Proved Plus Probable Oil Reserves of 122 million barrels and US$ 704 million^([1]) in Related After-Tax Net Present Value of Future Net Revenue as at December 31, 2017; Best estimate unrisked Prospective Oil Resources of 3,450 million barrels in the AGC Central license area

CALGARY, Feb. 15, 2018 /CNW/ - Oryx Petroleum Corporation Limited ("Oryx Petroleum" or the "Corporation") today announced its oil reserves and resources as at December 31, 2017 as evaluated by Netherland, Sewell & Associates, Inc. ("NSAI"), an independent oil and gas consulting firm, and as set forth in a report dated February 9, 2018 prepared in accordance with National Instrument 51-101 by NSAI (the "2017 NSAI Report"). The reserves and resources disclosure coincides with the filing on SEDAR at www.sedar.com of a material change report (the "Material Change Report"), which includes additional information derived from the 2017 NSAI Report.

Highlights of the report for Oryx Petroleum's gross (working interest) oil reserves and resources volumes, and future net revenue related to oil reserves and contingent oil resources sub-classified as development pending in the Hawler license area as at December 31, 2017, as compared to the equivalent estimates prepared by NSAI as at December 31, 2016 (the "2016 NSAI Report"), include:

• Proved plus probable oil reserves of 122 million barrels ("MMbbl") versus 202 MMbbl as at December 31, 2016:
• Significant decrease of volumes attributable to the Zey Gawra Cretaceous reservoir based on logging results and performance data of the Zab-1 sidetrack well drilled in 2017
• Decrease of volumes attributable to the Demir Dagh and Banan Cretaceous reservoirs based on performance data from existing Demir Dagh Cretaceous wells

• After-tax net present value of future net revenue related to proved plus probable oil reserves of US$ 704 million⁽¹⁾ versus US$ 1.0 billion⁽²⁾ as at December 31, 2016:
• Lower volumes, forecasted Brent crude oil prices and assumed export oil prices partially offset by impact of production sharing contract mechanics

• Best estimate (2C) unrisked contingent oil resources attributable to the Hawler license area of 148 MMbbl as at December 31, 2017 versus 140 MMbbl as at December 31, 2016:
• Best estimate (2C) risked contingent oil resources sub-classified as development pending of 47 MMbbl as at December 31, 2017 versus 42 MMbbl as at December 31, 2016
• After-tax risked net present value of future net revenue of US$ 106 million⁽¹⁾ as at December 31, 2017 versus US$ 71 million⁽²⁾ as at December 31, 2016

• Best estimate unrisked prospective oil resources of 3,750 MMbbl as at December 31, 2017 versus 853 MMbbl as at December 31, 2016
• Upward revision of estimates for the AGC Central license area

CEO's Comment

Commenting today, Oryx Petroleum's Chief Executive Officer, Vance Querio, stated: 

"We are pleased to report our reserves and resources at year end 2017 as evaluated by NSAI. Our proved plus probable oil reserves estimates and associated after-tax net present value of future net revenue have been impacted by a modestly lower long term oil price outlook, a significant downward revision of reserve volumes attributable to the Zey Gawra Cretaceous reservoir, and downward revisions to reserve volumes attributable to the Demir Dagh and Banan Cretaceous, and the Demir Dagh Jurassic, reservoirs. More positively, the remapping of prospects based on initial interpretation of 3D seismic data acquired and processed in 2017 has resulted in a more than tenfold increase in prospective oil resources attributable to the AGC Central license area. We look forward to an active drilling program in 2018 in the Hawler license area that should allow a more fulsome assessment of the potential of that license area and to further calibrate the significant potential of the AGC Central exploration license area in West Africa as we prepare for exploration drilling in 2019."

Summary Reserves and Resources

The following is a summary of NSAI's evaluation as at December 31, 2017 with comparatives to NSAI's evaluation as at December 31, 2016:

Oil Reserves and Resources and Future Net Revenue Summary Tables

The following is a discussion of estimated volumes as at December 31, 2016 and December 31, 2017 for each of the Corporation's license areas.

Kurdistan Region of Iraq - Hawler License Area

Reserves and Contingent Resources

Demir Dagh

Estimated volumes at the Demir Dagh field in the Hawler license area reflect data available as at December 31, 2017 including:

• Drilling, testing and post drill analysis of ten wells (Demir Dagh-2 through Demir Dagh-11), eight of which were drilled to the Cretaceous reservoir and two of which tested multiple zones;
  
  
• Observation of well performance and recording of dynamic data (e.g., production and pressure monitoring, interference testing) of six wells that have produced or are producing from the Cretaceous or Jurassic reservoirs; and
  
  
• Three dimensional (3D) and three component (3C) seismic data.

Estimates of oil reserves attributable to the Demir Dagh Cretaceous reservoir are based on evaluation of the performance data from existing Demir Dagh producing wells but recognize that the development plan will comprise horizontal wellbores rather than vertical wellbores drilled to date. The horizontal wells in the Demir Dagh Cretaceous reservoir will be placed at strategic positions to minimize water production and take advantage of regional water movement.

Estimated proved plus probable gross (working interest) oil reserves attributable to the Demir Dagh Cretaceous reservoir are 56 MMbbl as at December 31, 2017 versus 65 MMbbl as at December 31, 2016. The downward revision reflects revised assumed maximum daily production rates and lower estimated ultimate recovery per well. These revisions were based on production rates and other performance data from wells producing from the Demir Dagh Cretaceous reservoir in 2017.

Best estimate (2C) unrisked gross (working interest) contingent oil resources attributable to the Demir Dagh Cretaceous reservoir are 16 MMbbl as at December 31, 2017 unchanged versus December 31, 2016. NSAI assigns a 90% chance of development for the Cretaceous reservoir contingent oil resources at the Demir Dagh field, unchanged versus the 2016 NSAI Report, resulting in a risked estimate of 14 MMbbl. These resources are classified by NSAI as "development pending".

Estimated proved plus probable gross (working interest) oil reserves attributable to the Lower Jurassic Mus and Adaiyah reservoir are 3 MMbbl as at December 31, 2017 versus 5 MMbbl as at December 31, 2016. Estimates are based on the drilling results and post drilling analysis of the Demir Dagh-2 and Demir Dagh-3 wells that tested the Jurassic intervals and the well performance data of the Demir Dagh-3 well. The Demir Dagh-3 well was completed in the Jurassic reservoir in early 2016 and ceased production in late 2016 due to an abrupt increase in the water-oil ratio. The downward revision reflects the removal of an assumed workover of the Demir Dagh-3 well based on further analysis of the well's performance data conducted in 2017.

Estimated contingent oil resources volumes in the Lower Jurassic Butmah reservoir, the Lower Jurassic Naokelekan and Sargelu reservoirs, and the Tertiary Pila Spi reservoir remain unchanged versus December 31, 2016 as no new data has been collected from such reservoirs in 2017.

NSAI assigns a 75% chance of development for both the Lower Jurassic Butmah and the Lower Jurassic Naokelekan and Sargelu reservoirs at the Demir Dagh field and a 50% chance of development for the Tertiary Pila Spi reservoir, unchanged versus the 2016 NSAI Report. These resources are classified by NSAI as "development unclarified".

Zey Gawra

Best estimate proved plus probable oil reserves attributable to the Zey Gawra Cretaceous reservoir decreased to 22 MMbbl as at December 31, 2017 versus 76 MMbbl as at December 31, 2016.  Estimates are based on available logging data from the ZAB-1 well drilled in the 1990s and re-entered  in 2003 and 2016, drilling, logging and testing data from the Zey Gawra-1 discovery well drilled in 2013, testing and production data from the Zey Gawra-1 sidetrack well successfully completed in late 2016, and logging results and production data from the ZAB-1 sidetrack well completed in 2017.

The decrease in reserves is based primarily on the logging results and production data from the ZAB-1 sidetrack well. Interpretations of such data indicate a deeper natural gas-oil contact and a more shallow free water level than observed at the Zey Gawra-1 well. Volumes have been estimated assuming that there is compartmentalisation in the reservoir and thus different free water levels in different parts of the reservoir. The development plan has been adjusted to reflect a need for fewer wells and the maximum production rates and estimated ultimate recovery per well have been reduced based on production history.

Best estimate (2C) unrisked gross (working interest) contingent oil resources attributable to the Zey Gawra Tertiary reservoir are 7 MMbbl as at December 31, 2017 versus nil as at December 31, 2016. These contingent resources have been revised and reclassified from prospective resources based on data obtained during the drilling and logging of the ZAB-1 sidetrack well. NSAI assigns a 75% chance of development for the Tertiary reservoir contingent oil resources at the Zey Gawra field resulting in a risked estimate of 6 MMbbl. These resources are classified by NSAI as "development pending".

Banan

Estimated volumes attributable to the Banan Cretaceous reservoir were based on:

• data collected during the drilling and testing of the Banan-1 ("BAN-1") exploration well in early 2014 and during the drilling of the Banan ("BAN-2") appraisal well later in 2014;
  
  
• acquisition and initial processing of 3D seismic data covering the portion of the Banan structure east of the Zab river;
  
  
• drilling results, well performance and data accumulated from the Cretaceous reservoir at the Demir Dagh field; and
  
  
• recognition that the development plan will consist of horizontal wellbores rather than vertical wellbores drilled to date.

The interpretation of data accumulated to date is that the Banan field is likely two fields separated by a north-south fault, roughly along the line of the Zab river.

Estimated proved plus probable gross (working interest) oil reserves attributable to the Banan East Cretaceous reservoir are 23 MMbbl as at December 31, 2017 versus 31 MMbbl as at December 31, 2016. Estimated proved plus probable gross (working interest) oil reserves attributable to the Banan West Cretaceous reservoir are 19 MMbbl as at December 31, 2017 versus 25 MMbbl as at December 31, 2016. The downward revisions, like the revision to proved and probable reserves attributable to the Demir Dagh Cretaceous reservoir, reflect revised assumed maximum daily production rates and lower estimated ultimate recovery per well.

Best estimate (2C) unrisked gross (working interest) contingent oil resources attributable to the Banan East Cretaceous reservoir are 31 MMbbl as at December 31, 2017 unchanged versus December 31, 2016. NSAI assigns a 90% chance of development for such contingent oil resources estimated for the Banan East Cretaceous reservoir, unchanged versus the 2016 NSAI Report. These resources are classified by NSAI as "development pending".

Estimated contingent oil resources volumes in the Banan West Tertiary Pila Spi and Banan East Lower Jurassic Butmah reservoirs are unchanged as at December 31, 2017 versus December 31, 2016.  NSAI assigns a 50% chance of development for the Banan West Tertiary Pila Spi and a 75% chance of development for the Banan East Lower Jurassic Butmah, unchanged versus the 2016 NSAI Report. These resources are classified by NSAI as "development unclarified".

Ain Al Safra

Estimated unrisked and risked contingent oil resources attributable to the Ain Al Safra field, specifically the Lower Jurassic Alan, Mus and Adaiyah reservoirs, were unchanged at December 31, 2017 versus December 31, 2016. Estimates are based on the drilling and testing and post drilling analysis of the Ain Al Safra-1 well drilled in 2013 and additional reservoir data accumulated during the drilling of the Ain Al Safra-2 appraisal well in 2014.  

NSAI assigns a 75% chance of development for the Lower Jurassic Alan, Mus and Adaiyah reservoirs, unchanged versus the 2016 NSAI Report. These resources are classified by NSAI as "development unclarified".

Prospective Resources

Hawler

Estimated prospective oil resources attributable to the Hawler license area as at December 31, 2017 were 105 MMbbl compared to 111 MMbbl as at December 31, 2016. The revision reflects the reclassification of estimated prospective resources attributable to the Zey Gawra Tertiary reservoir at December 31, 2016 as contingent resources as at December 31, 2017.  Best estimate risked gross (working interest) prospective oil resources as at December 31, 2017 were 4 MMbbl. The prospects comprising such value are risked for geologic chance of success and chance of development which factors are unchanged versus the 2016 NSAI Report.

West Africa

Oryx Petroleum has interests in three license areas in West Africa as at December 31, 2017:

• 80% working interest in the AGC Central license area (assuming the AGC exercises its back-in rights) in the AGC administrative area offshore Senegal and Guinea Bissau; and
  
  
• a 20% working interest in the Haute Mer A license area and a 30% working interest in the Haute Mer B license area in each case offshore Congo (Brazzaville).

During 2017 the Corporation divested its 38.67% working interest in the OML 141 license area in Nigeria and relinquished its 80% working interest in the AGC Shallow license area in the AGC administrative area offshore Senegal and Guinea Bissau. During 2017, the Corporation also determined to cease all further investments in the Haute Mer A license area. It is anticipated that the Corporation's interests in the Haute Mer A license area will be assigned to the other partners in the license area in the near future. The Corporation has also commenced efforts to divest its interests in the Haute Mer B license area.

The Corporation's activity in West Africa in 2017 was focused on the processing and interpretation of 3D seismic data covering the AGC Central license area that was acquired in late 2016 and early 2017. Final interpretation is expected to be completed in the coming months.

Best estimate unrisked gross (working interest) prospective oil resources attributable to the Corporation's interests in license areas in West Africa (excluding the Haute Mer A license area) was 3,645 MMbbl at December 31, 2017 versus 742 MMbbl at December 31, 2016.

Estimated prospective oil resources attributable to the AGC Central license area as well as related risking for geologic success and chance of development were adjusted at December 31, 2017 versus December 31, 2016. Approximately 2,000 km² of 3D seismic data was acquired in late 2016 and early 2017. The data was processed during 2017 with interpretation in advanced stages at December 31, 2017. Based on data available at December 31, 2017, prospects and leads in the AGC Central license area were remapped. As a result of the remapping, 11 prospects have been identified with total best estimate unrisked gross (working interest) prospective oil resources of 3,450 MMbbl (risked: 392 MMbbl) as at December 31, 2017 versus 294 MMbbl (risked: 9 MMbbl) as at December 31, 2016.

There were no changes to estimated prospective oil resources in the Haute Mer B license area as at December 31, 2017 versus December 31, 2016. There were also no changes to risking for geologic chance of success or chance of development in the Haute Mer B license area.  The Corporation is seeking to divest its interests in the Haute Mer B license area.

After-Tax Net Present Values

Realised Price and Cost Assumptions

The after-tax net present values of future net revenue estimated by NSAI as at December 31, 2016 and 2017 utilize Brent crude oil prices shown below which are based on the average of forecasts of Brent crude oil prepared by three Canadian independent consultants. Such prices are escalated at 2% on January 1 of each year after 2027 and 2028, respectively.

All volumes included in the after-tax net present values of future net revenue estimated in the 2016 NSAI Report and the 2017 NSAI Report are attributable to Oryx Petroleum's interests in the Hawler license area in the Kurdistan Region of Iraq.

All sales are assumed to be export sales in the 2016 NSAI Report and the 2017 NSAI Report based on a pipeline export price. Assumed pipeline export prices in the 2016 NSAI Report and the 2017 NSAI Report are determined in accordance with an agreement reached with the Ministry of Natural Resources of the Kurdistan Region of Iraq in early 2016. Assumed pipeline export prices equal the Brent crude oil price less the $12 per barrel agreed export tariff plus the addition or deduction of a quality differential to the extent crude qualities differ from agreed specifications.

Export tariffs in both the 2016 NSAI Report and the 2017 NSAI Report are treated as non-recoverable. The quality differentials for API gravity and sulphur content in the 2016 NSAI Report and the 2017 NSAI Report are based on Demir Dagh and Zey Gawra Cretaceous reservoir oil quality specifications and anticipated quality specifications from the Demir Dagh Jurassic and Banan Cretaceous reservoirs at the time of the reports. The quality differentials assumed in each forecasted year are weighted averages reflecting the relative blend contributions assumed for each reservoir.

Operating costs assumed in the 2016 NSAI Report and the 2017 NSAI Report are based on information from in-country operator expense records provided to NSAI by Oryx Petroleum and commercially available databases at the time of preparation of each report. Operating costs are escalated 2% per year on January 1 of each year through the lives of the applicable properties.

Capital costs assumed in the 2016 NSAI Report and the 2017 NSAI Report were provided to NSAI by Oryx Petroleum and are based on authorizations for expenditures, field development plans, actual costs from recent activity, and commercially available cost databases available at the time of preparation of each report. Capital costs are escalated 2% per year to the date of expenditure.

Proved Plus Probable Oil Reserves

The after-tax net present value of future net revenue attributable to the Corporation's gross (working interest) proved plus probable oil reserves as at December 31, 2017, utilizing a 10% discount rate, is US$ 704 million versus US$ 1.0 billion as at December 31, 2016. The decrease reflects:

• Lower assumed export oil prices due to lower Brent crude oil prices. Overall crude production in 2017 NSAI Report also has a lower average API gravity than the crude production in the 2016 NSAI Report resulting in a negative adjustment to the quality differential;
  
  
• Lower oil reserves volumes resulting from downward revisions to estimates for the Demir Dagh, Banan and Zey Gawra Cretaceous reservoirs and the Demir Dagh Jurassic reservoir;
  
  
• Higher per barrel operating costs than assumed in the 2016 NSAI Report. Costs are significantly lower in absolute terms but the percentage decline in operating costs is lower than percentage decline in volumes; and
  
  
• Higher per barrel development costs than assumed in the 2016 NSAI Report. Costs are lower in absolute terms due to the reduced number of wells required to develop the Zey Gawra Cretaceous reservoir but the percentage decline in development costs is lower than the percentage decline in volumes.

These negative factors were partially offset by:

• Higher Contractor share of gross revenues due to the impact of production sharing contract mechanisms.

Best Estimate (2C) Contingent Oil Resources

The 2017 NSAI Report and the 2016 NSAI Report contain only estimated after-tax risked net present values of future net revenue attributable to contingent oil resources classified in the "development pending" project maturity sub-class, such resources attributable to the Demir Dagh and Banan Cretaceous reservoirs and the Zey Gawra Tertiary reservoir located in the Hawler license area. The estimated after-tax risked net present values of the future net revenue attributable to best estimate (2C) risked contingent oil resources in the "development pending" project maturity sub-class, utilising a 10% discount rate, is US$ 106 million as at December 31, 2017 versus US$ 71 million as at December 31, 2016. The increase in the estimate reflects the modestly higher volumes from reclassification of volumes attributable to the Zey Gawra Tertiary reservoir, lower per unit costs and the higher share of gross revenue due to the impact of production sharing contract mechanisms partially offset by lower forecasted Brent crude oil prices and lower assumed export prices.

ABOUT ORYX PETROLEUM CORPORATION LIMITED

Oryx Petroleum is an international oil exploration, development and production company focused in Africa and the Middle East. The Corporation'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 P.L.C. Oryx Petroleum has interests in four license areas, two of which have yielded oil discoveries. The Corporation is the operator in two of the four license areas. One license area is located in the Kurdistan Region of Iraq and three license areas are located in West Africa in 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 reserves and resources estimates and potential, future net revenue, drilling plans (including use of horizontal wellbores in the development of certain reservoirs), development plans and schedules and chance of success, future drilling of wells and the reservoirs to be targeted, costs and drilling times for wells, ultimate recoverability of current and long-term assets, plans for interpretation of 3D seismic data from the AGC Central license area, management plans and expectations for the Haute Mer A license area, plans to divest the Haute Mer B license area, plans to commence exploration drilling in the AGC Central license area in 2019, forecasts of Brent crude oil prices, possible commerciality of our projects, 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 Corporation, refer to the Corporation's Annual Information Form dated March 23, 2017 available at www.sedar.com and the Corporation'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 Corporation 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. Each of the reserve categories may be divided into developed and undeveloped. The proved reserves disclosed in this news release have been classified as developed producing, developed non-producing and undeveloped.

Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirement of the reserves category (proved, probable, possible) to which they are assigned.

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. 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 oil 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 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 license, field or reservoir (as applicable) as a whole and do not represent Oryx Petroleum's working interest in such volumes.

For details regarding the risk factors affecting the Corporation and the assumptions relied upon by the Corporation, refer to the Corporation's Annual Information Form dated March 23, 2017. The Corporation will file an annual information form for the year ended December 31, 2017 on or before March 31, 2018.

SOURCE Oryx Petroleum Corporation Limited