Mr. Vance Querio reports
ORYX PETROLEUM ANNOUNCES ITS YEAR END 2017 RESERVES AND RESOURCES
Oryx Petroleum Corp. Ltd. has released its oil reserves and resources as at Dec. 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 Feb. 9, 2018, prepared in accordance with National Instrument 51-101 by NSAI. The reserves and resources disclosure coincides with the filing on SEDAR of a 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 as well as future net revenue related to oil reserves and contingent oil resources subclassified as development pending in the Hawler licence area as at Dec. 31, 2017, as compared with the equivalent estimates prepared by NSAI as at Dec. 31, 2016, include:
-
Proved plus probable oil reserves of 122 million barrels versus 202 million barrels as at Dec. 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 $704-million
(U.S.) (1) versus $1-billion
(U.S.) (2) as at Dec. 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 licence area of 148 million barrels as at Dec. 31, 2017, versus 140 million barrels as at Dec. 31, 2016:
-
Best-estimate (2C) risked contingent oil resources subclassified as development pending of 47 million barrels as at Dec. 31, 2017, versus 42 million barrels as at Dec. 31, 2016;
-
After-tax risked net present value of future net revenue of $106-million
(U.S.) (1) as at Dec. 31, 2017, versus $71-million
(U.S.) (2) as at Dec. 31, 2016;
-
Best-estimate unrisked prospective oil resources of 3.75 billion barrels as at Dec. 31, 2017, versus 853 million barrels as at Dec. 31, 2016:
-
Upward revision of estimates for the AGC Central licence area.
(1) These estimated values are calculated using a 10-per-cent discount rate and are valid as at Dec. 31, 2017. 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-per-cent discount rate and are valid as at Dec. 31, 2016.
Chief executive officer's comment
Commenting, 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 3-D seismic data acquired and processed in 2017 has resulted in a more-than-tenfold increase in prospective oil resources attributable to the AGC Central licence area. We look forward to an active drilling program in 2018 in the Hawler licence area that should allow a more fulsome assessment of the potential of that licence area and to further calibrate the significant potential of the AGC Central exploration licence area in West Africa as we prepare for exploration drilling in 2019."
Summary reserves and resources
The attached tables are a summary of NSAI's evaluation as at Dec. 31, 2017, with comparatives with NSAI's evaluation as at Dec. 31, 2016.
OIL RESERVES AND RESOURCES AND FUTURE NET REVENUE SUMMARY TABLES
Dec. 31, 2016 Dec. 31, 2017
2016 NSAI report 2017 NSAI report
Proved plus probable Proved plus probable
Oil reserves (1) Gross (7) oil Future net Gross (7) oil Future net
(working interest) revenue (6) (working interest) revenue (6)
reserves (mmbbl) (US$ millions) reserves (mmbbl) (US$ millions)
Kurdistan region
of Iraq -- Hawler
Demir Dagh
Cretaceous 65 56
Jurassic 5 3
Zey Gawra
Cretaceous 76 22
Banan East
Cretaceous 31 23
Banan West
Cretaceous 25 19
Total (8) 202 1,014 122 704
Dec. 31, 2016
Best-estimate (2C) gross (7) oil
(working interest)
Contingent oil Unrisked Risked (9) Future net
resources (2) -- resources resources revenue (6)
development pending (mmbbl) (mmbbl) (US$ millions)
Kurdistan region
of Iraq -- Hawler
Demir Dagh
Cretaceous 16 14
Banan East
Cretaceous 31 28
Zey Gawra
Tertiary - -
Total (8) 46 42 71
Dec. 31, 2017
Best-estimate (2C) gross (7) oil
(working interest)
Contingent oil Unrisked Risked (9) Future net
resources (2) -- resources resources revenue (6)
development pending (mmbbl) (mmbbl) (US$ millions)
Kurdistan region
of Iraq -- Hawler
Demir Dagh
Cretaceous 16 14
Banan East
Cretaceous 31 28
Zey Gawra
Tertiary 7 6
Total (8) 54 47 106
Dec. 31, 2016 Dec. 31, 2017
Best-estimate Best-estimate
gross (7) oil gross (7) oil
(working interest) (working interest)
Contingent oil resources (2) Unrisked Risked (9) Unrisked Risked (9)
development unclarified (4) (mmbbl) (mmbbl) (mmbbl) (mmbbl)
Kurdistan region
of Iraq -- Hawler
Demir Dagh
Tertiary 6 3 6 3
Jurassic 42 31 42 31
Banan East
Jurassic 1 1 1 1
Banan West
Tertiary 17 9 17 9
Ain Al Safra
Jurassic 28 21 28 21
West Africa
Congo (Brazzaville)
-- Haute Mer A
Elephant 6 1 - -
Total (8) 100 66 94 65
Prospective oil resources (5) Unrisked Risked (10) Unrisked Risked (10)
(mmbbl) (mmbbl) (mmbbl) (mmbbl)
Iraq
Kurdistan region -- Hawler 111 5 105 4
West Africa
AGC Central 294 9 3,450 392
Haute Mer B 195 2 195 2
OML 141, Haute Mer A, 364 7 - -
AGC Shallow (11)
Total (8) 853 23 3,750 398
(1) The oil reserves data are based upon evaluations by NSAI, with effective dates
as at Dec. 31, 2016, and Dec. 31, 2017, as indicated. Volumes are based on
commercially recoverable volumes within the life of the production-sharing contract.
(2) The contingent oil resources data are based upon evaluations by NSAI, and the
classification of such resources as contingent oil resources by NSAI, with effective
dates as at Dec. 31, 2016, and Dec. 31, 2017, 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 per cent 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 (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 continuing 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 are based upon evaluations by NSAI, and the
classification of such resources as prospective oil resources by NSAI, with
effective dates as at Dec. 31, 2016, and Dec. 31, 2017, 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 per cent 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-per-cent discount rate as at Dec. 31, 2016, and
Dec. 31, 2017, as indicated. Gross proved plus probable oil reserves estimates and
gross development pending best-estimate (2C) contingent oil resource estimates used
to calculate future net revenue are estimated based on economically recoverable
volumes within the development/exploitation period specified in the production-sharing
contract, risk exploration contract or fiscal regime applicable to each licence 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 licence 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) The corporation's interest in the OML141 licence area was divested in 2017 and
its interest in the AGC Shallow licence area was relinquished in 2017. During 2017,
the corporation determined to cease all further investments in the Haute Mer A
licence area. It is anticipated that the corporation's interest in the
Haute Mer A licence area will be assigned to the other partners in the
licence area in the near future.
The following is a discussion of estimated volumes as at Dec. 31, 2016, and Dec. 31, 2017, for each of the corporation's licence areas.
Kurdistan region of Iraq -- Hawler licence area
Reserves and contingent resources
Demir Dagh
Estimated volumes at the Demir Dagh field in the Hawler licence area reflect data available as at Dec. 31, 2017, including:
-
Drilling, testing and postdrill analysis of 10 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 (for example, production and pressure monitoring and interference testing) of six wells that have produced or are producing from the Cretaceous or Jurassic reservoirs;
-
Three-dimensional (3-D) 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 million barrels as at Dec. 31, 2017, versus 65 million barrels as at Dec. 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 million barrels as at Dec. 31, 2017, unchanged versus Dec. 31, 2016. NSAI assigns a 90-per-cent 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 million barrels. 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 three million barrels as at Dec. 31, 2017, versus five million barrels as at Dec. 31, 2016. Estimates are based on the drilling results and postdrilling 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 Dec. 31, 2016, as no new data have been collected from such reservoirs in 2017.
NSAI assigns a 75-per-cent 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-per-cent 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 million barrels as at Dec. 31, 2017, versus 76 million barrels as at Dec. 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 compartmentalization 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 seven million barrels as at Dec. 31, 2017, versus nil as at Dec. 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-per-cent chance of development for the Tertiary reservoir contingent oil resources at the Zey Gawra field, resulting in a risked estimate of six million barrels. 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 3-D 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;
- 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 million barrels as at Dec. 31, 2017, versus 31 million barrels as at Dec. 31, 2016. Estimated proved plus probable gross (working interest) oil reserves attributable to the Banan West Cretaceous reservoir are 19 million barrels as at Dec. 31, 2017, versus 25 million barrels as at Dec. 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 million barrels as at Dec. 31, 2017, unchanged versus Dec. 31, 2016. NSAI assigns a 90-per-cent 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 Dec. 31, 2017, versus Dec. 31, 2016. NSAI assigns a 50-per-cent chance of development for the Banan West Tertiary Pila Spi reservoir and a 75-per-cent chance of development for the Banan East Lower Jurassic Butmah reservoir, 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 Dec. 31, 2017, versus Dec. 31, 2016. Estimates are based on the drilling and testing and postdrilling 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-per-cent 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 licence area as at Dec. 31, 2017, were 105 million barrels compared with 111 million barrels as at Dec. 31, 2016. The revision reflects the reclassification of estimated prospective resources attributable to the Zey Gawra Tertiary reservoir at Dec. 31, 2016, as contingent resources as at Dec. 31, 2017. Best-estimate risked gross (working interest) prospective oil resources as at Dec. 31, 2017, were four million barrels. 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 licence areas in West Africa as at Dec. 31, 2017:
- An 80-per-cent working interest in the AGC Central licence area (assuming the AGC exercises its back-in rights) in the AGC administrative area offshore Senegal and Guinea Bissau;
-
A 20-per-cent working interest in the Haute Mer A licence area and a 30-per-cent working interest in the Haute Mer B licence area in each case offshore Congo (Brazzaville).
During 2017, the corporation divested its 38.67-per-cent working interest in the OML 141 licence area in Nigeria and relinquished its 80-per-cent working interest in the AGC Shallow licence 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 licence area. It is anticipated that the corporation's interests in the Haute Mer A licence area will be assigned to the other partners in the licence area in the near future. The corporation has also commenced efforts to divest its interests in the Haute Mer B licence area.
The corporation's activity in West Africa in 2017 was focused on the processing and interpretation of 3-D seismic data covering the AGC Central licence 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 licence areas in West Africa (excluding the Haute Mer A licence area) was 3,645 million barrels at Dec. 31, 2017, versus 742 million barrels at Dec. 31, 2016.
Estimated prospective oil resources attributable to the AGC Central licence area as well as related risking for geologic success and chance of development were adjusted at Dec. 31, 2017, versus Dec. 31, 2016. Approximately 2,000 square kilometres of 3-D seismic data were acquired in late 2016 and early 2017. The data were processed during 2017 with interpretation in advanced stages at Dec. 31, 2017. Based on data available at Dec. 31, 2017, prospects and leads in the AGC Central licence 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 million barrels (risked: 392 million barrels) as at Dec. 31, 2017, versus 294 million barrels (risked: nine million barrels) as at Dec. 31, 2016.
There were no changes to estimated prospective oil resources in the Haute Mer B licence area as at Dec. 31, 2017, versus Dec. 31, 2016. There were also no changes to risking for geologic chance of success or chance of development in the Haute Mer B licence area. The corporation is seeking to divest its interests in the Haute Mer B licence area.
After-tax net present values
Realized price and cost assumptions
The after-tax net present values of future net revenue estimated by NSAI as at Dec. 31, 2016, and Dec. 31, 2017, utilize Brent crude oil prices shown herein, which are based on the average of forecasts of Brent crude oil prepared by three Canadian independent consultants. Such prices are escalated at 2 per cent on Jan. 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 licence 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 $12-per-barrel agreed export tariff plus the addition or deduction of a quality differential to the extent crude qualities differ from agreed specifications.
Export tariffs in both the 2016 NSAI report and the 2017 NSAI report are treated as non-recoverable. The quality differentials for API gravity and sulphur content in the 2016 NSAI report and the 2017 NSAI report are based on Demir Dagh and Zey Gawra Cretaceous reservoir oil quality specifications and anticipated quality specifications from the Demir Dagh Jurassic and Banan Cretaceous reservoirs at the time of the reports. The quality differentials assumed in each forecasted year are weighted averages, reflecting the relative blend contributions assumed for each reservoir.
Assumed Brent crude Assumed export oil
oil price (US$/bbl) price (US$/bbl)
Period ending as at Dec. 31, at Dec. 31,
Dec. 31, 2016 2017 2016 (1) 2017 (1)
2017 $56.67 $ - $46.39 $ -
2018 62.57 62 52.43 50.17
2019 67.13 63.93 56.1 53.17
2020 71.17 66.13 59.14 55.08
2021 75.24 70.37 63.61 58.43
2022 77,23 73.22 65.99 60.86
2023 79.22 75.18 67.87 62.51
2024 81.26 77.19 69.7 64.25
2025 83.34 79.21 71.55 66.03
2026 85.65 81.08 73.63 67.74
2027 87.32 82.66 75.12 68.94
2028 89.07 84.29 76.68 69.99
(1) All export sales are assumed to be pipeline export sales.
Export prices equal Brent crude oil price less a
$12-(U.S.)-per-barrel pipeline tariff plus or minus any
quality differential versus specifications agreed.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 cent per year on Jan. 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 cent 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 Dec. 31, 2017, utilizing a 10-per-cent discount rate, is $704-million (U.S.) versus $1-billion (U.S.) as at Dec. 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;
-
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 subclass, such resources attributable to the Demir Dagh and Banan Cretaceous reservoirs and the Zey Gawra Tertiary reservoir located in the Hawler licence 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 subclass, utilizing a 10-per-cent discount rate, is $106-million (U.S.) as at Dec. 31, 2017, versus $71-million (U.S.) as at Dec. 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 Corp. Ltd.
Oryx Petroleum is an international oil exploration, development and production company focused in Africa and the Middle East. Oryx Petroleum has interests in four licence areas, two of which have yielded oil discoveries. The corporation is the operator in two of the four licence areas. One licence area is located in the Kurdistan region of Iraq and three licence areas are located in West Africa in the AGC administrative area offshore Senegal and Guinea Bissau and in Congo (Brazzaville).
We seek Safe Harbor.
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