Oryx Petroleum Announces its Year End 2018 Reserves and Resources

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Feb 13, 2019, 09:00 ET

Proved Plus Probable Oil Reserves of 127 million barrels and US$ 814 million⁽¹⁾ in Related After-Tax Net Present Value of Future Net Revenue as at December 31, 2018

CALGARY, Feb. 13, 2019 /CNW/ - Oryx Petroleum Corporation Limited ("Oryx Petroleum" or the "Corporation") today announced its oil reserves and resources as at December 31, 2018 as evaluated by Netherland, Sewell & Associates, Inc. ("NSAI"), an independent oil and gas consulting firm, and as set forth in a report dated February 8, 2019 prepared in accordance with National Instrument 51-101 by NSAI (the "2018 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 2018 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, 2018, as compared to the equivalent estimates prepared by NSAI as at December 31, 2017 (the "2017 NSAI Report"), include:

Proved plus probable oil reserves increase 4% to 127 million barrels ("MMbbl") versus 122 MMbbl as at December 31, 2017:

Increase of volumes due to successful drilling in the Banan Tertiary reservoir in 2018 leading to the reclassification of related volumes from contingent oil resources
Decrease of volumes attributable to the Zey Gawra Cretaceous reservoir based on logging results from wells drilled at Zey Gawra in 2018 and well performance data
Reclassification of volumes attributable to the Demir Dagh Jurassic reservoir as contingent resources due to absence of plans to appraise or develop the reservoir

After-tax net present value of future net revenue related to proved plus probable oil reserves increases 16% to US$ 814 million⁽¹⁾ versus US$ 704 million⁽²⁾ as at December 31, 2017:

Increase is the result of higher forecast production volumes and significantly lower estimated per barrel development costs, partially offset by a more gradual increase in production and lower export oil prices

Best estimate (2C) unrisked contingent oil resources attributable to the Hawler license area of 168 MMbbl as at December 31, 2018 versus 148 MMbbl as at December 31, 2017:

Reclassification of volumes attributable to the Demir Dagh Jurassic reservoir from reserves to contingent resources, partially offset by reclassification of volumes attributable to the Banan Tertiary reservoir from contingent resources to reserves

Best estimate unrisked prospective oil resources of 2,263 MMbbl as at December 31, 2018 versus 3,750 MMbbl as at December 31, 2017

Refined estimates for the AGC Central license area based on further interpretation of seismic data and remapping of prospects completed in 2018

¹	These estimated values are calculated using a 10% discount rate and are valid as at December 31, 2018. Estimated value of future net revenue does not represent fair market value. See the Material Change Report for additional information regarding these estimated values.
²	These estimated values are calculated using a 10% discount rate and are valid as at December 31, 2017.

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 2018 as evaluated by NSAI. We are particularly pleased to report increases to both proved plus probable oil reserves and associated after-tax net present value of future net revenue. The 4% increase in proved plus probable reserves is primarily the result of successful appraisal activities in the Banan field in the Hawler license area which has resulted in the booking of reserves attributable to the Banan Tertiary reservoir. The after-tax net present value of future net revenue related to proved plus probable oil reserves increased by 16% due to the modest increase in proved plus probable reserves and, more importantly, substantially lower estimated capital expenditures. Based on our experience drilling horizontal wells in 2018, future wells are expected to cost significantly less than previously estimated. Also, the unit development cost of the new reserves attributable to the Banan Tertiary reservoir is much lower than the cost of the reserves lost to downward revisions and reclassification. The cost of facilities is also less than previously estimated.

The remapping of prospects based on interpretation of 3D seismic data completed in 2018 has resulted in a refinement and a downward revision to estimated prospective oil resources attributable to the AGC Central license area. The adjustment in no way diminishes our belief in the significant potential of the AGC Central license.

We are planning an active drilling program in 2019 in the Hawler license area that we expect will both increase production and allow us to better assess fields and reservoirs where we currently have contingent or prospective resources but no reserves. With prospects ranked and identified in the AGC Central exploration license area in West Africa, we plan to complete an environmental impact assessment and prepare for exploration drilling in 2020."

Summary Reserves and Resources

The following is a summary of NSAI's evaluation as at December 31, 2018 with comparatives to NSAI's evaluation as at December 31, 2017:

Oil Reserves and Resources and Future Net Revenue Summary Tables

December 31, 2017

December 31, 2018

2017 NSAI Report

2018 NSAI Report

Proved Plus Probable

Gross⁽⁷⁾ Oil (Working Interest)

Reserves

Future Net Revenue⁽⁶⁾

Reserves

Future Net Revenue⁽⁶⁾

Oil Reserves⁽¹⁾

(MMbbl)

(US$ million)

(MMbbl)

(US$ million)

Kurdistan Region of Iraq – Hawler

Demir Dagh

Cretaceous

Jurassic

Zey Gawra

Cretaceous

Banan East

Cretaceous

Banan West

Tertiary

Cretaceous

Total⁽⁸⁾

122

704

127

814

December 31, 2017

December 31, 2018

Best Estimate (2C) Gross⁽⁷⁾ Oil
(Working Interest)

Unrisked

Risked⁽⁹⁾

Unrisked

Risked⁽⁹⁾

Resources

Future Net Revenue⁽⁶⁾

Resources

Future Net Revenue⁽⁶⁾

Contingent Oil Resources⁽²⁾

– Development Pending⁽³⁾

(MMbbl)

(US$ million)

(MMbbl)

(US$ million)

Kurdistan Region of Iraq – Hawler

Demir Dagh

Cretaceous

Banan East

Cretaceous

Zey Gawra

Tertiary

Total⁽⁸⁾

106


	December 31, 2017		December 31, 2018
	Best Estimate Gross⁽⁷⁾ Oil (Working Interest)		Best Estimate Gross⁽⁷⁾ Oil (Working Interest)
Contingent Oil Resources⁽²⁾ – Development Unclarified ⁽⁴⁾	Unrisked	Risked⁽⁹⁾	Unrisked	Risked⁽⁹⁾
	(MMbbl)		(MMbbl)
Kurdistan Region of Iraq – Hawler
Demir Dagh
Tertiary	6	3	6	4
Jurassic	42	31	80	60
*Banan East*
Jurassic	1	1	1	1
Banan West
Tertiary	17	9	-	-
Ain Al Safra
Jurassic	28	21	28	21
Total⁽⁸⁾	94	65	115	86

Prospective Oil Resources⁽⁵⁾	Unrisked	Risked⁽¹⁰⁾	Unrisked	Risked⁽¹⁰⁾
Iraq	(MMbbl)		(MMbbl)
Kurdistan Region of Iraq – Hawler	105	4	105	4
West Africa
AGC Central	3,450	392	2,159	204
Haute Mer B⁽¹¹⁾	195	2	-	-
Total⁽⁸⁾	3,750	398	2,263	208

(1)	The oil reserves data is based upon evaluations by NSAI, with effective dates as at December 31, 2017 and December 31, 2018, as indicated. Volumes are based on commercially recoverable volumes within the life of the production sharing contract.
(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 effective dates as at December 31, 2017 and December 31, 2018, 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.
(3)	Classification of a project's maturity as Development Pending indicates that there is a high chance of development (i.e., probability that a known accumulation will be commercially developed), where resolution of the final conditions for development is being actively pursued.
(4)	Classification of a project's maturity as Development Unclarified indicates that evaluation of the project is incomplete and there is ongoing activity to resolve any risks or uncertainties regarding commercial development of the project. An economic evaluation has not been performed by NSAI on the contingent oil resources classified as Development Unclarified.
(5)	The prospective oil resources data is based upon evaluations by NSAI, and the classification of such resources as "prospective oil resources" by NSAI, with effective dates as at December 31, 2017 and December 31, 2018, 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 a discovery is made and development is undertaken, the probability that the recoverable volumes will equal or exceed the unrisked estimated amount is 50% for the best estimate. Prospective oil resources estimates are volumetric estimates prior to economic calculations.
(6)	After-tax net present value of related future net revenue using forecast prices and costs assumed by NSAI and a 10% discount rate as at December 31, 2017 and December 31, 2018, as indicated. Gross proved plus probable oil reserves estimates and estimates of best estimate (2C) gross contingent oil resources sub-classified as development pending used to calculate future net revenue are estimated based on economically recoverable volumes within the development period specified in the production sharing contract applicable to the Hawler license area. The estimated values disclosed do not represent fair market value.
(7)	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.
(8)	Individual numbers provided may not add to total due to rounding.
(9)	These are risked contingent resources that have been risked for chance of development.
(10)	These are risked prospective resources that have been risked for both chance of discovery and chance of development. If a discovery is made, there is no certainty that it will be developed or, if it is developed, there is no certainty as to the timing of such development.
(11)	On April 23, 2018, a subsidiary of Oryx Petroleum entered into an agreement providing for the transfer of the Corporation's 30% participating interest in the Haute Mer B license to a subsidiary of Total S.A. The transaction has not yet closed and is subject to arbitration proceedings. Oryx Petroleum's intent is to divest its interest and volume estimates attributable to the Corporation's interest in the Haute Mer B license have not been updated or included in the 2018 NSAI Report.

The following is a discussion of reserves and resources as at December 31, 2017 and December 31, 2018 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, 2018 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 54 MMbbl as at December 31, 2018 versus 56 MMbbl as at December 31, 2017. The modest downward revision reflects the impact of reducing the number of development wells, production in 2018, and a revised production profile with some previously estimated volumes no longer commercially recoverable during the life of the production sharing contract.

Best estimate (2C) unrisked gross (working interest) contingent oil resources attributable to the Demir Dagh Cretaceous reservoir are 16 MMbbl as at December 31, 2018 unchanged as at December 31, 2017. NSAI assigns a 75% chance of development for the Cretaceous reservoir contingent oil resources at the Demir Dagh field, versus a 90% chance of development in the 2017 NSAI Report, resulting in a risked estimate of 12 MMbbl. The decrease reflects the more contingent nature of the development plan for the reservoir. These resources are classified by NSAI as "development pending".

Estimated proved plus probable gross (working interest) oil reserves attributable to the Demir Dagh Lower Jurassic Mus and Adaiyah reservoir are nil as at December 31, 2018 versus 3 MMbbl as at December 31, 2017. The downward revision reflects the reclassification of reserves to contingent resources as Oryx Petroleum currently has no plans to further develop the Demir Dagh Jurassic reservoir.

Estimated contingent oil resources volumes attributable to the Lower Jurassic Mus and Adaiyah reservoirs have increased to 38 million barrels versus nil at December 31, 2017 due to their reclassification from reserves to contingent resources and the shift from an economic evaluation accounting for concessions to a volumetric analysis. 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. 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, 2017 as no new data has been collected from such reservoirs in 2018.

NSAI assigns a 75% chance of development for the Lower Jurassic Mus and Adaiyah reservoirs, the Lower Jurassic Butmah reservoir, and the Lower Jurassic Naokelekan and Sargelu reservoirs at the Demir Dagh field. NSAI assigns a 75% chance of development for the Tertiary Pila Spi reservoir, versus a 50% chance of development in the 2017 NSAI Report reflecting the successful appraisal drilling of the Tertiary reservoir at the Banan field. 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 14 MMbbl as at December 31, 2018 versus 22 MMbbl as at December 31, 2017. 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 and the Zey Gawra-2, Zey Gawra-3 and Zey Gawra-4 wells completed in 2018.

The decrease in reserves is based primarily on an interpretation of available data that indicates that the reservoir is more compartmentalised than the interpretation at 2017 year end. The compartmentalisation has resulted in a lower estimate of original oil in place and recoverable reserves. The development plan has also been adjusted to reflect lower maximum production rates and lower estimated ultimate recovery per well 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, 2018 unchanged versus December 31, 2017. NSAI assigns a 75% chance of development for the Tertiary reservoir contingent oil resources at the Zey Gawra field unchanged versus the 2017 NSAI Report resulting in a risked estimate of 6 MMbbl. These resources are classified by NSAI as "development pending".

Banan (East and West)

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-2 ("BAN-2") appraisal well later in 2014;
logging and production data from the BAN-2 well that was completed in 2018;
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.

The interpretation of data accumulated to date is that the Banan field is two fields (Banan East and Banan West) 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 22 MMbbl as at December 31, 2018 versus 23 MMbbl as at December 31, 2017. The modest downward revision reflects the impact of a reduced number of development wells, production in 2018, and a revised production profile with some previously estimated volumes no longer commercially recoverable during the life of the production sharing contract.

Estimated proved plus probable gross (working interest) oil reserves attributable to the Banan West Cretaceous reservoir are 19 MMbbl as at December 31, 2018 versus 19 MMbbl as at December 31, 2017.

Best estimate (2C) unrisked gross (working interest) contingent oil resources attributable to the Banan East Cretaceous reservoir are 31 MMbbl as at December 31, 2018 unchanged versus December 31, 2017. NSAI assigns a 75% chance of development for such contingent oil resources estimated for the Banan East Cretaceous reservoir, versus a 90% chance of development in the 2017 NSAI Report. The decrease reflects the more contingent development plan for the reservoir. These resources are classified by NSAI as "development pending".

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

data collected during the drilling of the BAN-2 appraisal well in 2014; and
data collected during drilling, logging and production from the Banan-3 and Banan-4 appraisal wells successfully completed in 2018.

Estimated proved plus probable gross (working interest) oil reserves attributable to the Banan West Tertiary Pila Spi reservoir are 17 MMbbl as at December 31, 2018 versus nil MMbbl as at December 31, 2017. The increase is due to the reclassification of volumes from contingent oil resources as a result of the successful drilling of the Banan-3 and Banan-4 appraisal wells in 2018.

Estimated contingent oil resource volumes attributable to the Banan East Lower Jurassic Butmah reservoirs are unchanged as at December 31, 2018 versus December 31, 2017. NSAI assigns a 75% chance of development for the Banan East Lower Jurassic Butmah, unchanged versus the 2017 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, 2018 versus December 31, 2017. 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 2017 NSAI Report. These resources are classified by NSAI as "development unclarified".

Prospective Resources

Estimated prospective oil resources attributable to the Hawler license area as at December 31, 2018 were 105 MMbbl (risked: 4 MMbbl) unchanged compared to December 31, 2017. The prospects comprising such value are risked for geologic chance of success and chance of development, which factors are unchanged versus the 2017 NSAI Report.

West Africa

Oryx Petroleum has interests in two license areas in West Africa as at December 31, 2018:

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 30% working interest in the Haute Mer B license area offshore Congo (Brazzaville).

On April 23, 2018, a subsidiary of Oryx Petroleum entered into an agreement providing for the transfer of the Corporation's 30% participating interest in the Haute Mer B license to a subsidiary of Total S.A. Notwithstanding the Corporation's position that all conditions to closing have been either satisfied or waived, the counter-party refuses to close the transaction and has purported to terminate the agreement. Oryx Petroleum has initiated arbitration to settle the dispute and believes strongly in the merits of its position. Notwithstanding, the arbitration panel may decide against the Corporation. Oryx Petroleum's intent is to divest its interest irrespective of the arbitration outcome and volume estimates attributable to the Corporation's interest in the Haute Mer B license have not been updated or included in the 2018 NSAI Report.

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, 2018. Approximately 2,000 km²of 3D seismic data was acquired in late 2016 and early 2017. The data was processed during 2017 and interpretation and prospect ranking largely completed in 2018. Based on data available at December 31, 2018, which permitted a more precise understanding of the license area, prospects in the AGC Central license area were remapped. As a result of the remapping, 23 prospective intervals have been identified with total best estimate unrisked gross (working interest) prospective oil resources of 2,159 MMbbl (risked: 204 MMbbl) as at December 31, 2018 versus 3,450 MMbbl (risked: 392 MMbbl) as at December 31, 2017.

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, 2017 and 2018 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 2028 and 2029, respectively.

All volumes included in the after-tax net present values of future net revenue estimated in the 2017 NSAI Report and the 2018 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 2017 NSAI Report and the 2018 NSAI Report based on a pipeline export price. Assumed pipeline export prices in the 2017 NSAI Report and the 2018 NSAI Report are determined in accordance with agreements in place with the Ministry of Natural Resources of the Kurdistan Region of Iraq at the time of each report. Assumed pipeline export prices in the 2018 NSAI Report equal the Brent crude oil price less a $7.88 per barrel export tariff plus the addition or deduction of a quality differential to the extent crude qualities differ from Brent crude oil specifications. Assumed pipeline export prices in the 2017 NSAI Report equal the Brent crude oil price less a $12.00 per barrel export tariff plus the addition or deduction of a quality differential to the extent crude qualities differed from agreed specifications.

Export tariffs in both the 2017 NSAI Report and the 2018 NSAI Report are treated as non-recoverable. The quality differentials for API gravity and sulphur content in the 2017 NSAI Report and the 2018 NSAI Report are based on actual and, where appropriate, forecast oil quality specifications 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.


	Assumed Brent Crude Oil Price (US$/bbl) as at December 31,		Assumed Export Oil Price (US$/bbl) at December 31,
Period Ending December 31,	2017	2018	2017⁽¹⁾	2018⁽¹⁾

2018	62.00	-	50.17	-
2019	63.93	64.25	53.17	49.24
2020	66.13	68.47	55.08	53.17
2021	70.37	71.32	58.43	56.26
2022	73.22	73.37	60.86	58.25
2023	75.18	75.21	62.51	59.31
2024	77.19	76.99	64.25	60.70
2025	79.21	78.86	66.03	62.09
2026	81.08	80.83	67.74	63.65
2027	82.66	82.42	68.94	65.02
2028	84.29	84.06	69.99	66.59
2029	85.98	85.70	71.67	68.18

(1)

All export sales are assumed to be pipeline export sales. Export prices in the 2018 NSAI Report equal Brent crude oil price less a US$7.88/bbl export tariff plus/minus any quality differential versus Brent crude oil specifications. Export prices in the 2017 NSAI Report equal Brent crude oil price less a US$12.00/bbl export tariff plus/minus any quality differential versus agreed crude oil specifications.

Operating costs assumed in the 2017 NSAI Report and the 2018 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 2017 NSAI Report and the 2018 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, 2018, utilizing a 10% discount rate, is US$ 814 million versus US$ 704 million as at December 31, 2017. The increase reflects:

Higher oil reserves volumes resulting primarily from the reclassification and upward revision of volumes attributable to the Banan Tertiary reservoir to proved plus probable reserves from contingent resources. The increase was partially offset by downward revisions to estimates for the Zey Gawra Cretaceous reservoir and the reclassification of volumes attributable to the Demir Dagh Jurassic reservoir to contingent resources from proved plus probable reserves;
Lower per barrel development costs than assumed in the 2017 NSAI Report resulting from lower estimated drilling costs, particularly for horizonal wells targeting the Demir Dagh and Banan Cretaceous reservoirs, revised estimates of facility costs, and the replacement of volumes attributable to the Zey Gawra Cretaceous and Demir Dagh Jurassic reservoirs with volumes attributable to the Banan Tertiary reservoir. Wells required to develop the Banan Tertiary reservoir are less expensive and more productive than those required to develop the Zey Gawra Cretaceous and Demir Dagh Jurassic reservoirs.

These positive factors were partially offset by:

an assumed production profile more weighted to later years than the assumed production profile assumed in the 2017 NSAI Report due to a more phased investment approach;
Lower assumed export oil prices due primarily to a new pricing regime agreed with the Ministry of Natural Resources of the Kurdistan Region of Iraq during 2018 that results in a higher combined export tariff and quality adjustment to Brent crude oil prices versus the tariffs and quality adjustments under the pricing regime in place during 2017. Overall crude production in 2018 NSAI Report has a lower average API gravity and higher sulphur content than the crude production in the 2017 NSAI Report resulting in a negative adjustment to the quality differential; and
Higher estimated operating costs based on costs incurred during 2018.

Best Estimate (2C) Contingent Oil Resources

The 2018 NSAI Report and the 2017 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$ 60 million as at December 31, 2018 versus US$ 106 million as at December 31, 2017. The decrease in the estimate reflects lower risked volumes due to a reduced chance of development assumed for the Demir Dagh and Banan Cretaceous reservoirs, revised timing of production due to a more phased investment approach that defers some production to later years and lower assumed export prices. These negative factors were partially offset by lower development costs.

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 three license areas, one of which has yielded an oil discovery. The Corporation is the operator in two of the three license areas. One license area is located in the Kurdistan Region of Iraq and two 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 to divest the Haute Mer B license area, plans to commence exploration drilling in the AGC Central license area in 2020, forecasts of Brent crude oil prices, and possible commerciality of our projects. 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, 2018 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, 2018. The Corporation will file an annual information form for the year ended December 31, 2018 on or before March 31, 2019.

SOURCE Oryx Petroleum Corporation Limited

about Oryx Petroleum, please contact: Scott Lewis, Head of Corporate Finance and Planning, Tel.: +41 (0) 58 702 93 52, [email protected]

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