services

Year ended

Year ended

December 31

December 31

2013

2012

$000

$000 (restated)

32

51

AOG Advisory Services SA

AOG International Holdings Ltd

1,692

1,368

Addax and Oryx Group Ltd

2,178

2,636

-

21

20

188

4

4

Addax Bioenergy Management Addax Energy SA Addax Immobilier SA Addax Nigeria Ltd.

160

-

AOG Advisory Services Ltd

105

344

-

1

4,191

4,613

Oryx Supply & Storage SA

Purchases of goods and services have been acquired on normal commercial terms and conditions. In addition $0.5 million (2012: $nil) has been donated to The Addax and Oryx Foundation, a Swiss-registered charity. (b) Payables to related parties

Year ended

Year ended

December 31

December 31

2013

2012

$000

$000 (restated)

AOG Advisory Services SA

1,105

533

Addax and Oryx Group Ltd

14

2,001

AOG International Holdings Ltd

1

-

Addax Energy SA

-

70

Addax Immobilier SA

-

4

1,120

2,608

The amounts outstanding are unsecured. No guarantees have been given. Amounts owing to related parties relate to purchases of goods and services which were acquired on normal commercial terms and will be settled in cash. (c) Receivables from related parties

December 31

December 31

2013

2012

$000

$000 (restated)

AOG Advisory Services Ltd

39

38

39

38

The amounts outstanding were acquired by related parties on normal commercial terms and will be settled in cash. The receivables are unsecured and bear no interest. No provisions are held against receivables from related parties. (d) AOG guarantee Certain contingent payments (Note 32) are supported by a guarantee provided by AOG.

78

(e) Key management compensation The remuneration of the directors and senior officers, the key management personnel of the Group, in aggregate is set out below.

Year ended

Year ended

December 31

December 31

2013

2012

$000

$000 (restated)

Wages, salaries and other short term benefits Post employment benefits Share-based compensation

6,640

2,988

438

383

10,125

5,504

17,203

8,875



30. Financial instruments by category Financial assets

December 31

December 31

2013

2012

$000

$000

$000

(restated)

Loans and receivables Trade and other receivables Cash and cash equivalents

Financial liabilities

6,606

12,361

306,034

72,725

312,640

85,086

December 31

December 31

2013

2012

$000

$000

$000

(restated)

Amortized cost Trade and other payables Borrowings

204,879

120,808

-

7,781

204,879

128,589

The fair value of the financial assets and liabilities approximates the carrying amounts.

31. Commitments (a) Capital commitments It will be necessary to incur expenditure in order to maintain existing exploration and appraisal rights, therefore as at December 31, 2013, the Group had capital commitments totalling $177.9 million (December 2012: $177.4 million) which includes minimum work obligations on production sharing contracts of $63.6 million (December 2012: $58.5 million). The Group signed a lease agreement during the third quarter of 2013 for an Early Production Facility relating to the Demir Dagh development in the Hawler license area. The commitment related to this lease agreement is $35.2 million. During the second quarter of 2013, the Group resolved to donate a total of $1.5 million over a period of 3 years to The Addax & Oryx Foundation. The first payment of $0.5 million was made in July 2013. (b) Operating lease commitments – Group company as lessee The Group leases buildings and equipment under non-cancellable operating lease agreements with varying terms and renewal rights. The corresponding lease expenditure charged to the statement of comprehensive income during the year ended December 31, 2013 was $1.2 million (December 2012: $0.9 million). The future aggregate minimum lease payments under non-cancellable operating leases are as follows:

Leases which expire

December 31

December 31

2013

2012

$000

$000 (restated)

No later than one year

677

13

One to five years

139

-

816

13

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32. Contingent liabilities During 2011, the Group acquired interests in various exploration licenses. The acquisition terms included additional consideration and other liabilities, contingent upon the outcome of future drilling activities and, in some cases, the quantities of reserves discovered. At December 31, 2013 these amounted in aggregate to a maximum of $193.5 million (December 31, 2012 – $197.5 million). In accordance with the terms of the agreements for the acquisition of interests in these license areas, the Group is contractually obliged to make the payments upon a declaration of commercial discovery. If quantities of hydrocarbons discovered are not determined to be commercial, no payments will be due. The aggregate fair value of the contingent consideration, based on the estimated probability of success, was initially evaluated by the directors at $46.3 million, of which $27.7 million was first recognised in the Group’s statement of financial position at December 31, 2011 in relation to the Hawler license area acquired as part of the business combination with Norbest Limited (subsequently renamed OP Hawler Kurdistan Limited). The determination of fair value was principally based on an assessment of the available geological data, historical success rates in the region and other related assumptions on the likelihood of commercial success. In addition, the net assets and liabilities acquired with OP Hawler Kurdistan Limited include a contingent payment to the Kurdistan Regional Government in relation to the declaration of a first commercial discovery. The total potential amount payable is $50 million of which the fair value, based on the estimated probability of success, was initially evaluated by the directors at $32.4 million and recognised in the fair values of the identifiable assets and liabilities acquired. During 2013, the fair values of the contingent consideration and the contingent payment have been re-evaluated following the discovery of reserves in the Hawler license area. The fair value of the payments increased by $74.5 million to an estimated fair value of $134.6 million, of which $70.0 million is expected to be paid within one year. The increase in fair value of the payments resulted in $56.9 million recognised in the statement of comprehensive income for the year ended December 31, 2013 and $17.6 million capitalised to property, plant and equipment. Consequent upon the relinquishment of the Sindi Amedi exploration license in the third quarter of 2013 the aggregate fair value of the contingent consideration was decreased by $3.9 million.

80

33. Events after the balance sheet date In January 2014, the Group determined that the Demir Dagh 2 (DD-2) well discovery is a Commercial Discovery pursuant to the terms of the Hawler Production Sharing Contract (PSC). In accordance with the terms of the Hawler PSC, Oryx Petroleum is obliged to provide an additional payment to the KRG of $50 million which was paid by the Group in February 2014. In accordance with the terms of the agreement of the acquisition of OP Hawler Kurdistan Ltd, Oryx Petroleum is also obliged to provide additional consideration of $20 million to the vendor, of which $10 million was paid in February 2014 with the balance to be paid prior to the end of 2014. In February 2014, the Group updated its reserves and resource volumes based upon a report issued by NSAI effective December 31, 2013. Total gross (working interest) proved and probable oil reserves in the Hawler license area in Kurdistan increased to 213 MMbbl from 164 MMbbl included in the NSAI report effective March 31, 2013. The increase in reserves booked relate primarily to the discovery at Zey Gawra announced in the fourth quarter of 2013. An increase of 23 MMbbl of best estimate gross (working interest) contingent resources was also included in the report effective December 31, 2013 citing a total of 217 MMbbl in the Hawler license area (NSAI report effective March 31, 2013 – 200 MMbbl) and 6 MMbbl in the Haute Mer A license area (NSAI report effective March 31, 2013 - nil). This increase is due to the discoveries at Banan and Ain-Al-Safra in the Hawler license area, and the Elephant discovery in the Haute Mer A license area. Finally, the report effective December 31, 2013 updated the best estimate unrisked gross (working interest) prospective oil resources to 1,167 MMbbl (risked: 209 MMbbl). In February 2014, OPCL extended the uncommitted bond facility agreement for an additional twelve months, whereby up to a maximum of $15 million may be used by Oryx Petroleum for bank guarantees. As at the date of this document, no guarantees were issued under this agreement. In March 2014, the Group announced that the testing of the E-1 exploration well targeting the Elephant prospect in the Haute Mer A license area confirmed the discovery of natural gas and crude oil. The discovery of natural gas and crude oil was previously announced in September 2013. Together with the operator of the license area, the Group will further analyse the test results and other data accumulated during the drilling of the well and determine the next steps. Effective February 25, 2014 OP (TBA) Limited has changed its name to OP AGC Central Limited.

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CONTACT

[email protected] Oryx Petroleum Corporation Limited Registered Office 3400 First Canadian Centre 350 7 Avenue Southwest Calgary, Alberta T2P 3N9 Canada

Iraq OP Hawler Kurdistan Limited Gulan Str., English Village No. 275 Erbil, Kurdistan Region Iraq Tel +41 58 702 94 00

Geneva Oryx Petroleum Services SA 35 rue de la Synagogue 1204 Geneva Switzerland Tel +41 58 702 93 00 Fax +41 58 702 93 40

Congo Oryx Petroleum Congo SA Residence Gabriella Avenue Jean-Marie Concko Centre Ville Pointe Noire Republique du Congo Tel +242 05 708 44 44

Nigeria OP OML 141 Nigeria Limited Maersk House,Third Floor 121 Louis Solomon Close Victoria Island, Lagos Nigeria Tel +234 1 277 8332 or 8333

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oryxpetroleum.com

84