News Column

Oryx Petroleum Q2 2014 Financial and Operational Results

August 6, 2014

 An active quarter highlighted by first production and sales

CALGARY, Aug. 6, 2014 /CNW/ - Oryx Petroleum Corporation Limited ("Oryx Petroleum" or the "Group") today announces its financial and operational results for the quarter ended June 30, 2014.

Highlights:

•Production commenced in June 2014 with gross (100%) production averaging 3,200 bbl/d (working interest production of 2,100 bbl/d) for the twelve days of production in Q2 2014



•Operations continue safely in the Hawler License Area in the Kurdistan Region of Iraq



•Total revenues consisted of $1.4 million on working interest sales of 20,000 bbls and an average realized sales price of $57.73/bbl



•Net loss of $8.7 million ($0.09 per common share) in Q2 2014 compared to a net loss of $38.5 million ($0.43 per common share) in Q2 2013



$55 million of cash and cash equivalents as of June 30, 2014; $262 million including the $207 million in net proceeds from the offering of common shares completed July 18, 2014



•Revised 2014 capital expenditure forecast of $370 to $410 million ($180 to $220 million for 2H 2014)



•Operating Update and Outlook – Hawler License Area (Kurdistan Region of Iraq)



  •Demir Dagh Production and Facilities – First production of oil was achieved during the quarter; the current gross capacity of facilities is approximately 5,000 bbl/d and current gross wellhead production capacity is approximately 15,000 bbl/d; gross (100%) production of 25,000 bbl/d is targeted by the end of Q4 2014



•Demir Dagh Sales – First sales of oil into the domestic market were achieved during the quarter; installation of tie-in lines to the KRI-Turkey export pipeline are underway



•Demir Dagh Appraisal and Development Drilling – during the quarter, successful testing of the Demir Dagh-3 ("DD-3") appraisal well and the Demir Dagh-6 ("DD-6") development well was completed, the Demir Dagh-7 ("DD-7") development well was spudded and a 3D seismic data acquisition program was commenced; three additional development wells are planned in 2014



•Ain Al Safra Appraisal – The Ain Al Safra-2 ("AAS-2") appraisal well has reached total depth of 3,700 metres and a testing program in the Jurassic and Triassic reservoirs will commence in the next few weeks



•Banan Appraisal – The Banan-2 ("BAN-2") appraisal well was spudded in early June 2014 and has reached a depth of approximately 2,600 metres with test results expected in Q4 2014



•Zey Gawra Appraisal – The Zey Gawra-2 ("ZEG-2") appraisal well is expected to be spudded in Q3 2014



•Operations Update and Outlook – West Africa



  •AGC Shallow – Preparations continue for a potentially high impact exploration well targeting the Dome Iris prospect with the well likely to be drilled in the first half of 2015

 

•Haute Mer A – The Group continues to work with its partners in the Haute Mer A license area to determine next steps following the successful test of the Elephant-1 discovery



•Haute Mer B – Planning for a potentially high impact exploration well continues with drilling expected in the first half of 2015



CEO´s Comment

Commenting today, Oryx Petroleum´s Chief Executive Officer, Michael Ebsary, stated:

"The second quarter for Oryx Petroleum was highlighted by the achievement of first production and sales and continued execution of our drilling program. Importantly, and notwithstanding difficult market conditions, we completed an offering of common shares in July. The net proceeds of the offering will fund our operations into 2015.

Activity in the quarter was focused in the Kurdistan Region of Iraq where we commissioned production facilities at the Demir Dagh field and commenced production and sales in the domestic market. We expect to steadily increase production and sales throughout the year as we prepare for export sales. Our exploration and appraisal drilling program during the quarter included the completion of drilling and testing of three wells at Demir Dagh. Appraisal drilling at Ain Al Safra continues with results of a testing program expected in the third quarter of 2014. We spudded the very important BAN-2 appraisal well and are making good progress. Through the balance of the year we will continue appraisal and development drilling in the Hawler license area with the aim of converting contingent resources into reserves, and reserves into production."

Selected Financial Highlights

Financial results are prepared in accordance with International Financial Reporting Standards ("IFRS") and the reporting currency is US dollars. The following table summarises the selected financial highlights for Oryx Petroleum for the three and six month periods ended June 30, 2014 and June 30, 2013 and the year ended December 31, 2013:











Three Months Ended

June 30


Six Months Ended

June 30


Year Ended

December 31


($ in millions unless otherwise indicated)

2014

2013

2014

2013

2013













Revenue

1.4

-

1.4

-

-

Operating Costs

1.2

-

1.2

-

-













Working Interest Production (bbl)

25,000

-

25,000

-

-

Sales (bbl)

20,000

-

20,000

-

-

Average Sales Price ($/bbl)

57.73

-

57.73

-

-

Operating costs ($/bbl)

58.01

-

58.01

-

-

Netback(1) ($/bbl)

(18.62)

-

(18.62)

-

-













Net Loss

8.7

38.5

15.6

85.5

185.8

Net Loss per common share ($/sh)

0.09

0.43

0.16

1.05

2.04













Net Cash used in operating activities

3.6

2.7

27.2

9.4

8.7

Net Cash used in investing activities

94.0

46.4

223.6

102.0

234.1

Capital Expenditures(2)

106.2

48.9

 

186.1

 

90.3

200.2

License Acquisition Costs

-

-

14.5

13.0

48.2













Cash and Cash Equivalents

    55.2(3)



55.2(3)



306.0

Total Assets

932.1



932.1



976.2

Total Equity

754.3



754.3



766.0



(1)

Netback is a non-IFRS measure that represents sales net of Royalties, operating expenses and taxes. Management believes that Netback is a useful supplemental measure to analyse operating performance and provides an indication of the results generated by the Group's principal business activities prior to the consideration of other income and expenses. Netback does not have a standard meaning under IFRS and may not be comparable to similar measures used by other companies.

(2)

Excludes license acquisition costs.

(3)

Does not include net cash proceeds of $207 million from the common share offering completed July 18, 2014



•Revenue for the quarter increased from nil in Q2 2013 to $1.4 million in Q2 2014 due to the commencement of production and sales from the Demir Dagh field in June 2014. Working interest production and sales were 25,000 and 20,000 barrels, respectively, with the difference held in inventory in the Group's Consolidated Statement of Financial Position. The average sales price realised was $57.73 per barrel. In addition to oil sales, Revenue includes recovery of carried costs.



•Operating Costs in the quarter increased from nil in Q2 2013 to $1.2 million in Q2 2014 reflecting the commencement of production from the Demir Dagh field. Q2 2014 costs include non-recurring charges of approximately $1.0 million associated with the start-up of production. As a result of these start-up charges the netback achieved in Q2 2014 was negative $18.62 per barrel.



Net loss for the quarter decreased from $38.5 million in Q2 2013 to $8.7 million in Q2 2014 due primarily to decreases in impairment and general and administrative expenses. Q2 2013 results included an impairment expense related to the Dila well in the OML 141 license area and a $13.7 million charge relating to a share grant to employees and management immediately prior to the completion of the Group´s initial public offering. Moreover, an increasing proportion of the Group`s technical personnel costs are being assigned directly to capital projects. The principal offsetting increases include a $1.6 million charge related to adjustments to the fair value of contingent liabilities associated with the Group`s acquisition of its interest in the Hawler license area, an increase in depreciation, depletion and amortisation expense, and the aforementioned increase in operating costs. As at June 30, 2014 the fair value of the contingent liabilities was $78.4 million and was included in trade and other payables in the Group`s Consolidated Statement of Financial Position.



The weighted average number of common shares outstanding for purposes of net loss per basic and diluted common share calculations for Q2 2014 is 99,983,151. As of June 30, 2014 total common shares outstanding were 99,897,167.



On July 18, 2014 the Group issued 19,910,000 shares as part of a common share offering. On 30 July 2014, the Group issued 12,191 common shares to its Directors as remuneration for services provided in the first and second quarters of 2014. At this time, the Group also issued 923,676 common shares to employees and executive officers under the Group´s Long Term Incentive Plan. Upon vesting, previously granted Long Term Incentive Plan awards will result in the issuance of up to an additional 802,891 Common shares during 2015 and 2016.



•Net cash used in operating activities was $3.6 million for Q2 2014 compared to $2.7 million in Q2 2013. The increase in cash used in operating activities is primarily due to the negative netback realised and higher cash administrative costs associated with increased headcount.  The Q2 2014 result includes a $0.6 million increase in non-cash working capital.

•Net cash used in investing activities increased from $46.4 million in the quarter ended  June 30, 2013 to $94.0 million for the quarter ended June, 30 2014 reflecting increased capital investment activity. In the Middle East, capital expenditures included drilling and testing costs related to the DD-3, DD-5, DD-6, AAS-2 and BAN-2 appraisal wells, Demir Dagh development costs included the costs associated with an Early Production Facility ("EPF") and seismic acquisition costs in the Hawler license area. In West Africa, capital expenditures included testing of the Elephant-1 exploration well in the Haute Mer A license area, and drilling preparation in the AGC Shallow license area. The difference between net cash used in investing activities and capital expenditures in Q2 2014 is primarily due to the timing of cash payments to suppliers.



The following tables summarise the Group`s capital expenditure incurred by activity and by license area for the three and six month periods ended June  30, 2014 and June  30, 2013.





Three months ended



Six months ended





June 30, 2014



June 30, 2013



June 30, 2014



June 30, 2013

($ in millions)

















Middle East

















Hawler



86.7



20.3



154.2



36.2

Wasit



0.2



1.0



0.7



2.9

Sindi Amedi



-



1.5



-



2.4

Sub-Total Middle East



86.9



22.8



154.9



41.5



















West Africa

















AGC Shallow



2.3



0.9



3.3



1.3

OML 141



0.5



21.8



1.7



43.4

Haute Mer A



5.2



2.6



14.7



3.1

Haute Mer B



10.9



-



10.9



-

Sub-Total West Africa



18.9



25.3



30.6



47.8



















Corporate



0.4



0.8



0.6



1.0



















Total capital expenditure



106.2



48.9



186.1



90.3



 





Three months ended



Six months ended





June 30, 2014



June 30, 2013



June 30, 2014



June 30, 2013

($ in millions)

















Middle East

















Exploration drilling



20.5



16.2



38.3



30.1

Appraisal and development drilling



23.8



-



50.9



-

Facilities



24.6



-



39.4



-

Seismic acquisition



5.1



2.3



6.0



3.8

Studies and capitalized G&A



12.9



3.8



20.3



7.1

Property, plant & equipment



-



0.5



-



0.5

Sub-Total Middle East



86.9



22.8



154.9



41.5



















West Africa

















Exploration drilling



5.9



10.2



15.0



20.1

Seismic acquisition



3.4



0.4



3.6



0.7

Studies and capitalized G&A



9.6



14.6



12.0



26.9

Property, plant & equipment



-



0.1



-



0.1

Sub-Total West Africa



18.9



25.3



30.6



47.8



















Corporate



0.4



0.8



0.6



1.0



















Total capital expenditure



106.2



48.9



186.1



90.3





Cash and cash equivalents decreased to $55.2 million from $152.8 million at March 31, 2014 reflecting cash operating expenditures, capital expenditures, and movements in working capital. Oryx Petroleum had no borrowings as of June 30, 2014. On July 18, 2014 the Group completed an offering of common shares raising net proceeds of approximately $207 million.

Selected Operational Highlights

Kurdistan Region of Iraq

•Demir Dagh Appraisal/Development – The Group continues to progress its appraisal and development of the Demir Dagh discovery. Oryx Petroleum has a 65% participating and working interest in the Hawler license area. Netherland, Sewell & Associates, Inc. ("NSAI") estimates as of December 31, 2013 that the Demir Dagh structure contains gross (100%) proved and probable oil reserves of 258 MMbbl, best estimate gross (100%) contingent oil resources of 271 MMbbl and best estimate unrisked gross (100%) prospective oil resources of 50 MMbbl (risked: 10 MMbbl). Key highlights of appraisal and development activity include the following:





•Production Facilities – The Group successfully tested and commissioned its initial Demir Dagh production facilities in June 2014. The initial oil production capacity of the facilities is approximately 5,000 bbl/d. The production facilities are designed to deliver produced oil to a truck loading facility within the Hawler license area, or to transport oil through export pipelines. Production facilities capacity is expected to be sufficient to support  the Group´s gross (100%) production targets of 25,000 bbl/d by the end of Q4 2014 and 40,000 bbl/d in 2015 when the full EPF is commissioned.



•Production, Liftings and Domestic Sales – The Group recorded its first lifting on June 20, 2014. Liftings have averaged 3,000 to 4,000 bbl/d except for a brief interruption in mid-July 2014 caused by constraints on the movement of crude oil and petroleum products across the Kurdistan Region of Iraq. Liftings have since resumed at pre-interruption levels. Production thus far has been sourced from the Demir Dagh-2 ("DD-2") well. The DD-4 and DD-3 wells have been completed as oil producers and the Group is in the process of tieing in these two wells to the production facilities. Additional development wells are expected to continue to increase wellhead production capacity and the Group expects Demir Dagh wells to collectively have capacity sufficient to meet the Group`s target for gross (100%) production of 25,000 bbl/d by the end of Q4 2014.



•Export Infrastructure – A 1.2 kilometre 16" connecting line to the KRI-Turkey export pipeline is expected to be installed during the second half of 2014.



•Appraisal/Development Drilling – The DD-3 appraisal well was drilled approximately 3 km to the southeast of the DD-2 well. The well´s objective was to appraise Cretaceous, Jurassic and Triassic age reservoirs. The DD-3 well reached total measured depth of approximately 4,400 metres and successfully tested oil in the Cretaceous and Jurassic reservoirs. The well was completed as a producer in May 2014 in the Cretaceous.



The DD-5 appraisal well was drilled approximately 3 kilometres to the west of the DD-2 well and reached total measured depth of approximately 1,900 metres in the Lower Cretaceous. The well`s objective was to appraise Cretaceous reservoirs, targeting the saddle area between the Banan and Demir Dagh structures. A testing program was completed in May 2014. During the testing only small quantities of oil flowed to the surface due to an inability to re-connect to the permeable fracture network indicated by logging data and losses observed during drilling.







The DD-6 development well was drilled approximately 1.5 kilometres from the DD-2 well and reached total measured depth of approximately 2,029 metres in the Lower Cretaceous. The well´s objective was to further delineate the Cretaceous reservoir, targeting the crest of the reservoir just to the south of the main fault running from west to east across the structure between the Demir Dagh-1 well and the DD-2 well. A testing program was successfully completed in early July 2014. The well demonstrated high productivity but natural gas encountered at the top of the perforation interval constrained the use of choke sizes and flow rates. The natural gas production suggests presence of a small gas cap in the Demir Dagh Cretaceous. The Group has elected for the time being to use DD-6 as an observation well, given the presence of gas, but may choose to convert it to an oil producer in the future.



Following completion of the testing program on the DD-6 well the EDC Romfor-22 rig spudded the DD-7 development well.  DD-7 is being drilled near the crest of the Demir Dagh structure through the main east-west fault. The well has reached a measured depth of approximately 1,800 metres and is expected to reach a total measured depth of 2,121 metres in Q3 2014. The EDC Romfor-22 rig is scheduled to drill three additional development wells on the Demir Dagh structure in 2014 in order to increase wellhead production capacity and further delineate the Cretaceous reservoir.







•Seismic Acquisition – Acquisition of approximately 440 square kilometres of 3D seismic data over the Demir Dagh, Banan and Zey Gawra structures commenced in June 2014. The 3D seismic data is expected to provide additional information to further refine development plans.



Demir Dagh Full Field Development – The Group`s full field development plans for Demir Dagh are progressing. The Group plans to build a Permanent Production Facility ("PPF") with initial gross (100%) oil production capacity of 100,000 bbl/d. A front end engineering design ("FEED") is almost complete and site construction has begun. The Group plans to continuously drill development wells to increase production capacity in preparation for the commissioning of the PPF in 2016. Should the Demir Dagh, Zey Gawra and Banan appraisal programs result in conversion of significant quantities of possible reserves and/or contingent resources to the proved plus probable classification, the Group expects to expand the capacity of the PPF in a modular fashion.



•Ain Al Safra Appraisal – As announced on October 24, 2013, testing of the Ain Al Safra exploration well ("AAS-1") resulted in an oil discovery in the Lower Jurassic. The KS Discoverer-1 rig spudded the AAS-2 appraisal well in March 2014. The well´s objective is to further appraise the Lower Jurassic interval and the full extent of the discovered oil column and to drill to the Triassic to understand any upside potential that the AAS-1 well was unable to reach. AAS-2 has reached a total measured depth of just over 3,700 metres in the Triassic. Based on logging data and observations during drilling a testing program targeting Jurassic and Triassic reservoirs will commence in the next few weeks with results expected in Q3 2014.



•Banan Appraisal – The Sakson Hilong 10 rig spudded the BAN-2 appraisal well in early June 2014 approximately 5 kilometres to the north-west of the successful Banan-1 exploration well ("BAN-1"). As announced on March 12, 2014 oil was successfully flowed in two cased-hole drill stem tests on the BAN-1 exploration well, one in each of the Cretaceous (Shiranish and top Kometan formations) and the Lower Jurassic (Butmah formation).  Prior to the start of the BAN-1 testing program, NSAI estimated as of December 31, 2013 that the Banan discovery contains low, best and high estimates gross (100%) contingent oil resources of 5, 40 and 440 MMbbl, respectively, all in the Cretaceous formations. NSAI also estimated, as of December 31, 2013, prior to drilling and testing of Jurassic and Triassic formations, that the Banan structure also contains best estimate unrisked gross (100%) prospective oil resources of 235 MMbbl  (risked: 46 MMbbl) in the Tertiary Pila Spi formation, the Jurassic Alan, Mus, Adaiyah and Butmah formations, and the Triassic Kurra Chine formation.



The BAN-1 well was drilled down-dip of the crest of the Banan structure. The Group believes significant up-dip potential exists in all formations. The up-dip potential in the Cretaceous formations in particular is underscored by NSAI´s high estimate of contingent resources for Banan. BAN-2 is being drilled in a more crestal position over the Banan structure than the BAN-1 discovery well and is targeting oil potential in Cretaceous, Jurassic and Triassic formations. The well has reached a measured depth of approximately 2,700 metres in the Jurassic. Observations during drilling thus far in the targeted reservoirs have been encouraging. The well is expected to reach targeted total measured depth of 3,800 metres and complete testing in Q4 2014. Additionally,  data collected and observations during drilling through the Tertiary Pila Spi formation suggest the presence of a potentially sizable deposit of moveable crude oil. As such,  the Group is considering accelerating plans for a shallow well to appraise the Tertiary Pila Spi formation.







•Zey Gawra Appraisal – As announced in December 2013, light oil was successfully tested in the Cretaceous from the Zey Gawra-1 ("ZEG-1") exploration well. The ZEG-2 appraisal well targeting Tertiary and Cretaceous formations will be drilled later in 2014. Additionally, the Group is evaluating the possibility of tieing back wells on Zey Gawra to the Demir Dagh production facilities. NSAI estimates that as of December 31, 2013 the Zey Gawra structure contains 71 MMbbl of gross (100%) proved plus probable oil reserves and 32 MMbbl of best estimate unrisked gross (100%) prospective oil resources (risked: 12 MMbbl).



AGC



•In the AGC Shallow license area Oryx Petroleum has largely completed the processing and analysing of previously acquired 3D seismic data and has chosen the Dome Iris prospect as its first drilling target. The Group is conducting further technical analyses and now expects the exploration well will most likely be drilled in the first half of 2015. NSAI estimates that as of December 31, 2013 the Dome Iris prospect contains unrisked best estimate gross (100%) prospective oil resources of 117 MMbbl (risked: 17 MMbbl).



Congo (Brazzaville)



•Haute Mer A – On September 4, 2013, Oryx Petroleum announced that the Elephant-1 exploration well targeting the Elephant prospect in the Haute Mer A license area discovered crude oil and natural gas. Results of the testing conducted in early 2014 and announced on March 4, 2014 confirmed the discovery. Partners in Haute Mer A are analysing results of the two wells drilled to date in order to determine next steps. More resource volumes need to be discovered in order to justify commercial development.  The Group and its partners continue to work on plans for next steps with at least one well expected to be drilled in 2015. The partners have formally notified the government of Congo (Brazzaville) of their intent to enter the second exploration phase of the Production Sharing Contract and are awaiting formal approval from the National Assembly.



•Haute Mer B – During Q2 2014 members of the contractor group received final approval of the Production Sharing Contract by the National Assembly and President of Congo (Brazzaville). Oryx Petroleum has a 30% participating and working interest in the Haute Mer B license area. The partners are planning to drill an exploration well, which will most likely target the Loubossi prospect. The well is expected to be drilled in the first half of 2015. NSAI estimates that as of December 31, 2013 the Loubossi prospect contains 189 MMbbl of best estimate unrisked gross (100%) prospective oil resources (risked: 24 MMbbl).



Wasit Province of Iraq

•Oryx Petroleum´s activities with regards to its interests in the Wasit province of Iraq were limited in Q2 2014.  The Group is hopeful activities will resume in 2015.

Nigeria

•The Group and its partners in OML 141 continue to develop plans for future activity in OML 141 with limited activity expected prior to 2015.



2014 Capital Expenditure Forecast and Funding Outlook

Reforecasted capital expenditures for 2014 are $370-$410 million versus the previously announced forecast of $400-$450 million.

The following table summarises Oryx Petroleum's reforecasted 2014 annual capital expenditure program.

















Location

License



Drilling

Facilities

Seismic & Studies

Other

Total

2014

Reforecast







$ millions

$ millions

$ millions

$ millions

$ millions

Kurdistan Region

Hawler



208

65 - 85

28

21

322 - 342

Wasit Province

Wasit



-

-

1

4

5

Nigeria

OML 141



-

-

-

4

4

AGC

AGC



5

-

-

5

10

Congo

HMA



9

-

1

3

13



HMB



0 - 22

-

4

7

11 – 33

Corporate

Corporate



-

-

-

4

4

Capex Total



217 - 279

65 - 85

34

48

369 - 411



Notes:

(1)  


The above table excludes budgeted and reforecasted amounts relating to license acquisition costs



The revised forecast reflects the deferment of the planned exploration well in the AGC license area to 2015.  The lower end of the forecast reflects deferment of the exploration well planned for Haute Mer B and a portion of expenditures for the PPF at Demir Dagh into 2015. The full year forecast translates into a second half 2014 forecast of approximately $180 million to $220 million

Oryx Petroleum believes that current cash and cash equivalents are sufficient to fund the Group´s reforecasted capital expenditure program, contingent payments and cash general and administrative costs into 2015 but anticipates it will need to source additional capital to fund the continued expansion of its operations in 2015. Oryx Petroleum is in discussions with various financial institutions with regards to the Group´s capital requirements. Should appropriate additional financing not be available or should anticipated cash flows from production in the Hawler license area vary from expectations, the Group has the flexibility to further adjust its capital expenditure plans accordingly.

Regulatory Filings

This announcement coincides with the filing with the Canadian securities regulatory authorities of Oryx Petroleum's unaudited condensed consolidated interim financial statements for the three and six months ended June 30, 2014 and the related management's discussion and analysis thereon.  Copies of these documents filed by Oryx Petroleum may be obtained under Oryx Petroleum´s profile at www.sedar.com, and on the Group's website, www.oryxpetroleum.com

ABOUT ORYX PETROLEUM GROUP LIMITED

Oryx Petroleum is an international oil exploration and production company focused in Africa and the Middle East. The Group's shares are listed on the Toronto Stock Exchange under the symbol "OXC". The Oryx Petroleum group of companies was founded in 2010 by The Addax and Oryx Group Limited and key members of the former senior management team of Addax Petroleum Group. Oryx Petroleum has interests in six license areas, two of which have yielded oil discoveries and four of which are prospective for oil. The Group is the operator or technical partner in four of the six license areas. Two license areas are located in the Kurdistan Region and the Wasit governorate (province) of Iraq and four license areas are located in West Africa in Nigeria, the AGC administrative area offshore Senegal and Guinea Bissau, and Congo (Brazzaville). Further information about Oryx Petroleum is available at www.oryxpetroleum.com or under Oryx Petroleum's profile at www.sedar.com.

Reader Advisory Regarding Forward-Looking Information

Certain statements in this news release constitute "forward-looking information", including statements related to the Group's reserves and resources estimates and potential, drilling plans, development plans and schedules and chance of success, results of exploration activities, future drilling of new wells, ultimate recoverability of current and long-term assets, possible commerciality of our projects, future expenditures, and statements that contain words such as "may", "will", "could", "should", "anticipate", "believe", "intend", "expect", "plan", "estimate", "potentially", "project", 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.

Although Oryx Petroleum believes these statements to be reasonable, the assumptions upon which they are based may prove to be incorrect. For more information about these assumptions and risks facing the Group, refer  to the Group`s annual information form dated March 12, 2014 available at www.sedar.com and the Group`s website at www.oryxpetroleum.com. Further, statements including forward-looking information in this news release 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, future events or otherwise.  If the Group 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 news release is expressly qualified by this cautionary statement.

Reserves and 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.

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. There is no certainty that any portion of the prospective resources will be discovered. The risked prospective oil resources reported in this news release 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, risk exploration contract or fiscal regime applicable to each license area. Reference to 100% indicates that the applicable reserves or resources are volumes attributed to the discovery or prospect as a whole and do not represent Oryx Petroleum´s working interest in such reserves or resources.

Reader Advisory Regarding Production Figures

Unless provided otherwise, all production and capacity figures and volumes cited in this news release are gross (100%) values, indicating that figures (i) have not been adjusted for deductions specified in the production sharing contract applicable to the Hawler license area, and (ii) are attributed to the license area as a whole and do not represent Oryx Petroleum's working interest in such production, capacity or volumes.



SOURCE Oryx Petroleum Corporation Limited


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