ShaMaran Petroleum Corp. — Audit Report / Information 2020

Feb 15, 2021

Form 51-101 F1

ShaMaran Petroleum Corp.

Statement of Reserves Data

And Other Oil and Gas Information

As of December 31, 2020

Table of Contents

Part 1	Date of Statement	Date of Statement	2
Item	1.1	Relevant Dates	2
Part 2	Disclosure of Reserves Data		2
Item	2.1	Reserves Data (Forecast Prices and Costs)	3
Part 3	Pricing Assumptions		7
Item	3.1	Supplemental Estimates	7
Item	3.2	Forecast Prices Used in Estimates	7
Part 4	Reconciliations of Changes in Reserves		8
Item	4.1	Reserves Reconciliation	8
Part 5	Additional Information Relating to Reserves Data		9
Item	5.1	Undeveloped Reserves	9
Item	5.2	Significant Factors or Uncertainties	10
Item	5.3	Future Development Costs	11
Part 6	Other Oil and Gas Information		12
Item	6.1	Oil and Gas Properties and Wells	12
Item	6.2	Properties With No Attributed Reserves	15
Item	6.3	Forward Contracts	15
Item	6.4	Additional Information Concerning Abandonment and Reclamation Costs	15
Item	6.5	Tax Horizon	15
Item	6.6	Costs Incurred	15
Item	6.7	Exploration and Development Activities	16
Item	6.8	Production Estimates	17
Item	6.9	Production History	17
Appendix
Summary of Contingent Resources			18

1

Part 1 Date of Statement

Item 1.1 Relevant Dates

1. Date of Statement: February 11, 2021 2. Effective Date: December 31, 2020 3. Preparation Date: February 11, 2021

Part 2 Disclosure of Reserves Data

ShaMaran Petroleum Corp., herein after referred to as “ShaMaran” or the “Company”, has as of December 31, 2019 reserves relating entirely to the Company’s interest in the Atrush Block, its sole oil and gas property, located in the Kurdistan Region of Iraq (“Kurdistan”). ShaMaran currently has a 27.6 percent working interest in the Block and is continuing to fund expenditure on that basis. For stating the Company’s oil and gas reserves publicly, the Company retained the services of McDaniel & Associates Consultants Ltd. (“McDaniel”), who are independent qualified reserves evaluators appointed by the Company pursuant to NI 51-101, to conduct independent evaluations of all the Company’s oil and gas properties. McDaniel has provided the Company with an evaluation (the “McDaniel Report”) prepared in compliance with NI 51-101 in respect of the Company’s oil and gas reserves as at December 31, 2020.

The definitions of the various categories of reserves are those set out in NI 51-101 and in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”). The Company engaged McDaniel to provide an evaluation of the Company's proved, probable and possible reserves. The following are the definitions of proved, probable and possible reserves as set out in the COGE Handbook:

" proved reserves " are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. At least a 90% probability that the quantities actually recovered will equal or exceed the estimated proved reserves is the targeted level of certainty.

" probable reserves " are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. At least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves is the targeted level of certainty.

" possible reserves " are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. At least a 10% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable plus possible reserves is the targeted level of certainty.

It should not be assumed that the present worth of estimated future net revenue represents the fair market value of the reserves. There is no assurance that the forecast price and cost assumptions contained in the McDaniel Report will be attained and variances could be material. The reserves and revenue estimates set forth below are estimates only and the actual reserves and realized revenue may be greater or less than those calculated.

Unless otherwise stated herein all currency amounts indicated as “$” in this Statement of Reserves Data are expressed in thousands of United States dollars (“USD”).

2

Item 2.1 Reserves Data (Forecast Prices and Costs)

Breakdown of Reserves (Forecast Case)

The following table discloses, in the aggregate, the Company's gross and net proved, probable and possible reserves, estimated using forecast prices and costs, by product type.

SUMMARY OF OIL AND GAS RESERVES AS OF DECEMBER 31, 2020 (Forecast Prices & Costs)

Iraq Proved developed producing ........ Proved developed non–producing Proved undeveloped ..................... Total proved reserves .................. Probable ........................................ Total Proved Plus Probable Reserves .................................. Possible ......................................... Total Proved Plus Probable Plus Possible Reserves .................... Total Proved developed producing ........ Proved developed non–producing Proved undeveloped ..................... Total proved reserves .................. Probable ........................................ Total Proved Plus Probable Reserves .................................. Possible ......................................... Total Proved Plus Probable Plus Possible Reserves ....................	ShaMaran's Interest in Reserves(1)(2)(3)
	Light and Medium Oil (Mbbl) Heavy Oil (Mbbl) Conventional Natural Gas (MMcf) Natural Gas Liquids (Mbbl) Gross(4) Net(5) Gross(4) Net(5) Gross(4) Net(5) Gross(4) Net(5)
	9,254 5,089 1,823 1,003 – – – – - - - - – – – – 4,929 2,654 957 515 – – – – 14,184 7,743 2,780 1,518 – – – – 9,982 5,341 3,382 1,819 – – – – 24,165 13,084 6,162 3,337 – – – – 10,142 4,819 3,253 1,577 – – – – 34,307 17,904 9,416 4,914 – – – – 9,254 5,089 1,823 1,003 – – – – - - - - – – – – 4,929 2,654 957 515 – – – – 14,184 7,743 2,780 1,518 – – – – 9,982 5,341 3,382 1,819 – – – – 24,165 13,084 6,162 3,337 – – – – 10,142 4,819 3,253 1,577 – – – – 34,307 17,904 9,416 4,914 – – – –

Notes:

(1) Totals may not add due to rounding.

(2) The definitions of the various categories of reserves and expenditures are those set out in NI 51-101.

(3) The Atrush Field contains crude oil of variable density. Fluid type is classified according to COGEH: Light/Medium Oil is based on density less than 920 kg/m[3] and Heavy Oil is between 920 and 1000 kg/m[3] .

(4) “Gross” reserves refer to ShaMaran’s working interest share before deducting royalties and are based on a 27.6 percent working interest share of the property gross resources.

(5) “Net” reserves refer to ShaMaran’s share of total cost and profit revenues. Note, as the government pays income taxes on behalf of ShaMaran out of the government's profit oil share, the net reserves were based on the effective pre-tax profit revenues by adjusting for the tax rate.

3

Net Present Value of Future Net Revenue (Forecast Case)

The following table discloses, by country and in the aggregate, the net present value of the ShaMaran’s future net revenue attributable to the reserves categories in the previous table, estimated using forecast prices and costs, before and after deducting future income tax expenses, and calculated without discount and using discount rates of 5%, 10%, 15% and 20%.

SUMMARY OF NET PRESENT VALUE OF FUTURE NET REVENUE

AS OF DECEMBER 31, 2020

(Forecast Prices & Costs)

Reserves Category Iraq Proved developed producing . Proved developed non- producing ........................ Proved undeveloped ............ Total Proved Reserves ........ Probable ................................ Total Proved Plus Probable Reserves ........................ Possible ................................. Total Proved Plus Probable Plus Possible Reserves ... Total Proved developed producing Proved developed non- producing ........................ Proved undeveloped ............ Total Proved Reserves ........ Probable ................................ Total Proved Plus Probable Reserves ........................ Possible ................................. Total Proved Plus Probable Plus Possible Reserves ...	Net Present Values of Future Net Revenue(1)(2)(3)(4)(5)(6)(7) Unit Value(8) before Income Tax Discounted Before Income Taxes Discounted at(%/year) After Income Taxes Discounted at(%/year) at 0 5 10 15 20 0 5 10 15 20 10%/year $000 $000 $000 $000 $000 $000 $000 $000 $000 $000 $/bbl 79,269 73,941 69,222 65,031 61,296 79,269 73,941 69,222 65,031 61,296 11.36 - - - - - - - - - - - 35,199 30,231 26,055 22,557 19,624 35,199 30,231 26,055 22,557 19,624 8.22 114,468 104,172 95,278 87,588 80,920 114,468 104,172 95,278 87,588 80,920 10.29 177,060 139,000 111,688 91,602 76,503 177,060 139,000 111,688 91,602 76,503 15.60 291,528 243,171 206,965 179,190 157,422 291,528 243,171 206,965 179,190 157,422 12.60 140,064 105,989 83,239 67,461 56,144 140,064 105,989 83,239 67,461 56,144 13.01 431,592 349,160 290,204 246,651 213,567 431,592 349,160 290,204 246,651 213,567 12.72 79,269 73,941 69,222 65,031 61,296 79,269 73,941 69,222 65,031 61,296 11.36 - - - - - - - - - - - 35,199 30,231 26,055 22,557 19,624 35,199 30,231 26,055 22,557 19,624 8.22 114,468 104,172 95,278 87,588 80,920 114,468 104,172 95,278 87,588 80,920 10.29 177,060 139,000 111,688 91,602 76,503 177,060 139,000 111,688 91,602 76,503 15.60 291,528 243,171 206,965 179,190 157,422 291,528 243,171 206,965 179,190 157,422 12.60 140,064 105,989 83,239 67,461 56,144 140,064 105,989 83,239 67,461 56,144 13.01 431,592 349,160 290,204 246,651 213,567 431,592 349,160 290,204 246,651 213,567 12.72
	Before Income Taxes Discounted at(%/year)
	0 5 10 15 20
	$000 $000 $000 $000 $000 79,269 73,941 69,222 65,031 61,296 - - - - - 35,199 30,231 26,055 22,557 19,624 114,468 104,172 95,278 87,588 80,920 177,060 139,000 111,688 91,602 76,503 291,528 243,171 206,965 179,190 157,422 140,064 105,989 83,239 67,461 56,144 431,592 349,160 290,204 246,651 213,567 79,269 73,941 69,222 65,031 61,296 - - - - - 35,199 30,231 26,055 22,557 19,624 114,468 104,172 95,278 87,588 80,920 177,060 139,000 111,688 91,602 76,503 291,528 243,171 206,965 179,190 157,422 140,064 105,989 83,239 67,461 56,144 431,592 349,160 290,204 246,651 213,567

Notes:

(1) Based on a 27.6 percent Company working interest.

(2) Totals may not add due to rounding.

(3) The definitions of the various categories of reserves and expenditures are those set out in NI 51-101.

(4) Based on forecast prices and costs at January 1, 2021.

(5) Interest expenses and corporate overhead, etc. were not included.

(6) The net present values may not necessarily represent the fair market value of the reserves.

(7) Government pays income taxes on behalf of ShaMaran out of the government's profit oil share and as such the before and after tax values are identical.

(8) Unit values are calculated using estimated net present value of future net revenue before income taxes using a discount rate of 10% and the Company net reserves. Unit values are presented on a $/bbl basis for the light/medium and heavy oil reserves combined.

4

Total Future Net Revenue (Undiscounted)

Sub-Item 3b – Breakdown of Future Net Revenue

The following table discloses, by country and in the aggregate, certain elements of the Company's future net revenue attributable to proved reserves, proved plus probable reserves and proved plus probable plus possible reserves, estimated using forecast prices and costs, and calculated without discount.

						Future Net		Future Net
					Abandonment	Revenue		Revenue
					and	Before		after
			Operating	Development	Reclamation	Income	Income	Income
Reserves Category	Revenue(1)	Royalties(2)	Costs(3)	Costs	Costs	Taxes(4)	Taxes(5)	Taxes
	$000	$000	$000	$000	$000	$000	$000	$000
Iraq
Total Proved Reserves ..	369,776	-	189,204	49,333	16,770	114,468	-	114,468
Total Proved Plus
Probable Reserves ...	664,640	-	305,972	49,333	17,807	291,528	-	291,528
Total Proved Plus
Probable Plus	945,110	-	444,524	49,333	19,660	431,592	-	431,592
Possible Reserves .....
Total
Total Proved Reserves ..	369,776	-	189,204	49,333	16,770	114,468	-	114,468
Total Proved Plus Probable Reserves ...	664,640	-	305,972	49,333	17,807	291,528	-	291,528
Total Proved Plus
Probable Plus	945,110	-	444,524	49,333	19,660	431,592	-	431,592
Possible Reserves .....

Notes:

(1) Revenue comprises cost oil, profit oil revenue and carry repayment.

(2) Royalties are taken off before determining revenue and so are not included in this table.

(3) Operating costs included bonuses and capacity building value.

(4) Totals may not add or subtract due to rounding.

(5) Government pays income taxes on behalf of ShaMaran out of the government's profit oil share and so income taxes are excluded.

5

Sub-Item 3c – Total Future Net Revenue by Production Group

The following table discloses, by production group, the net present value and the unit value of the Company's future net revenue attributable to its proved reserves, its proved plus probable reserves and its proved plus probable plus possible reserves, before deducting future income tax expenses, estimated using forecast prices and costs, and calculated using a 10% discount rate.

10% discount rate.
Reserves Category	Production Group(1) Future Net Revenue before Income Taxes (Discounted at 10%/Year) Unit Value(2)
Proved Reserves............................................... Proved Plus Probable Reserves ........................ Proved Plus Probable Plus Possible Reserves ..	$000 ($/bbl) ($/Mcf) ($/boe) Light and Medium Crude Oil 79,663 10.29 Heavy Oil 15,615 10.29 Conventional Natural Gas – – Natural Gas Liquids – –
	Total 95,278 10.29 Light and Medium Crude Oil 164,912 12.60 Heavy Oil 42,053 12.60 Conventional Natural Gas – – Natural Gas Liquids – –
	Total 206,965 12.60 Light and Medium Crude Oil 227,710 12.72 Heavy Oil 62,494 12.72 Conventional Natural Gas – – Natural Gas Liquids – –
	Total 290,204 12.72

Notes:

(1) The Atrush Field contains crude oil of variable density even within a single reservoir unit and as such the actual split between Light/Medium Oil and Heavy Oil is uncertain. To give an indicative split of the “Future Net Revenue before Income Taxes by Production Group”, the ratio of the Light/Medium and Heavy Oil reserves has been applied in a simplistic manner to calculate the total future net revenue.

(2) Unit values are calculated using estimated net present value of future net revenue before income taxes using a discount rate of 10% and the Company net reserves. Unit values are presented on a $/bbl basis for crude oil reserves.

A Summary of Contingent Resources as at December 31, 2020 has been included in the Appendix at the end of this document.

6

Part 3 Pricing Assumptions

Item 3.1 Supplemental Estimates

Not relevant

Item 3.2 Forecast Prices Used in Estimates

The following table sets forth the benchmark reference prices as at December 31, 2020, provided by McDaniel which were McDaniel's then current forecast prices at the effective date of the McDaniel Report.

		Atrush field	Atrush field
Year	Brent Crude Oil	Price differential(2)	Sales Oil Price(2)
	Price(1)	(Atrush,Iraq)	(Atrush,Iraq)	Inflation Rates
	($/bbl)	($/bbl)	($/bbl)	(%/Year)
2020 achieved price sales price	41.99	15.72	26.27	N/A
2021 .....................................................................	49.50	15.78	33.72	2.00
2022 .....................................................................	53.55	15.78	37.77	2.00
2023 .....................................................................	54.62	15.78	38.84	2.00
2024 .....................................................................	55.71	15.78	39.93	2.00
2025 .....................................................................	56.83	15.78	41.05	2.00
2026 .....................................................................	57.96	15.78	42.18	2.00
2027 .....................................................................	59.12	15.78	43.34	2.00
2028 .....................................................................	60.31	15.78	44.53	2.00
2029 .....................................................................	61.51	15.78	45.73	2.00
Inflation after 2030 ..............................................				2.00

Notes:

(1) Brent price forecast based on the McDaniel January 1, 2021 price forecast.

(2) Atrush field price is adjusted for quality differential, transportation tariffs and marketing fees and is based on ShaMaran's current marketing agreement of $15.78/bbl.

7

Part 4 Reconciliations of Changes in Reserves

Item 4.1 Reserves Reconciliation

The following table provides a reconciliation of ShaMaran's gross reserves between December 31, 2019 to December 31, 2020 based on forecast prices and costs.

Iraq (and Total) Light and Medium Oil (Mbbl) Gross Proved Gross Probable Total Gross Proved plus Probable Gross Proved	Iraq (and Total) Light and Medium Oil (Mbbl) Gross Proved Gross Probable Total Gross Proved plus Probable Gross Proved	Heavy Oil (Mbbl) Conventional Natural Gas (MMcf) Gross Probable Total Gross Proved plus Probable Gross Proved Gross Probable Total Gross Proved plus Probable
Opening balance(1)(2) December 31,2019 13,750	14,614 28,364 687 895 1,582 - - -
Plus: Extensions 1,932 Improved recovery - Technical revisions 2.909 Discoveries - Acquisitions - Less: Dispositions - Economic factors - Production 4,407	- - - 1,795 3,726 379 572 950 - - - - - - - - - - - (6,427) (3,518) 1,865 1,915 3,780 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 4,407 150 - 150 - - -
Ending balance – December 31, 2020 14,184	9,982 24,165 2,780 3,382 6,162 - - -

Notes:

(1) Gross reserves are based on a 27.6 percent Company working interest.

(2) Reserves reconciliation for year ended December 31, 2020 was based on forecast prices and costs.

8

Part 5 Additional Information Relating to Reserves Data

Atrush reserves were first recognized in the year ended December 31, 2013. In addition to sufficient accumulated technical data supporting recoverability, the declaration of commerciality by the contractor group in November 2012 and the KRG approval of the initial Field Development Plan (“FDP”) in October 2013 formed an adequate commercial basis for initial reserves recognition. During 2014 and 2015 several well tests and re-tests were executed and established the wellconnected nature of the upper Jurassic reservoir in the Atrush field. These tests also demonstrated the producibility of the heavy oil in the lower part of the oil column. The combined effect of these results allowed a reclassification of a portion of the contingent resources into reserves. In November 2015 an update to the FDP was presented to the KRG. In the second quarter of 2017 installation and commissioning of the Atrush Production Facilities was completed. Production started on 3[rd] July 2017. In 2017 one new well Chiya Khere-7 (“CK-7”) was drilled and found the top of the reservoir 114m shallow to prognosis, which resulted in upwards shift of the mapped reservoirs and thus an increase in medium and a decrease in heavy oil in place.

Drilling, testing and completion of CK-7 was completed in early 2018. The Chiya Khere-10 (“CK-10”) production well and the Chiya Khere-9 (“CK-9”) water disposal wells were also drilled, tested and completed. CK-10 found the top of the reservoir 45m shallow to prognosis in a crestal part of the structure, whilst CK-9, targeting the aquifer for water disposal, encountered the top of the Barsarin formation about 55m low to prognosis.

During the testing phases of the CK-7 well, the lower Jurassic Mus reservoir produced oil of a gravity of 20.1 degree API at a depth shallower than anticipated. This resulted in an upwards shift of the medium to heavy oil transition in the Mus reservoir and thus in a readjustment of medium versus heavy oil in place in that reservoir.

Following positive well test results, the CK-7 and CK-10 wells were connected to the Production Facilities and came online during July 2018.

An extended well test was run on AT-3 during 2019 to evaluate the productivity and characteristics of the heavy (13 degrees API) oil within the Lower Sargelu and Naokelekan. This testing was inconclusive and a further testing is currently being planned.

Development plans for 2020 were put on hold due to the COVID-19 pandemic, however subsurface work continued to be matured to support resumption of field development activities in 2021 as the HSSE and oil price environment improve.

Crude oil reserves have been assigned as part of this evaluation to the development of the core medium-oil region. The remainder of the discovered, potentially recoverable volumes are classified as contingent resources.

9

Item 5.1 Undeveloped Reserves

The following tables set forth the proved undeveloped gross reserves and the probable undeveloped gross reserves, each by product type, attributed to ShaMaran's assets for the years ended December 31, 2016, December 31, 2017 and December 31, 2018 in the aggregate, and before that time based on forecast prices and costs. The reserves have been classified as undeveloped due to the significant facility expenditure required to get to first oil production.

SUMMARY OF COMPANY UNDEVELOPED RESERVES (Forecast Prices & Costs)

Proved Undeveloped	Light/Medium Oil	HeavyOil	Conventional Natural Gas
	First Attributed Booked	First Attributed Booked	First Attributed Booked
Prior to 2015 .......................................................... 2016 ....................................................................... 2017 ....................................................................... 2018 ....................................................................... 2019 ....................................................................... 2020 .......................................................................	(Mbbl) (Mbbl) – 4,653 – 4,653 2,607 3,026 576 3,402 3,323 4,058 1,932 4,929	(Mbbl) (Mbbl) – – – 2,287 – 282 – 484 – 414 379 957	(MMcf) (MMcf) – – – – – – – – – – – –
Probable Undeveloped	First Attributed Booked	First Attributed Booked	First Attributed Booked
Prior to 2015 ......................................................... 2016 ...................................................................... 2017 ...................................................................... 2018 ...................................................................... 2019 ...................................................................... 2020 ......................................................................	(Mbbl) (Mbbl) – 7,779 – 7,779 3,684 9,779 1,254 9,654 1,667 5,142 1,795 4,666	(Mbbl) (Mbbl) – – – 2,394 – 745 – 740 – 287 572 1,190	(MMcf) (MMcf) – – – – – – – – – – – –

Item 5.2 Significant Factors or Uncertainties

McDaniel conducted its independent reserves evaluation on ShaMaran's reserves as at December 31, 2020. The process of establishing reserves requires significant judgments and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change.

As circumstances change and additional data become available, reserves estimates also change. Estimates made are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, prices, economic conditions and governmental restrictions.

Although every reasonable effort is made to ensure that reserves estimates are accurate, reserves estimation is an inferential science. As a result, the subjective decisions, new geological or production information and a changing environment may impact these estimates. Revisions to reserves estimates can arise from changes in year-end oil and gas prices, and reservoir performance.

10

Item 5.3 Future Development Costs

The following table provides information regarding the development costs deducted in the estimation of future net revenue attributable to the ShaMaran's reserves.

FUTURE DEVELOPMENT COSTS (UNDISCOUNTED)[(1)(2) ]

		Proved Plus Probable	Proved Plus Probable Plus
	Proved Reserves	Reserves	Possible Reserves
	$ millions	$ millions	$ millions
Iraq (and Total)
2021 ..............................................................................	12.5	12.5	12.5
2022 ..............................................................................	10.4	10.4	10.4
2023 ..............................................................................	14.5	14.5	14.5
2024 ..............................................................................	7.9	7.9	7.9
2025 ..............................................................................	4.0	4.0	4.0
Thereafter .....................................................................	-	-	-
Total Future Development Costs.................................	49.3	49.3	49.3

Note:

(1) Future Development Costs shown are associated with booked reserves in the McDaniel Report and do not necessarily represent the Company's full exploration and development budget.

11

Part 6 Other Oil and Gas Information

Item 6.1 Oil and Gas Properties and Wells

- Summary of Producing and Non Producing Wells

Summary of Producing and Non-Producing Wells
	Light/Medium		Conventional
	Oil	HeavyOil	Natural Gas	Total
	(wells)	(wells)	(wells)
Iraq (and Total)
Gross Wells(1)
Producing(3)...................................................................	10.0	–	–	10.0
Non-producing(4)...........................................................	3.0	–	–	3.0
Total Gross Wells..........................................................	16.0	–	–	16.0
Net Wells(2)
Producing(3)...................................................................	2.8	–	–	2.8
Non-producing(4)...........................................................	0.8	–	–	0.8
Total Net Wells.............................................................	3.6	–	–	3.6

Notes:

• (1) “Gross Wells” represent the number of wells in which the Company has a working-interest.

• (2) “Net Wells” represent the number of wells obtained by aggregating the Company’s working-interests in each of its Gross Wells.

• (3) “Producing” includes wells presently producing and contributing revenue or wells presently producing that are expected to contribute revenue in the foreseeable future through the sale of presently produced oil.

• (4) “Non-Producing” includes wells that are presently non-producing or wells presently producing but are not expected to contribute revenue in the foreseeable future through the sale of presently produced oil.

The Company currently holds a 27.6% direct interest in the Atrush Block PSC. Details of the Atrush Block are provided below.

Atrush Block

Production Facility and Pipeline

The Atrush Field reached peak rates in excess of 50,000 bopd during 2019, predominately from the nine Upper Jurassic wells. The current Atrush processing capacity is 58,000 blpd with 40,000 blpd capacity at the permanently installed production facilities and 18,000 blpd at the Pad C Early Production Facility (“EPF”) which was expanded from 10,000 blpd in Q1.2021.

Development Wells

In 2014, three development wells were drilled:

• The AT-4 well was drilled up-dip towards the undrilled crest of the structure from the AT-1 drilling site. AT-4 was tested, producing a 27-28 degree API oil at a combined rate of 9,059 bopd from two of the intervals tested.

• The CK-5 was drilled from the Chamanke-A well pad with the bottom hole location in the Adaiyah formation approximately 870 metres west southwest of the surface location, penetrating a gross vertical oil column of approximately 540 metres.

• CK-8 was also drilled from the Chamanke-A well and encountered the reservoir higher than expected some 1.4 kilometres east southeast of the surface location.

In 2015, the CK-5 and CK-8 development wells were successfully tested and completed. The CK-5 well tested 3 separate intervals at a combined rate of 7,350 bopd. The CK-8 well tested 2 intervals at a combined rate of 8,400 bopd.

The completions for both the AT-4 and the AT-2 well were installed and successfully tested in the second and third quarters of 2016 respectively.

The CK-7 well was spudded in Q4 2017 and the reservoir section was encountered 114 metres shallower than prognosis. In March and April 2018 three intervals were successfully tested: the Mus formation tested 20.1 degree API oil at a rate of 0.8 Mbopd, with a final productivity of 13 stb/d/psi; the Alan formation tested 27.1 degree API oil at a rate of 0.9 Mbopd, with a final productivity of 6 stb/d/psi; and the main Lower Sargelu formation tested 26.4 degree API oil at 1.0 Mbopd at a drawdown of only 2 psi, yielding a final productivity of 446 stb/d/psi. No water was produced at the end of the test.

12

CK-7 is now completed over the Alan and Lower Sargelu formation with an electric submersible pump. During the final completion test the well produced 7,040 bopd at only 14 psi drawdown.

The CK-10 well was spudded on May 15, 2018 was drilled to a total depth of 1,985 metres, which was reached on time and within budget on June 16, 2018. The reservoir section was encountered some 60 metres shallow to prognosis. The well flow tested approximately 4.4 Mbopd at a low drawdown, yielding a final productivity index of 313 stb/d/psi. The well is now completed over the Lower Sargelu formation.

The Chiya Khere-9 (“CK-9”) water disposal well was spudded on 20[th] July 2018 and was drilled to a total depth of 3015 metres, which was reached on time and within budget on 18[th] October 2018. The well was injection tested between 7[th] and 20[th] November, achieving the targeted daily injection volume of 10,000bbl/d.

The 2019 development campaign entailed drilling CK-11, CK 12, CK-13 and CK-15. The CK-11 well targeted the upper and lower Sargelu which produced at 8,200 bopd with an estimated maximum reservoir rate of 8,550 bopd. The CK-12 well targeted the Mus formation; however, it initially tested with a lower than expected reservoir productivity index, and subsequently only reached initial rates of approximately 600bopd. A 2020 stimulation of the Mus formation is planned to increase the productivity in the CK-12 well. The CK-13 well targeted the Naokelekan and the upper Sargelu and produced at 5,500bopd with an estimated maximum reservoir rate of 8,160bopd. CK-15 targeted the upper and lower Sargelu and produced at rates of 5,000bopd with the potential to exceed 7,000bopd.

The 2020 drilling campaign was suspended in Q1.2020 due to the COVID-19 pandemic, expected to be re-started in 2021 to include:

• drilling and completion of two more upper Jurassic production wells targeting medium gravity oil

• drilling and completion of three new lower Jurassic Mus producers also in the medium gravity oil leg.

Location and Operational History

The Atrush Block is located approximately 85 kilometres northwest of Erbil, the capital of Kurdistan, and has a surface area of 269 square kilometres. Oil has been proven in Jurassic fractured carbonates in the Chiya Khere structure and is estimated to contain a low estimate of 1.5 billion barrels, a best estimate of 2.0 billion barrels and a high estimate of 2.6 billion barrels of discovered oil in place. The structure is expressed at surface by the Chiya Khere mountain which runs east-west for approximately 25 kilometres with an approximate width of 3.5 kilometres.

In the year 2008 GEP acquired 143 kilometres of 2D seismic data covering the Atrush Block. In April 2011 the Atrush structure was confirmed as an oil discovery by the Atrush-1 (“AT-1”) exploration well. This was followed by the AT-2 appraisal well in July 2012. 3D seismic covering the entire Atrush Block was acquired between July 2011 and August 2012 and a Declaration of Commerciality made on November 7, 2012. The eastern part of the field was successfully appraised in June 2013 by the Atrush-3 (“AT-3”) well.

The AT-2 appraisal well was drilled to a depth of 1,750 metres, below the base of Jurassic reservoir section, which was reached in July 2012. The Company announced on September 13, 2012 the results of the comprehensive AT-2 well testing program which confirmed through three separate DSTs the AT-1 Jurassic oil discovery. Individual test rates for the three Jurassic DSTs, constrained by surface testing equipment, were over 10,000 bopd (approximately 27.0 degree API) and confirmed the significant potential for production from the highly fractured Jurassic reservoir. An additional two DSTs conducted in two deeper Jurassic formations confirmed them to be oil bearing and productive, with test rates limited by the gas lift test method. GEP submitted in October 2012 to the Ministry of Natural Resources (“MNR”) of Kurdistan an AT-2 Discovery Report giving notice of the additional discovery formations in the lower part of the Jurassic.

On November 7, 2012 TAQA, GEP and MOKDV, collectively being the Contractor under the Atrush PSC at that time, submitted to the Atrush Block Management Committee a Declaration of Commercial Discovery (“DCD”) with effect from November 7, 2012 in accordance with the terms of the Atrush PSC. The DCD was submitted together with an Appraisal Report covering the Atrush field.

The AT-3 eastern area appraisal well was spudded on March 25, 2013 and the well was drilled to a measured depth of 1,806 metres which was reached on June 23, 2013. The well encountered an estimated oil column of 286 metres in the Jurassic reservoir and successfully extended the Atrush accumulation 6.5 kilometres further to the east, while proving producible oil 180 metres deeper than previous wells thereby reducing the uncertainty on the Oil Water Contact/Free Water Level. AT-3 was suspended pending the planned re-entry and successful retest in January 2015.

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In June 2013 an interference test was conducted between AT-1 and AT-2. The wells, which are 3.1 kilometres apart, confirmed excellent pressure communication and multi Darcy horizontal permeability through the fracture system in the Jurassic reservoir. This reservoir connectivity was further confirmed, as announced by the Company in February 2015, by pressure communication between the tested Chiya Khere-6 (“CK-6”) and AT-3 wells and the AT-2 well, over a distance of 6.5 kilometres, demonstrating that the eastern appraisal area is in pressure communication with the Phase 1 development area.

The Atrush Block Field Development Plan (“FDP”) was submitted for approval to the KRG on May 6, 2013, in accordance with the terms of the Atrush PSC within 180 days after the DCD made on November 7, 2012. The FDP was presented in detail to the MNR in June 2013. Phase 1 of the FDP was duly approved with an effective date October 1, 2013.

On October 7, 2013 the Company announced that Phase 1 of the FDP for the Atrush Block had been approved by the KRG. The initial 20-year Development Phase (as defined in the Atrush PSC) commenced on the October 1, 2013.

Following submission of the FDP the AT-1 discovery well was determined to be unsuitable for long-term production and was plugged and abandoned in October 2013.

In 2014 CK-6, an eastern area appraisal well, was drilled from the Chamanke-C well pad and reached the Jurassic reservoir approximately 139 metres structurally higher than the nearby AT-3 well, approximately 600 metres South-southeast of the surface location. Three well tests were conducted, showing excellent reservoir quality and demonstrating producible oil as deep as -460m AMSL, nearly 200m deeper than the equivalent interval that successfully tested the higher viscosity oil in the AT-2 well.

Also in 2015, the AT-3 eastern appraisal well was re-entered and tested at a maximum oil rate of 4,900 bopd comingled from two intervals.

The Atrush field facilities were completed and commissioned in the second quarter of 2017. Production started up on the 3[rd] of July, taking production from AT-2, AT-4, CK-5 and CK-8 and ramping up to an average production of 26.3 Mbopd of 25.1 degree API for the month of December 2017.

Production for the first two months of 2018 remained stable at an average daily production of 26.8 Mbopd and 24.0 Mbopd for the months of January and February respectively. In March 2018, production dropped to approximately 20.3 Mbopd due to a partial blockage of a Production Facility heat exchanger by sediments. In early April 2018 production was temporarily suspended to address the partial blockage of the heat exchanger. The sediments were successfully removed from the heat exchanger during this plant shut down.

Analysis of the removed sediments indicate high concentrations of salts lost to the formation during drilling operations. These materials were flowed back into the production facilities with the produced dry oil where they caused capacity restrictions. To target these materials, fresh water was introduced at the CK-5 wellhead from June 2018 onwards. The salt materials are now diluted into the fresh water, which is then separated and disposed of during normal processing operations.

During the third quarter of 2018, daily production was constrained by exceptionally high export pipeline downtime during the month of August (over 6 days) as well as salt fill in the Production Facilities stripper column. The stripper column fill became apparent once additional well capacity from the Chiya Khere-7 (“CK-7”) and Chiya Khere-10 (“CK-10”) wells enabled Production Facility rates to exceed 26.0 Mbopd. The stripper column was flushed during a two-day shutdown in late September which successfully removed all salt restrictions and enabled the high stabilized rates throughout the fourth quarter.

During the fourth quarter 2018, well rates were steadily increased to test and evaluate the limits of the Production Facility. By end November 2018 and through early December 2018, several days with daily rates over 30.0 Mbopd were recorded until the onset of failure of the CK-10 Electric Submersible Pump (ESP), which reduced the available well capacity and therefore daily production rates. The CK-10 well was brought back on production late January 2019 after a successful workover.

The AT-3 well was re-completed as a Heavy Oil production well during December 2018. An extended well test was run on AT-3 during 2019 to evaluate the productivity and characteristics of the heavy (13 degrees API) oil within the Lower Sargelu and Naokelekan. This testing was inconclusive and a further testing is currently being planned.

The 2019 development campaign entailed drilling CK-11, CK 12, CK-13 and CK-15. The CK-11 well targeted the upper and lower Sargelu which produced at 8,200 bopd. The CK-13 well targeted the Naokelekan and the upper Sargelu and produced at 5,500bopd. CK-15 targeted the upper and lower Sargelu and produced at rates of 5,000bopd. The CK-12 well targeted the Mus formation; however, it initially tested with a lower than expected reservoir productivity index, and subsequently

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only reached initial rates of approximately 600bopd. An intervention planned for Q1.2021 will aim to perforate the Naokelekan/Upper Sargelu and increase CK-12 offtake rates to a target rate of 4,000 bopd.

Item 6.2 Properties With No Attributed Reserves

The Company held no properties through the year ended December 31, 2020 which have no attributed reserves.

Item 6.3 Forward Contracts

The Company has not entered into any forward contracts.

Item 6.4 Additional Information Concerning Abandonment and Reclamation Costs

Properties Kurdistan Region of Iraq (including wells and production facilities)	Abandonment and Reclamation Costs	Abandonment and Reclamation Costs
	Undiscounted $000 17,807	Discounted @ 10% $000 9,340

The table above shows the Company’s 27.6% participating interests at December 31, 2020 in the estimated well and facilities abandonment and reclamation costs (not including any “credits” for equipment salvage). Abandonment and reclamation costs have been estimated using industry practice and are in line with estimates provided in the Atrush Field Development Plan.

Future net revenue as prepared by McDaniel and as disclosed in item 2.1, is based on McDaniel’s estimate of well abandonment timing and cost, excluding facilities and site reclamation costs. According to the Atrush Production Sharing Contract, all abandonment and site reclamation costs are cost recoverable. Should there not be sufficient cost recovery to cover abandonment and site reclamation costs, which is likely to be the case at end of field life when final abandonment occurs, the Government will pay any remaining balance. Therefore final facilities abandonment and site reclamation costs do not impact the Company’s future net revenue.

Item 6.5 Tax Horizon

The Company has no foreseeable material tax liabilities associated with its oil and gas operations.

Item 6.6 Costs Incurred

The costs included in the following represent the Company’s share of the total costs incurred.

Properties in Kurdistan Atrush Block TOTAL		Costs incurred in theyear	ended Dec 31,2020
	Acquisition Costs $millions 0 0.0	Exploration Costs $millions 0.0 0.0	Development Costs $millions 9.5 9.5	Other Costs $millions
				0.0
				0.0

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Item 6.7 Exploration and Development Activities

Summary of Exploration and Development wells drilled in 2020

Iraq (and Total)	Exploration	Stratigraphic	Production	Service
	wells	Test wells	wells	wells	Total
	(wells)	(wells)	(wells)	(wells)	(wells)
Gross Wells(1)
Total Gross Wells.....................................	–	–	0	0	0
Net Wells(2)
Total Net Wells.........................................	–	–	0	0	0

Notes:

(1) “Gross Wells” represent the number of wells in which the Company has a working-interest.

(2) “Net Wells” represent the number of wells obtained by aggregating the Company’s working-interests in each of its Gross Wells.

Atrush Block

Production Facility and Pipeline

The Atrush Field reached peak rates in excess of 50,000 bopd during 2020, predominately from the nine Upper Jurassic wells. There are plans in the 2021 budget to expand the current production facility by building an additional train which would meet and exceed the peak rates achieved by the field set out by the current field development plan.

Development Wells

The 2019 development campaign entailed drilling CK-11, CK 12, CK-13 and CK-15. The CK-11 well targeted the upper and lower Sargelu which produced at 8,200 bopd with an estimated maximum reservoir rate of 8,550 bopd. The CK-12 well targeted the Mus formation; however, it initially tested with a lower than expected reservoir productivity index, and subsequently only reached initial rates of approximately 600bopd. A 2020 stimulation of the Mus formation is planned to increase the productivity in the CK-12 well. The CK-13 well targeted the Naokelekan and the upper Sargelu and produced at 5,500bopd with an estimated maximum reservoir rate of 8,160bopd. CK-15 targeted the upper and lower Sargelu and produced at rates of 5,000bopd with the potential to exceed 7,000bopd.

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Item 6.8 Production Estimates

First oil was produced on July 3[rd] 2017. The operator reported a total exported field production of 16.513 MMbbl for the year 2020 or a company share of 2.16 MMbbl. The forecast for 2021 is:

SUMMARY OF COMPANY GROSS PRODUCTION ESTIMATES[(1)(2)] (Forecast Prices & Costs)

Iraq (and Total) Proved Atrush Total Probable Atrush Total Possible Atrush Total	Light and Medium Oil (Mbbl) Year 2021 3,038.7 3,038.7 106.6 - 423.6 423.6	Heavy Oil (Mbbl) Year 2021 595.6 595.6 206.4 - 177.4 177.4	Conventional Natural Gas (MMcf) Year 2021
			-
			- -
			- -
			-

Notes:

(1) Estimates are calculated based on the McDaniel Report.

(2) Represents estimated production from January 1, 2020 to December 31, 2020

Item 6.9 Production History

Between July 3[rd] and December 31[st] 2017 the Atrush field operator TAQA reported an exported production of 3,336,633 bbl of medium gravity oil from the Atrush field. For the full year 2018 the exported production from the Atrush field reported by TAQA was 8,077,176 bbl of medium gravity oil. In 2019 the exported production from the Atrush field reported by TAQA was 11,819,215 bbl of medium gravity oil. In 2020 the exported production from the Atrush field reported by TAQA was 16,512,640 bbl of medium and heavy gravity oil

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Appendix

SUMMARY OF CONTINGENT RESOURCES

AS OF DECEMBER 31, 2020

McDaniel has prepared for ShaMaran an assessment of the crude oil and conventional natural gas contingent resources as of December 31, 2020.

Contingent 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. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent resources are further classified in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status.

The resource estimates have been prepared in accordance with standards set out in the Canadian National Instrument

NI 51-101 and the COGE Handbook.

The Atrush Block (see description on pages 12 and 13) crude oil and conventional natural gas contingent resources as of December 31, 2020 were estimated to be as follows:

Contingent Resources(2)(4)(5)	Light & Medium Oil (Mbbl)(3) Gross CompanyInterest Gross 100% Gross(1) Net(6) 100%	Light & Medium Oil (Mbbl)(3) Gross CompanyInterest Gross 100% Gross(1) Net(6) 100%	Heavy Oil (Mbbl)(3) Conventional Natural Gas (MMcf) CompanyInterest Gross CompanyInterest Gross(1) Net(6) 100% Gross(1) Net(6)	Heavy Oil (Mbbl)(3) Conventional Natural Gas (MMcf) CompanyInterest Gross CompanyInterest Gross(1) Net(6) 100% Gross(1) Net(6)	Heavy Oil (Mbbl)(3) Conventional Natural Gas (MMcf) CompanyInterest Gross CompanyInterest Gross(1) Net(6) 100% Gross(1) Net(6)	Heavy Oil (Mbbl)(3) Conventional Natural Gas (MMcf) CompanyInterest Gross CompanyInterest Gross(1) Net(6) 100% Gross(1) Net(6)
	Gross 100%
						Gross(1) Net(6)
Low Estimate (1C) (Development On Hold) Low Estimate (1C) (Development Not Viable) Best Estimate (2C) (Development On Hold) Best Estimate (2C) (Development Not Viable) High Estimate (3C) (Development On Hold) High Estimate (3C) (Development Not Viable) Risked Best Estimate(4)	12,343 30,072 41,879 21,050	3,407 N/A 21,611 79,065 8,300 N/A 41,702 147,943 11,559 N/A 98,849 170,269 5,810 N/A 43,985		5,965 N/A 21,822 N/A 19,541 11,510 N/A 40,832 N/A 36,691 27,282 N/A 46,994 N/A 52,148 12,140 N/A 1,835		5,393 N/A 10,127 N/A 14,393 N/A 506 N/A

Notes:

(1) Company gross interest resources are based on a 27.6 percent working interest share of the property gross resources.

• (2) There is no certainty that it will be commercially viable to produce any portion of the contingent resources.

• (3) The Atrush Field contains crude oil of variable density. Fluid type is classified according to COGEH: Light/Medium Oil is based on a density less than 920 kg/m[3] and Heavy Oil is between 920 and 1000 kg/m[3] .

• (4) The “Risked Best Estimate” contingent resources account for the chance of development, which is defined as the probability of a project being commercially viable. Quantifying the chance of development requires consideration of both economic contingencies and other contingencies, such as legal, regulatory, market access, political, social license, internal and external approvals and commitment to project finance and development timing. As many of these factors are extremely difficult to quantify, the chance of development is uncertain and must be used with caution. The chance of development was estimated to be 70 percent for the Light/Medium and Heavy Crude Oil Development On Hold contingent resources, 10 percent for the Heavy Oil Crude Oil Development Not Viable contingent resources and 5 percent for the Natural Gas.

(5) The contingent resources are sub-classified as “development unclarified” with an “undetermined” economic status.

• (6) Company net interest resources are not available as McDaniel did not undertake a valuation of the resources.

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The resources included in the table above have been sub-classified into development on hold for additional drilling beyond the current commitment and development not viable for the majority of the heavy oil resources where there are currently no plans to further appraise the extended heavy oil development and would require a significant increase in the oil price to warrant this activity as well as for the natural gas development.

The reservoir in the Atrush field consists of fractured carbonates, which require production data for an optimized development plan. As such it was decided to develop the asset under a phased approach whereby information is collected during the first phase of development. This will aid in determining the best approach to the development of the remaining volume of discovered resources (contingent resources). As some of the parameters of development are not clear yet, these contingent resources have been classified as “development unclarified”. A larger development could have been implemented from early on, but without the proper assessment of production performance and narrowing of the uncertainty, the results would not have been optimized. As such it is our view that there is a high likelihood of future development phases proceeding to development and commercialization. Given the nature of the reservoir (containing both types of oil in developed reservoirs) the same chance of development has been applied.

The specific contingencies which prevent the classification of Atrush resources as reserves are largely the lack of information to understand both the drive mechanism, the contribution of the oil stored in the matrix of the reservoir rocks and the production characteristics of heavy oil production. Long-term production from the Jurassic reservoirs, as well as the continued refinement and maturation of the static and dynamic modeling in 2021 will aid narrowing the uncertainty significantly. The information collected from those activities will assist to decide on a concept for the next phase of development (“Phase 2"). Commercial decisions to select the best concept and implement Phase 2 will most likely be taken early 2021. Variation between the possible technical concepts is too large to provide a meaningful timeline for implementation of Phase 2. Even though the development of the contingent resources in the Atrush field is unclarified as yet, management estimates the cost of developing all of the full field contingent resources based on a conceptual development plan at $1.1 billion resulting in a cost factor of approximately 4 USD per barrel of oil. The Company forecasts the development period for the full field contingent resources over a period of 5 years beginning with continuation of the suspended 2020 drilling campaign in 2021 and building up to full production capacity by the year 2023/2024. The assumed recovery technology is vertical wells under natural water drive.

The Atrush Block prospective resources estimates have not been re-evaluated since December 31, 2013.

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