MIE Holdings Corporation - Proxy Solicitation & Information Statement 2018

THIS CIRCULAR IS IMPORTANT AND REQUIRES YOUR IMMEDIATE ATTENTION

If you are in any doubt as to any aspect of this circular or as to the action to be taken, you should consult your licensed securities dealer, registered institution in securities, bank manager, solicitor, professional accountant or other professional adviser.

If you have sold or transferred all of your shares in MIE Holdings Corporation, you should at once hand this circular to the purchaser or the transferee or the bank, licensed securities dealer, registered institution in securities or other agent through whom the sale or transfer was effected for transmission to the purchaser or the transferee.

Hong Kong Exchanges and Clearing Limited and The Stock Exchange of Hong Kong Limited take no responsibility for the contents of this circular, make no representation as to its accuracy or completeness and expressly disclaim any liability whatsoever for any loss howsoever arising from or in reliance upon the whole or any part of the contents of this circular.

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MIE HOLDINGS CORPORATION MI能源控股有限公司

(Incorporated in the Cayman Islands with limited liability) (Stock Code: 1555)

(1) MAJOR TRANSACTION IN RELATION TO THE DISPOSAL OF ASSETS

AND

(2) NOTICE OF THE EXTRAORDINARY GENERAL MEETING

A letter from the Board is set out on pages 7 to 16 of this circular. A notice convening the extraordinary general meeting (the ‘‘EGM’’) of the Company to be held at Plaza 1–2, Novotel Century Hong Kong, 238 Jaffe Road, Wanchai, Hong Kong, on May 7, 2018 at 10:00 a.m. is set out on pages EGM-1 to EGM-2 of this circular. Whether or not you are able to attend the EGM in person, please complete and return the accompanying form of proxy in accordance with the instructions printed thereon and return it to the Company’s registrar in Hong Kong, Tricor Investor Services Limited at Level 22, Hopewell Centre, 183 Queen’s Road East, Hong Kong, as soon as possible and in any event not less than 48 hours before the time fixed for the holding of the EGM or any adjourned meeting thereof (as the case may be). Completion and return of the form of proxy shall not preclude you from attending and voting at the EGM or any adjourned meeting thereof (as the case may be) should you so wish.

April 19, 2018

CONTENTS

		Page
DEFINITIONS	. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	1
LETTER FROM THE BOARD . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .		7
APPENDIX I	— FINANCIAL INFORMATION OF THE GROUP . . . . . . . . . . .	I-1
APPENDIX II	— COMPETENT PERSON’S REPORT . . . . . . . . . . . . . . . . . . . . . . . .	II-1
APPENDIX III	— GENERAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	III-1
NOTICE OF EGM . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .		EGM-1

– i –

DEFINITIONS

In this circular, unless the context otherwise requires, the following expressions shall have the following meanings:

‘‘Adjustment Date’’
8:00 a.m. (Calgary time) on January 1, 2018
‘‘Agreement’’ the agreement of purchase and sale dated March 23, 2018 entered into between the Vendor and the Purchaser in relation to the Disposal
‘‘Announcement’’ the announcement of the Company dated March 26, 2018 in relation to, inter alia, the Disposal
‘‘Assets’’
the Petroleum and Natural Gas Rights, the Tangibles and the Miscellaneous Interests and the entire legal and beneficial interest of the Vendor in and to any White Map Assets, but notwithstanding anything to the contrary in the Agreement, which excludes the Excluded Assets
‘‘Board’’ the board of Directors
‘‘C$’’ Canadian dollars, the lawful currency of Canada
‘‘Circular’’ the circular to be issued by the Company in accordance with the Listing Rules in respect of, among other things, the Disposal
‘‘Closing’’ completion of the Disposal in accordance with the terms and conditions of the Agreement
‘‘Closing Date’’
10:00 a.m. on the later of (i) May 4, 2018, or (ii) two business days after item (iv) of the Vendor’s Conditions Precedent (as set out in the paragraph headed ‘‘Conditions Precedent’’ in this announcement) has been satisfied, complied with or waived (if applicable), or such other time and date as the parties to the Agreement may agree upon in writing
‘‘Company’’
MIE Holdings Corporation (stock code: 1555), a company incorporated in the Cayman Islands with limited liability, the Shares of which are listed on the Main Board of the Stock Exchange
‘‘Competent Person’’
Sproule Associates Limited
‘‘Competent Person’s Report’’
the competent person’s report set out in Appendix II to this circular, issued by the Competent Person, in accordance with the requirements of the Listing Rules

– 1 –

DEFINITIONS

‘‘Conditions Precedent’’
conditions precedent to the Closing, details of which are set out in the paragraph headed ‘‘Conditions Precedent’’ in this announcement
‘‘connected person(s)’’ has the meaning ascribed to under the Listing Rules
‘‘Consideration’’
the total consideration payable by the Purchaser pursuant to the Agreement, details of which are set out in the paragraph headed ‘‘Consideration’’ in this announcement
‘‘Director(s)’’ the director(s) of the Company
‘‘Disposal’’
the disposal of the Assets pursuant to the terms and conditions of the Agreement
‘‘EGM’’
the extraordinary general meeting of the Company to be convened to consider, and if thought fit, approve, among other things, the Disposal, the notice of which is set out on pages EGM-1 to EGM-2 of this circular
‘‘Excluded Assets’’
certain interests of the Vendor specifically excluded in the Agreement, including without limitation 100% of the Vendor’s interest in non-convertible gross overriding royalties and any of the leased vehicles deemed to be Excluded Assets (pursuant to the terms of the Agreement)
‘‘Group’’ the Company and its subsidiaries
‘‘GST’’
the goods and services tax administered pursuant to the Excise Tax Act of Canada, as amended and the regulations thereunder or under any successor or parallel federal or provincial legislation that imposes a tax on the recipient of goods and services
‘‘Lands’’
all lands as areally described in the Agreement and the White Map Area
‘‘Latest Practicable Date’’
April 16, 2018, being the latest practicable date prior to the printing of this circular for ascertaining certain information herein
‘‘Leased Substances’’ all Petroleum Substances, rights to or in respect of which are granted, reserved or otherwise conferred by or under the Title Documents (but only to the extent that the Title Documents pertain to the Lands)
‘‘Listing Rules’’
the Rules Governing the Listing of Securities on the Stock Exchange

– 2 –

DEFINITIONS

‘‘Miscellaneous Interests’’

all property, assets, interests and rights pertaining to the Petroleum and Natural Gas Rights and the Tangibles (other than the Petroleum and Natural Gas Rights and the Tangibles themselves), or either of them, but only to the extent that such property, assets, interests and rights pertain to the Petroleum and Natural Gas Rights and the Tangibles, or either of them, including without limitation any and all of the following (as set out in the Agreement):

(i) contracts and agreements relating to the Petroleum and Natural Gas Rights and the Tangibles, or either of them, including without limitation gas purchase contracts, processing agreements, transportation agreements and agreements for the construction, ownership and operation of facilities and the agreements;
(ii) fee simple surface rights to, and all other rights to enter upon, use or occupy, the surface of any lands which are or may be used to gain access to or otherwise use the Petroleum and Natural Gas Rights and the Tangibles, or either of them, including surface rights;
(iii) all subsisting rights to carry out operations relating to the Lands or Tangibles, and without limitation, all easements and well, pipeline and other Permits, licenses and authorizations;
(iv) all records, books, documents, licences, reports and data which relate to the Petroleum and Natural Gas Rights and the Tangibles, or either of them, including any of the foregoing that pertain to seismic, geological or geophysical matters;
(v) the Wells, including the wellbores and any and all casing;
(vi) any facility or area specific emergency response plans pertaining to the Assets;
(vii) all non-interpretative technical data; and
(viii) the Seismic Rights.
‘‘Petroleum and Natural Gas Rights’’

all rights to and in respect of the Leased Substances and the Title Documents (but only to the extent that the Title Documents pertain to the Lands)

– 3 –

DEFINITIONS

‘‘Petroleum Substances’’ any of crude oil, crude bitumen and products derived therefrom, synthetic crude oil, petroleum, natural gas, natural gas liquids and any and all other substances related to any of the foregoing, whether liquid, solid or gaseous, and whether hydrocarbons or not, including without limitation sulphur and coal bed methane
‘‘PRC’’ the People’s Republic of China, which for the purpose of this circular, excludes Hong Kong, Macau Special Administrative Region of the PRC and Taiwan
‘‘Purchaser’’
a partnership formed pursuant to the laws of Alberta, Canada, a subsidiary of an entity listed on the Toronto Stock Exchange and a third party independent of the Company and its connected persons
‘‘RMB’’ Renminbi, the lawful currency of the PRC
‘‘Seismic Rights’’ the rights to be granted by the Vendor to the Purchaser at Closing
‘‘Share(s)’’ ordinary share(s) of US$0.001 each in the capital of the Company
‘‘Shareholder(s)’’ holder(s) of the Shares
‘‘Stock Exchange’’ The Stock Exchange of Hong Kong Limited
‘‘Tangibles’’

means the facilities and any and all tangible depreciable property and assets, other than the facilities, which are located within the White Map Area and which are used or have been used, are capable of being used or are intended to be used to produce, process, gather, treat, measure, make marketable, store, transport, dispose, remove or inject the Leased Substances or any of them or in connection with water injection, water disposal or removal operations that pertain to the Petroleum and Natural Gas Rights, including without limitation any and all gas plants, oil batteries, buildings, production equipment, pipelines, pipeline connections, meters, generators, motors, compressors, treaters, dehydrators, scrubbers, separators, pumps, tanks, boilers and communication equipment (including any SCADA systems)

– 4 –

DEFINITIONS

‘‘Title Documents’’

collectively, any and all certificates of title, leases, reservations, licenses, assignments, trust declarations, operating agreements, royalty agreements, gross overriding royalty agreements, participation agreements, farm-in agreements, sale and purchase agreements, pooling agreements, permits, surface rights, sale contracts, joint venture contracts, and any other documents and agreements which formerly granted, reserved, or otherwise conferred or currently grant, reserve or otherwise confer rights to (i) explore for, drill for, produce, take, use or market Petroleum Substances, (ii) share in the production of Petroleum Substances, (iii) share in the proceeds from, or measured or calculated by reference to the value or quantity of, Petroleum Substances which are produced; and (v) rights to acquire any of the rights described in items (i) to (iv) of this definition; but only if the foregoing pertain in whole or in part to Petroleum Substances within, upon or under the Lands

‘‘US$’’
United States dollars, the lawful currency of the United States of America
‘‘Vendor’’
Canlin Resources Partnership, a partnership formed pursuant to the laws of Alberta, Canada and a subsidiary of the Company
‘‘Wells’’
all wells which have been, are or may be used in connection with the Petroleum and Natural Gas Rights, including without limitation producing, shut-in, suspended, abandoned, abandoned and reclamation certified, water source, water disposal and water injection wells and the wells, as set out in the Agreement
‘‘White Map Area’’ all lands within an area as outlined on a land plot set out in the Agreement
‘‘White Map Assets’’
all of the Vendor’s entire right, estate, interest and obligations in and to all Petroleum Substances, lands, leases, tangibles, miscellaneous interests and permits falling within the White Map Area, with all of such additional unscheduled Assets and liabilities
‘‘%’’
per cent

– 5 –

DEFINITIONS

For the purpose of this circular and for illustrative purpose only, C$ is converted into HK$ at the rate of HK$6.0836:C$1.00, US$ is converted into HK$ at the rate of HK$7.8220: US$1.00 and US$ is converted into RMB at the rate of RMB6.3294:US$1.00. No representation is made that any amounts in C$ or US$ has been or could be converted at the above rates or at any other rates.

– 6 –

LETTER FROM THE BOARD

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MIE HOLDINGS CORPORATION MI能源控股有限公司

(Incorporated in the Cayman Islands with limited liability)

(Stock Code: 1555)

Executive Directors: Mr. Zhang Ruilin (Chairman) Mr. Zhao Jiangwei

Non-executive Directors: Ms. Xie Na Mr. Jiao Qisen

Independent Non-executive Directors: Mr. Mei Jianping Mr. Jeffrey Willard Miller Mr. Guo Yanjun

Principal place of business in Hong Kong: Level 54, Hopewell Centre 183, Queen’s Road East Hong Kong

Beijing Office: Suite 1501, Block C, Grand Place 5 Hui Zhong Road Chaoyang District Beijing 100101 PRC

April 19, 2018

To the Shareholders

Dear Sir/Madam,

(1) MAJOR TRANSACTION IN RELATION TO THE DISPOSAL OF ASSETS AND

(2) NOTICE OF THE EXTRAORDINARY GENERAL MEETING

INTRODUCTION

Reference is made to the Announcement in relation to the Agreement entered into by the Vendor and the Purchaser on March 23, 2018 (Calgary time) pursuant to which the Vendor agreed to sell and the Purchaser agreed to purchase the Assets, at the Base Price of C$60.0 million (approximately HK$365.0 million) (subject to adjustments).

– 7 –

LETTER FROM THE BOARD

The purpose of this circular is to provide you with, among other things, (i) further details in relation to the Agreement and the transactions contemplated thereunder; (ii) the Competent Person’s Report; (iii) other information as required under the Listing Rules; and (iv) the notice convening the EGM.

THE AGREEMENT

The principal terms of the Agreement are as follows:

Date

March 23, 2018

Parties

(i) the Vendor; and
(ii) the Purchaser.

To the best of the Directors’ knowledge, information and belief and having made all reasonable enquiries, the Purchaser and its ultimate beneficial owner(s) are third parties independent of the Company and its connected person(s).

Subject matter of the Disposal

The Assets are the entire legal and beneficial interest of the Vendor in certain Petroleum and Natural Gas Rights, the Tangibles and the Miscellaneous Interests located in central Alberta, Canada. The Assets under the Disposal are oil and gas reserves and infrastructure in the Carrot Creek and Cyn Pem fields of central Alberta, Canada, including gathering pipelines and an operated gas plant. Section 4 of the Competent Person’s Report summarizes the location, formations, acreage, reserves, and historic production of the Assets. Further background on the regional geologic setting and localized geology or engineering are also discussed in sections 5 and 6 of the Competent Persons’ Report.

The Assets under the Disposal do not include the Excluded Assets, which are (i) nonconvertible gross overriding royalties of the Vendor in the White Map Area and (ii) surplus oilfield equipment that is not associated with any assets in the White Map Area. The White Map Area includes some or all of townships 49 to 55, ranges 11 to 16 west of the fifth meridian in central Alberta, Canada.

Consideration

Base Price and adjustments

The Consideration under the Agreement is C$60.0 million (approximately HK$365.0 million) (the ‘‘Base Price’’) plus or minus (as applicable) the net amount of any operating adjustments pursuant to the terms of the Agreement.

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LETTER FROM THE BOARD

Operating adjustments

Subject to the terms of the Agreement, all benefits and obligations of any kind and nature relating to the operation of the Assets conveyed pursuant to the Agreement, excluding income taxes but otherwise including without limitation maintenance, development, operating and capital costs, government incentives and administration fees, royalties and other burdens, and proceeds from the sale of production whether accruing, payable or paid and received or receivable, shall be adjusted between the parties between the Adjustment Date and the Closing Date in accordance with generally accepted accounting principles. The maximum estimated amount of operating adjustments is C$4.0 million (equivalent to approximately HK$24.3 million), whereas based on latest available information and best estimates, the estimated impact of the operating adjustments is C$3.1 million (equivalent to approximately HK$18.9 million). However, the final operating adjustments could vary from the estimate due to the volumes produced, the product mix, the price obtained for the products, as well as the actual operating and capital costs associated with the operation of the Assets.

The Vendor shall provide to the Purchase prior to the Closing a written statement of all such operating adjustments to be made at Closing. Adjustments not settled or incorrectly settled prior to at Closing shall be settled to or by the Vendor or the Purchaser (as the case may be), as soon as practicable after Closing.

Payment of Consideration

The Purchaser shall pay to the Vendor, at Closing, (i) the Consideration and (ii) the GST payable in respect of the Assets, by wire transfer to an account designated by the Vendor to the Purchaser in writing prior to Closing.

The Consideration was determined on normal commercial terms after arm’s length negotiations between the Vendor and the Purchaser with reference to a number of factors, including production rates, reserve values and the strategic value of the assets under the macro Canadian natural gas environment. With reference to the strategic value of the assets, the Board has assessed this by (i) considering whether or not the Assets under the Disposal will see further investment and development by the Vendor given recent natural gas pricing, and (ii) considering other investment opportunities in the Vendor’s portfolio which rank higher than the Assets under the Disposal. References to macro Canadian natural gas environment are in relation to the weakening of natural gas pricing recently in Canada. In addition, other recent market conditions in Western Canada (as further described in the section titled ‘‘Financial and Trading Prospects of the Group’’ in Appendix I to this circular) are also considered. These current market conditions are relevant in assessing the strategic value of the assets as they require the Company to invest in optimum assets among uncertainties in the market.

Based on the Base Price of approximately C$60.0 million (approximately HK$365.0 million), the Acquisition represents multiples of C$5.51/boe, being the Consideration divided by the 2P reserves of the Assets and C$29,354.2/boe/d, being the Consideration divided by the total daily production of the Assets. The Board has reviewed the Consideration in terms of the average production rate acquisition price ($/boe/d) of similar gas weighted transactions announced in Canada in 2017. The Board also reviewed the Consideration in terms of the average 2P reserves value ($/boe) of similar gas weighted transactions announced in Canada in

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LETTER FROM THE BOARD

The abovementioned gas weighted transactions announced in Canada in 2017 include those transactions set out in the table below. Given the gas weighting percentage for the Assets under Disposal is approximately 71%, taking into account of the gas weighting of the gas weighted transactions, the Board has concluded that the Consideration was favorable based on both of these indicators.

Gas weighted transactions over C$10 million announced in Canada in 2017

				Transaction	Metrics
		Transaction	Gas	Production	2P
Target	Acquiror	Value Deal Type	Weighting		Reserves
		(C$MM)	(%)	($/boe/d)	($/boe)
Cenovus Energy	Torxen Resources/	$1,300 Asset	77%	$24,074	n.a.
	Schlumberger
Cenovus Energy	International Petroleum	$512 Asset	71%	$21,333	$5.12
	Corp.
RMP Energy	Tangle Creek Energy	$80 Asset	70%	$24,883	$3.48
Undisclosed company(ies)	Ikkuma Resources Corp.	$34 Asset	98%	$2,972	$0.87
Pengrowth Energy	Undisclosed company(ies)	$300 Asset	60%	$21,622	$3.85
Questfire Energy Corp.	Manitok Energy Inc.	$55 Corporate	77%	$12,854	$1.92
Apache Corporation	Paramount Resources Ltd.	$460 Asset	74%	$10,890	$1.59
Trilogy Energy Corp.	Paramount Resources Ltd.	$1,190 Corporate	62%	$47,348	$7.21
Bellatrix Exploration Ltd.	Undisclosed company(ies)	$35 Asset	70%	$24,643	n.a.
Centrica	MIE Holdings	$722 Asset	87%	$12,945	$2.10
Trilogy Energy Corp.	Undisclosed company(ies)	$60 Asset	68%	$93,750	n.a.
Trilogy Energy Corp.	Undisclosed company(ies)	$50 Asset	84%	$45,455	$9.09
Paramount Resources	Undisclosed company(ies)	$150 Asset	n.a.	$107,143	n.a.
Undisclosed company(ies)	Clearview Resources	$20 Asset	67%	$17,946	$6.00
UGR Blair Creek Ltd.	Painted Pony Petroleum	$277 Asset	96%	$32,541	$0.85
Enerplus	Undisclosed company(ies)	$67 Asset	66%	$9,219	n.a.
Undisclosed company(ies)	Clearview Resources	$11 Asset	58%	$32,443	$10.55
Kelt Exploration	Undisclosed	$100 Asset	50%	$76,746	$7.87
Chinook Energy	Undisclosed company(ies)	$11 Asset	65%	$106,061	$47.06
Average			72%	$38,151	$7.68
Median			70%	$24,643	$4.48

Taking into account the above, the Directors consider the Consideration is fair and reasonable and in the interests of the Company and the Shareholders as a whole, given that (i) the Consideration exceeds average gas weighted metrics of comparable transactions that took place in Canada in 2017, (ii) the Vendor does not plan to make additional investments in the Assets under the Disposal and (iii) the proceeds generated can be used for other assets with higher ranking to allow the Company to get the most from its investment capital.

– 10 –

LETTER FROM THE BOARD

Conditions precedent

Closing is conditional on the following conditions precedent being satisfied or waived (if applicable):

Purchaser’s conditions

The obligation of the Purchaser to purchase the Vendor’s interest in and to the Assets is subject to the following conditions precedent, which are inserted for the exclusive benefit of the Purchaser and may be waived by the Purchaser:

(i) the representations and warranties of the Vendor as set out in the Agreement shall be true in all material respects when made and as of the Closing Date;
(ii) all obligations of the Vendor as set out in the Agreement to be performed prior to or at Closing shall have been timely performed in all material respects;
(iii) from the Adjustment Date to the Closing Time, the Assets shall have suffered no material, adverse physical damage or change. For clarity, a reduction in the price received for the sale of Petroleum Substances is not a material, adverse damage or change;
(iv) the Vendor shall have delivered to Purchaser at or prior to Closing discharges, releases or no interest letters (in form and substance satisfactory to Purchaser, acting reasonably) of any and all security held by any third party encumbering the Vendor’s interest in and to the Assets or any part or portion thereof, which discharges, releases or no interest letters are requested by Purchaser a reasonable time prior to Closing; and
(v) subject to any other terms of the Agreement, prior to the Closing Date, the Vendor shall have obtained and produced to the Purchaser relevant third party written consents as and if required under the terms of the Title Documents and any other agreements and documents to which the Assets are subject and which are customarily obtained prior to closing in oil and gas transactions in Canada.

Vendor’s conditions

The obligation of the Vendor to sell its interest in and to the Assets is subject to the following conditions precedent, which are inserted for the exclusive benefit of the Vendor and may be waived by the Vendor:

(i) the representations and warranties of the Purchaser as set out in the Agreement shall be true in all material respects when made and as of the Closing Date;
(ii) all obligations of the Purchaser as set out in the Agreement to be performed prior to or at Closing shall have been timely performed in all material respects;
(iii) all amounts to be paid by the Purchaser to the Vendor at Closing shall have been paid to the Vendor in the form stipulated in the Agreement; and

– 11 –

LETTER FROM THE BOARD

(iv) the Vendor shall receive confirmation from the Company that all of the requirements under the Listing Rules (including, without limitation, the requirements on Shareholders’ approval under Chapter 14 of the Listing Rules), which are applicable to the transactions contemplated under the Agreement, have been satisfied.

If any one or more of the conditions precedent has or have not been satisfied, complied with (through no act, default or omission of the Vendor or the Purchaser (as the case may be)), or waived by the Vendor or the Purchaser (as the case may be), at or before the earlier of the date specified above or the Closing Date, the Vendor or the Purchaser (as the case may be) may in addition to any other remedies which it may have available to it, rescind the Agreement by written notice to other party. If a party rescinds the Agreement, the Vendor and the Purchaser shall be released and discharged from all obligations (unless specifically provided otherwise in the Agreement).

Closing

Closing shall take place on the Closing Date.

Upon Closing of the Disposal, the Group will continue to own oil and gas assets in Western Canada.

Closing of the Disposal is subject to the Conditions Precedent being satisfied, including the approval of the Disposal by Shareholders at the EGM. Accordingly, the Disposal may or may not proceed and Shareholders and potential investors of the Company are advised to exercise caution when dealing in the Shares and other securities of the Company.

KEY SUMMARY OF THE COMPETENT PERSON’S REPORT

The Competent Person’s Report contains key information on the Assets under the Disposal. This includes regional and local geological setting and formations, acreage and mineral rights, production and reserves, and economic evaluation in relation to the Assets. The results of this evaluation are summarized in section 2 of the Competent Person’s Report.

The Vendor’s average working interest is 71.55% and its gross acreage is 62,072 acres (net 44,412) in the Carrot Creek area. With respect to the the Cyn-Pem area, the Vendor’s average working interest is 45.73% and its gross acreage is 4,520 acres (net 2,067). In July 2017, Carrot Creek was producing approximately 150 bopd at about 55% water cut from 15 wells and approximately 13,400 mcfd of raw gas from a further 87 wells. Cyn-Pem was producing approximately 175 bopd from 18 wells and approximately 750 mcf of gas from 1 well in July 2017.

According to the Competent Person’s Report as at January 1, 2018, the total proved reserves (‘‘1P’’) of the Assets was approximately 6,727 thousand barrels of oil equivalent (‘‘MBOE’’) and the total proved and probable reserves (‘‘2P’’) of the Assets was approximately 10,877 MBOE.

– 12 –

LETTER FROM THE BOARD

INFORMATION ON THE PARTIES

The Group

The Group is principally engaged in the exploration, development, production and sale of oil, gas and other petroleum products. The Group operates the Daan oilfield under a production sharing contract. In addition, the Group has a diverse producing, resource and infrastructure oil and gas asset throughout Western Canada and a working interest in the Niobrara shale oil and gas assets in the USA. The Group also participates as an associate in the exploration, development and production of petroleum assets located in the Republic of Kazakhstan, Canada and the northern part of the South China in the PRC.

The Purchaser

The Purchaser is a partnership formed pursuant to the laws of Alberta, Canada. The Purchaser is an energy producer headquartered in Calgary, Alberta, Canada with a diverse portfolio of assets located in various regions throughout the world.

FINANCIAL INFORMATION ON THE ASSETS AND FINANCIAL EFFECTS OF THE DISPOSAL

The net profits (before taxation and extraordinary items) attributable to the Assets for the two financial years ended December 31, 2017 were C$5.2 million (approximately HK$31.6 million) for year ended December 31, 2017 and C$3.4 million for the year ended December 31, 2016 (approximately HK$20.7 million) respectively. The net profits (after taxation)[(Note)] attributable to the Assets for the two financial years ended December 31, 2017 were C$3.8 million (approximately HK$23.1 million) for year ended December 31, 2017 and C$2.5 million for the year ended December 31, 2016 (approximately HK$15.2 million) respectively. The net book value of the Assets was C$39.3 million as at December 31, 2017 (approximately HK$239.1 million).

Based on the difference between the Consideration (being C$56.9 million (approximately HK$346.2 million), taking into account estimated operating adjustments in the amount of C$3.1 million (approximately HK$18.9 million)) and the net book value of the Assets (being C$39.3 million (approximately HK$239.1 million) as at December 31, 2017), the Company is expected to record an unaudited book gain, before transaction expense, taxes and adjustments to net book value up to the date of Closing, of approximately C$17.6 million (approximately HK$107.1 million) pursuant to the Disposal. The actual gain on the Disposal is subject to audit and may be different from the expected amount as stated above.

After Closing, the consolidated total assets of the Group will decrease by approximately C$54.3 million (approximately HK$330.3 million) and total liabilities of the Group will decrease by approximately C$15.0 million (approximately HK$91.2 million) (calculated based on the net book value of the Assets as at December 31, 2017).

Note: Tax resource pools are comingled and are not specifically identifiable to the Assets. Therefore, tax resource deductions specific to the Assets cannot be calculated with a degree of certainty. For simplicity, a general 27% corporate income tax rate was applied for calculation of the after taxation net profits. There were no extraordinary items during the two financial years ended December 31, 2017.

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LETTER FROM THE BOARD

USE OF PROCEEDS

The net proceeds to the Vendor from the Disposal after deducting related transaction costs and expenses are estimated to be C$56.3 million (approximately HK$342.5 million). The Vendor intends to apply the net proceeds from the Disposal used towards general working capital of the Vendor and/or funding for future investment opportunities generally.

REASONS FOR AND BENEFITS OF THE DISPOSAL

According to the Competent Person’s Report as at January 1, 2018, the 2P reserves of the Assets was approximately 10,877 MBOE, representing only about 3% of the Vendor’s total 2P reserves BOE and 2.73% of the Group’s total net 2P reserves BOE. Accordingly, the level of reserves in relation to the Assets under Disposal is insignificant as compared to the Vendor’s as well as the Group’s total 2P reserves. The Assets were acquired by the Group as part of the Group’s very substantial acquisition in the fourth quarter of 2017 (the ‘‘Acquisition’’) as the Assets formed part of the assets held by CQ Energy Canada Partnership. However, the Assets under the Disposal are considered to be non-strategic in the future development of the Company and will not be seeing future investment and growth by the Vendor. It is in accordance with the normal market practice in Canada for the Group to dispose of nonstrategic assets in order to realign its resources. Given the levels of reserves in relation to the Assets under the Disposal only represent a small portion of Assets being acquired under the Acquisition, the Disposal provides a considerable return to the Group from its investment of the Assets under the Acquisition. Save as disclosed in this circular, there is no other material change of circumstances since the Acquisition that contributed to the Group’s decision in disposing the Assets under the Disposal. Moreover, since the Assets only constitute a small percentage of the Group’s total 2P reserves BOE in Canada, it will not in any event affect the current business model and intention of the Group on owning oil and gas assets in Western Canada. The Company continues to hold the view that, despite the unfavorable macro Canadian natural gas environment and market conditions, the Vendor has a portfolio with high quality and great potential that builds a resilient and profitable business. The Company is also of the view that Canada natural gas market is well positioned to play an important role in the global energy mix. The Company will closely follow the market to ensure that the Group’s corporate strategy and operation planning would respond to market condition promptly in order to deliver better value for the shareholders.

The Disposal will attribute potential gains of approximately C$17.6 million (approximately HK$107.1 million) to the Group upon Closing and will enhance the financial strength of the Group in the current oil and gas market environment. In addition, the Disposal (being a divestment of non-core assets) will allow the Group to maintain a focused and concentrated asset base while strengthening its balance sheet.

Accordingly, as disclosed above, given that (i) the Disposal is generating Consideration which exceeds average 2017 metrics on comparable transactions in Canada and (ii) the Disposal strengthens the remaining portfolio of the Vendor through the sale of assets (which are non-strategic to the Vendor and will not be seeing additional investment and growth by the Vendor given the current natural gas pricing) through normal course of business, the Board is

– 14 –

LETTER FROM THE BOARD

of the view that: (i) the Disposal is in the interest of the Company and the Shareholders as a whole; (ii) the terms of the Agreement are fair and reasonable; and (iii) the entering into of the Agreement is in the interest of the Company and Shareholders as a whole.

IMPLICATIONS UNDER THE LISTING RULES

As the highest applicable percentage ratio in respect of the Disposal exceeds 25% but is less than 75%, the Disposal constitutes a major transaction for the Company under Chapter 14 of the Listing Rules and is therefore subject to the notification, announcement and shareholders’ approval requirements under Chapter 14 of the Listing Rules. The Company will convene the EGM at which ordinary resolution(s) will be proposed to approve, among other things, the Disposal.

To the best of the knowledge, information and belief of the Directors having made all reasonable enquiries, no Shareholder has any material interest in the Disposal as at the date of this announcement, and as such, no Shareholder is required to abstain from voting on the resolution(s) to be proposed at the EGM to approve the Disposal.

EGM

The EGM will be held at Plaza 1–2, Novotel Century Hong Kong, 238 Jaffe Road, Wanchai, Hong Kong, on Monday, May 7, 2018 immediately after the conclusion of the extraordinary general meeting of the Company in relation to the disposal of the legal and beneficial interest of the Vendor in certain Petroleum and Natural Gas Rights, the Tangibles and the Miscellaneous Interest located in central Alberta, Canada for the purpose of considering and, if thought fit, passing the resolutions set out in the notice of EGM, which is set out on pages EGM-1 to EGM-2 of this circular.

Whether or not you are able to attend the EGM in person, please complete and return the accompanying form of proxy in accordance with the instructions printed thereon and return it to the Company’s register in Hong Kong, Tricor Investor Services Limited at Level 22, Hopewell Centre, 183 Queen’s Road East, Hong Kong, as soon as possible and in any event not less than 48 hours before the time fixed for the holding of the EGM or any adjourned meeting thereof (as the case may be). Completion and return of the form of proxy shall not preclude you from attending and voting in person at the EGM or any adjourned meeting thereof (as the case may be) should you so wish.

CLOSURE OF REGISTER OF MEMBERS

The register of members of the Company will be closed from Wednesday, May 2, 2018 to Monday, May 7 2018, both days inclusive, during which period no transfer of shares of the Company will be effected. In order to qualify for the attendance at the EGM, all transfers accompanied by the relevant share certificates must be lodged with the Company’s Hong Kong share register, Tricor Investor Services Limited at Level 22, Hopewell Centre, 183 Queen’s Road East, Hong Kong not later than 4:30 p.m. on Monday, April 30, 2018.

– 15 –

LETTER FROM THE BOARD

RECOMMENDATION

The Directors (including the independent non-executive Directors) consider that the terms of the Agreement are on normal commercial terms and are fair and reasonable and in the interests of the Company and the Shareholders as a whole. Accordingly, the Directors (including the independent non-executive Directors) recommend the Shareholders to vote in favour of the relevant resolutions to approve the Disposal at the EGM.

ADDITIONAL INFORMATION

Your attention is drawn to the further information contained in the appendices to this circular.

Yours faithfully, For and on behalf of the Board Zhang Ruilin Chairman

– 16 –

FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

1. STATEMENT OF INDEBTEDNESS

Borrowings

At the close of business on February 28, 2018, being the latest practicable date for the purpose of the statement of indebtedness prior to the printing of this circular, the Group had total outstanding indebtedness of approximately RMB5,324.4 million, comprising (i) secured bank loans of approximately RMB803.7 million, (ii) secured finance institution loans of approximately RMB1,912.9 million, (iii) secured third party borrowings of approximately RMB616.8 million, (iv) interest bearing notes carrying at a book value of approximately RMB1,974.6 million, and (v) an unsecured borrowing due to a related party of approximately RMB16.4 million.

Compound Instruments

At the close of business on February 28, 2018, being the latest practicable date for the purpose of the statement of indebtedness prior to the printing of this circular, the Group had convertible bonds with principal amount of HK$340,000,000 with an Initial Conversion Price of HK$0.58 and due to mature on the third anniversary of the date of issue, bearing interest at 5% per annum, payable semi-annually in arrears on January 26, and July 26, and will mature on January 26, 2021.

Charges

As at February 28, 2018, certain assets, comprising principally oil assets and properties in Alberta, Canada, were pledged to banks as collateral security for banking facilities in the amount of RMB803.7 million. In addition, as of February 28, 2018, certain available for sale financial assets, bank accounts and shares of subsidiaries of the Group were also pledged to secure borrowings in the aggregate amount of RMB2,529.7 million.

Contingent liabilities

As at February 28, 2018, the Group had no material contingent liabilities or guarantees.

Save as aforesaid or otherwise disclosed herein, and apart from intra-group liabilities and normal trade payables in the ordinary course of business, the Group did not have any other debt securities issued and outstanding, or authorised or otherwise created but unissued, loans or any term loans (secured, unsecured, guaranteed or otherwise), any other borrowings or indebtedness in the nature of borrowing including bank overdrafts and any liabilities under acceptances (other than normal trade bills), acceptance credits or hire purchase commitments (guaranteed, unguaranteed, secured or otherwise), mortgages, charges or other material contingent liabilities, as at the close of business on February 28, 2018.

– I-1 –

FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

2. WORKING CAPITAL STATEMENT

In determining the sufficiency of the working capital of the Group, a key consideration is that the senior notes of US$315.9 million (equivalent to RMB2,053.4 million) will expire on April 25, 2019 (the ‘‘Senior Notes’’) which is within twelve months from the date of this Circular. Management of the Company is planning for a debt refinancing which may involve exchange offer and concurrent new money issuance of senior notes to meet the repayment of Senior Notes in full (the ‘‘Planned Senior Notes Refinancing’’). The Directors have included the proceeds from the Planned Senior Notes Refinancing in the working capital forecast based on the management’s best estimate. Up to the date of this Circular, the timetable and the detailed plan of the Planned Senior Notes Refinancing have not been committed. The Company is in the initial stages of discussions for the Planned Senior Notes Refinancing with financial institutions. Whether the Planned Senior Notes Refinancing could be executed depends on various factors, including but not limited to sentiment of bond market and oil price that may affect the financial performance of the Company.

Should the Planned Senior Notes Refinancing fail and is excluded from the working capital forecasts and the Group fails to obtain any alternative financing arrangement to meet the repayment of Senior Notes due on April 25, 2019, the Group will not have sufficient working capital for the Group’s requirement upon the maturity of the Senior Notes.

The Directors are of the opinion that, in the absence of unforeseeable circumstances, after taking into account the Group’s business prospects, the financial resources available to the Group, including the internally generated funds, the available financing facilities, the effects of the completion of the Disposal and on the assumption that the Planned Senior Notes Refinancing as set out above will be completed, the Group has sufficient working capital for its present requirements for at least the next twelve months from the date of this Circular.

3. FINANCIAL AND TRADING PROSPECTS OF THE GROUP

Recent market events and conditions, including global excess oil and natural gas supply, actions taken by the Organization of the Petroleum Exporting Countries (‘‘OPEC’’), slowing growth in emerging economies, market volatility and disruptions in Asia, sovereign debt levels and political upheavals in various countries, have caused significant weakness and volatility in commodity prices. These events and conditions have caused a significant decrease in the valuation of oil and gas companies and a decrease in confidence in the oil and gas industry. These difficulties have been exacerbated in Canada by the recent changes in government at a federal level and, in the case of Alberta, at the provincial level, and the resultant uncertainty surrounding regulatory, tax, royalty changes and environmental regulation that have been announced or may be implemented by the new governments. In addition, the inability to get the necessary approvals to build pipelines and other facilities to provide better access to markets for the oil and gas industry in Western Canada has led to additional downward price pressure on oil and gas produced in Western Canada and uncertainty and reduced confidence in the oil and gas industry in Western Canada. Lower commodity prices may also affect the volume and value of the Group reserves, rendering certain reserves uneconomic. In addition, lower commodity prices have restricted, and may continue to restrict, the Group’s cash flow resulting in a reduced capital expenditure budget.

– I-2 –

FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

In the last several years, the United States and certain European countries have experienced significant political events that have cast uncertainty on global financial and economic markets. In addition to the political disruption in the United States, the citizens of the United Kingdom recently voted to withdraw from the European Union and the Government of the United Kingdom has begun to take steps to implement such withdrawal. To the extent that certain political actions taken in North America, Europe and elsewhere in the world result in a marked decrease in free trade, access to personnel and freedom of movement, it could have an adverse effect on the Group’s ability to market its products internationally, increase costs for goods and services required for the Target’s operations, reduce access to skilled labour and negatively impact the Group’s business, operations, and financial conditions.

North American oil and natural gas prices are based upon US dollar denominated commodity prices. As a result, the price received by Canadian producers is affected by the C$/ US$ foreign exchange rate that may fluctuate over time. The Vendor has not entered into any contracts to manage foreign exchange risk.

When operating in such a challenging macro environment, the Group focuses on its ability to remain flexible and to react promptly to drastic changes. In 2017, despite the challenging macro environment, we were pleased with our achievements in managing and lowering our costs. In particular, lifting costs in our China oilfields increased only 2.0% to US$8.48/bbl. In terms of overall overhead, the total headcount of the Group increased from 1,387 as of yearend 2016 to 1,495 as of year-end 2017. In 2017, the Group has continued to adapt and rebalance in response to the lower commodity prices by way of managing and lowering our operating and administrative costs, while maintaining safe and reliable operations.

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COMPETENT PERSON’S REPORT

APPENDIX II

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INDEPENDENT COMPETENT PERSON’S REPORT OF CERTAIN P&NG RESERVES IN ALBERTA, CANADA OF CANLIN ENERGY CORPORATION FOR MIE HOLDINGS CORPORATION (AS OF JANUARY 1, 2018)

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COMPETENT PERSON’S REPORT

APPENDIX II

Copies:
Canlin Energy Corporation (2 copies)
Electronic (2 copies)
Sproule (1 copy)
Project No.:
3390.22221
Prepared for:
Canlin Energy Corporation and MIE Holdings Corporation
Authors:
Barrett R. Hanson, P.Eng., SPEC, Project Leader
Alec Kovaltchouk, P.Geo.
Exclusivity:
This report has been prepared for the exclusive use of Canlin Energy Corporation and MIE
Holdings Corporation. The distribution to and use by third parties of the Report is governed by
the terms and conditions of the Engagement Agreement entered into between Sproule and
Canlin Energy Corporation and by the assumptions and limitations as contained herein.

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COMPETENT PERSON’S REPORT

APPENDIX II

Table of Contents — Page 1

1. Table of Contents

1 Table of Contents 2 Executive Summary 3 Introduction 3.1 Scope and Terms of Reference 3.2 Statement of Competent Persons 3.3 Credentials of Sproule 3.4 Field Operations 3.5 Nature and Source of Information 3.6 Reporting Standards 3.7 Effective and Preparation Dates 3.8 Evaluation Procedures 3.9 Evaluation Results 3.10 Reserve Definitions 3.11 Abbreviations
4 Summary of Assets 4.1 Location of Assets 4.2 Ownership and Acreage 4.3 Reserves and Net Present Value 4.4 Project Gross Field Production Profiles
5 Regional Geological Discussion 5.1 Regional Petroleum History 5.2 Regional and Basin Generalized Geology, Evident Petroleum System
6 Local Geological and Engineering Discussion 6.1 Reserves 6.2 Rights to Explore and Extract Hydrocarbons 6.3 Geology 6.4 Production 6.5 Overall Development Plan 6.6 Methods of Estimation 6.7 Volumes of Sales Product
7 General Business Discussion 7.1 General Description of the Company 7.2 Statement of Long Term Prospects 7.3 Assessment of Technical Staff
8 Economic Evaluation Discussion 8.1 Discounted Net Present Values 8.2 Fiscal Terms

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COMPETENT PERSON’S REPORT

APPENDIX II

Table of Contents — Page 2

8.3 Economic Assumptions
9 Social and Environmental Discussion 10 Basis of Opinion 10.1 Evaluation Results 10.2 Risks 10.3 Exclusivity 10.4 Report Preparation
11 References

Tables

Table	2-1	Summary of Reserves and Net Present Value as of January 1, 2018
		Before Income Tax
Table	4.2-1	Summary of Canlin’s Working Interest, Project Gross Developed and
		Canlin Net Developed Acreage
Table	4.3-1	Summary of P&NG Reserves and Net Present Value as of January 1,
		2018 Before Income Tax
Table	6.1-1	Summary of Oil, Gas and NGL Reserves as of January 1, 2018
		(Forecast Prices and Costs)
Table	6.3.2.1	Reservoir Parameters of Main Reservoirs – Carrot Creek and Cyn-Pem
		areas
Table	6.4.3-1	Summary of Project Gross Total Proved Production Forecasts
Table	6.4.3.2	Summary of Project Gross Total Proved Plus Probable Production
		Forecasts
Table	6.5-1	Summary of Undeveloped Well Locations by Formation – Carrot Creek
		Area
Table	6.5-2	Timing of Undeveloped Well Locations by Year
Table	6.6-1	Gas By-Product Yields from Sales Gas Volumes
Table	8.1-1	Summary of Net Present Value Before Income Taxes as of January 1,
		2018 (Forecast Prices and Costs)
Table	8.3.2-1	Summary of Pricing Forecast and Assumptions as of December 31, 2017
Table	8.3.2-2	Summary of Price Offsets to Forecast Price
Table	8.3.3-1	Summary of Project Gross Capital Costs in 2018 Dollars for Carrot Creek
		Area (MM$Cdn)
Table	8.3.4-1	Summary of Project Gross Operating Cost Assumptions in 2018 Dollars
Table	8.3.6-1	Summary of Sensitivity Analyses
Table	10.2.1-1	Overall Risk Assessment Matrix
Table	10.2.1-2	Project Risk Assessment

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COMPETENT PERSON’S REPORT

APPENDIX II

Table of Contents — Page 3

Figures

s
Figure	4.1-1	Location Map – Carrot Creek and Cyn-Pem Areas showing Canlin
		Interest Lands
Figure	4.4-1	Project Gross Production History with Total Proved Oil Production
		Forecast for Carrot Creek and Cyn-Pem Areas
Figure	4.4-2	Project Gross Production History with Total Proved Gas Production
		Forecast for Carrot Creek and Cyn-Pem Areas
Figure	4.4-3	Project Gross Production History with Total Proved Plus Probable Oil
		Production Forecast for Carrot Creek and Cyn-Pem Areas
Figure	4.4-4	Project Gross Production History with Total Proved Plus Probable Gas
		Production Forecast for Carrot Creek and Cyn-Pem Areas
Figure	5.2.1-1	Stratigraphic Correlation Chart of Western Alberta
Figure	6.3-1	Map of Canlin Interest Lands in the Carrot Creek Area
Figure	6.3-2	Map of Canlin Interest Lands in the Cyn-Pem Area
Figure	6.3.1.1	Carrot Creek and Cyn-Pem Areas – Cardium Formation Net Pay
Figure	6.3.1.2	Carrot Creek Area – Notikewin Formation Porosity Thickness
Figure	6.3.1.3	Carrot Creek Area – Wilrich Formation Porosity Thickness
Figure	6.3.1.4	Carrot Creek Area – Gething Formation Net Pay
Figure	6.3.1.5-1	Carrot Creek Area – Upper Rock Creek Net Pay
Figure	6.3.1.5-2	Carrot Creek Area – Middle Rock Creek Net Pay
Figure	6.3.1.5-3	Carrot Creek Area – Lower Rock Creek Net Pay
Figure	6.5.1	Carrot Creek and Cyn-Pem Areas – Canlin Owned or Accessible
		Infrastructure

Appendices

Appendix A Reserve Definitions Appendix B Abbreviations, Units and Conversion Factors Appendix C Cash Flow Reports Appendix D Well List with Interest and Burdens Appendix E Representation Letter

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COMPETENT PERSON’S REPORT

APPENDIX II

Executive Summary — Page 1

2. Executive Summary

Table 2-1 summarize our evaluation, before income taxes, of certain P&NG reserves of Canlin Energy Corporation (“the Company” or “Canlin”), as of January 1, 2018. Canlin Energy Corporation is a wholly owned subsidiary of Maple Marathon Investments which is a wholly owned subsidiary of MIE Holding Corporation (“MIE”). Sproule has performed an evaluation of certain petroleum and natural gas assets in the Carrot Creek (“Carrot Creek”) and Cynthia-Pembina (“Cyn-Pem”) areas in the Province of Alberta, Canada (combined as “the Assets”). Canlin has entered into a Purchase and Sale Agreement to sell one hundred percent of their interest in the Assets. The evaluation considers certain geological, geophysical, engineering and commercial aspects of the development and production of the Assets.

After tax values have not been reported at the request of Canlin.

The recoverable volumes were estimated deterministically for all reserves categories using production decline analysis on actual production data, where sufficient data was available to establish production trends. Volumetric and analogy techniques were also used to estimate recoverable volumes for undeveloped locations and wells with short production histories.

The reserves definitions and ownership classification used in this evaluation are the standards defined by the COGE Handbook reserve definitions and consistent with Canadian National Instrument 51-101 (“NI 51101”). The oil reserves are presented in thousands of barrels, at stock tank conditions. The natural gas reserves are presented in millions of cubic feet, at base conditions of 14.65 psia and 60 degrees Fahrenheit. The natural gas liquids and condensate reserves are presented in thousands of barrels, at base conditions of 60 degrees Fahrenheit and equilibrium pressure.

The net present values of the reserves are presented (on a before income tax basis) in Canadian dollars and are based on annual projections of net revenue, which were discounted at various rates using the midperiod discounting method. These rates are 5, 10, 15 and 20 percent and undiscounted.

The price forecasts that formed the basis for the revenue projections in the evaluation were based on Sproule’s December 31, 2017 pricing model.

Capital and operating costs were escalated at 2.0 percent per year starting in 2019. Sproule’s cost escalation in 2018 assumes a 0 percent increase.

Abandonment and reclamation costs for existing wells with economic developed reserves, and future economic proposed development have been included in the evaluation and have been forecast at the entity level.

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COMPETENT PERSON’S REPORT

APPENDIX II

Executive Summary — Page 2

The Company has not identified any material dedicated facilities for which abandonment and reclamation costs have been included in the evaluation.

The evaluation does not include abandonment and reclamation costs associated with active producing wells, which are not economic to produce under the forecast prices, active service wells, inactive wells, and various active or inactive gathering and processing facilities, that the Company holds an interest in, that were not identified as being material dedicated facilities by the Company.

No allowances for salvage were incorporated into the abandonment and reclamation costs contained in this report.

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COMPETENT PERSON’S REPORT

APPENDIX II

Table 2.1

Canlin Energy Corporation Consolidated

Summary of the Evaluation of the P.& N.G. Reserves As Of Date : 2017-12-31

Net Present Values Before Taxes Remaining Reserves	Net Present Values Before Taxes Remaining Reserves
@ 20.0% @ 15.0% @ 10.0% @ 5.0% @ 0% Company Company Gross
M$ M$ M$ M$ M$ Net Gross 100%
Light and Medium Crude Oil (MBbl) 8897 10155 11764 13759 15887 340.7 368.6 674.5 Proved Developed Producing 32 28 19 1 -33 2.8 2.8 6.6 Proved Developed Non-Producing
8929 10183 11783 13760 15854 343.5 371.4 681.0 Total Proved 1205 1657 2413 3705 5800 100.0 112.4 217.2 Probable Developed Producing 21 25 30 33 30 1.3 1.3 2.9 Probable Developed Non-Producing
1226 1683 2442 3738 5830 101.3 113.7 220.1 Total Probable
10156 11865 14226 17498 21684 444.8 485.1 901.1 Total Proved + Probable Conventional Natural Gas (Solution Gas) (MMcf) 0 0 0 0 0 991 1117 2259 Proved Developed Producing 0 0 0 0 0 14 14 40 Proved Developed Non-Producing
0 0 0 0 0 1004 1131 2299 Total Proved 0 0 0 0 0 339 379 817 Probable Developed Producing 0 0 0 0 0 6 6 17 Probable Developed Non-Producing
0 0 0 0 0 345 385 834 Total Probable
0 0 0 0 0 1349 1516 3133 Total Proved + Probable Conventional Natural Gas (Non Assoc. & Assoc.) (MMcf) 36701 42204 49663 60025 74547 18172 19375 24638 Proved Developed Producing 84 84 80 67 37 79 88 381 Proved Developed Non-Producing -178 2508 6709 13608 25610 9242 9826 11385 Proved Undeveloped
36608 44796 56452 73700 100194 27494 29289 36403 Total Proved 4905 6818 10155 16382 28598 5789 6197 8024 Probable Developed Producing 34 40 48 57 67 24 26 98 Probable Developed Non-Producing -718 2363 7434 16579 35014 11876 12713 13372 Probable Undeveloped
4221 9221 17638 33019 63679 17689 18935 21494 Total Probable
40829 54017 74089 106719 163873 45183 48225 57897 Total Proved + Probable Natural Gas Liquids (MBbl) 0 0 0 0 0 633.6 864.8 1129.7 Proved Developed Producing 0 0 0 0 0 2.8 4.2 17.4 Proved Developed Non-Producing 0 0 0 0 0 368.5 416.4 482.5 Proved Undeveloped
0 0 0 0 0 1004.9 1285.3 1629.6 Total Proved 0 0 0 0 0 224.8 276.9 369.8 Probable Developed Producing 0 0 0 0 0 1.0 1.3 4.7 Probable Developed Non-Producing 0 0 0 0 0 467.4 538.7 566.6 Probable Undeveloped
0 0 0 0 0 693.2 816.9 941.1 Total Probable
0 0 0 0 0 1698.1 2102.2 2570.7 Total Proved + Probable
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COMPETENT PERSON’S REPORT

APPENDIX II

Table 2.1

Canlin Energy Corporation Consolidated

Summary of the Evaluation of the P.& N.G. Reserves As Of Date : 2017-12-31

	Remaining Reserves	Remaining Reserves	Remaining Reserves		Net Present	Values Before Taxes	Values Before Taxes
	Gross	Company	Company	@ 0%	@ 5.0%	@ 10.0%	@ 15.0%	@ 20.0%
	100%	Gross	Net	M$	M$	M$	M$	M$
Grand Total (MBoe) - BTax (M$)
Proved Developed Producing	6287.0	4648.7	4168.1	90434	73784	61427	52359	45598
Proved Developed Non-Producing	94.0	24.0	21.1	4	69	99	112	116
Proved Undeveloped	2380.0	2054.2	1908.9	25610	13608	6709	2508	-178
Total Proved	8761.0	6726.8	6098.1	116049	87460	68235	54979	45537
Probable Developed Producing	2060.4	1485.3	1346.2	34398	20088	12568	8475	6110
Probable Developed Non-Producing	26.8	7.9	7.2	96	90	78	66	55
Probable Undeveloped	2795.3	2657.5	2446.8	35014	16579	7434	2363	-718
Total Probable	4882.5	4150.6	3800.2	69508	36757	20080	10903	5447
Total Proved + Probable	13643.5	10877.4	9898.3	185557	124217	88315	65882	50984

Note: Related product revenues are included with the primary product NPV's (Solution Gas w/Oil, NGL and Sulphur with Oil and Gas)

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COMPETENT PERSON’S REPORT

APPENDIX II

Introduction — Page 1

3. Introduction

3.1 Scope and Terms of Reference

This report was prepared by Sproule Associates Limited (“Sproule”) at the request of Canlin Energy Corporation and MIE Holdings Corporation. Canlin Energy Corporation is hereinafter referred to as "the Company" or “Canlin” and MIE Holdings Corporation is hereinafter referred to as “MIE”, unless otherwise specified. MIE Holdings Corporation owns one hundred percent of the shares of The Company, through its’ wholly owned subsidiary, Maple Marathon Investments Limited. The effective date of this report is January 1, 2018, and it consists of an independent technical evaluation of certain P&NG reserves in the Province of Alberta, Canada. The reserves evaluated include The Company’s interests in the Carrot Creek and Cynthia-Pembina (“Cyn-Pem”) areas.

This Competent Person’s Report (“CPR”) was prepared between March and April 2018 for the purpose of evaluating the Company’s interest in certain P&NG reserves according to the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) reserve definitions that are consistent with the standards of Canadian National Instrument 51-101, which have been accepted by the Hong Kong Stock Exchange as being in accordance with the requirements of Chapter 18 of the Listing Rules of the exchange. This report was prepared for the Company’s corporate purposes.

This report is included in one (1) volume which consists of the following sections: Executive Summary, Introduction, detailed discussion regarding geology, engineering, general business, economic evaluation and social and environment, and our basis of opinion. Various appendices are also included to provide additional support for our work.

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COMPETENT PERSON’S REPORT

APPENDIX II

Introduction — Page 2

3.2 Statement of Competent Persons

Barrett R. (Barry) Hanson, P.Eng., SPEC

I, Barrett R. Hanson, Senior Petroleum Engineer, of Sproule, 900, 140 Fourth Avenue SW, Calgary, Alberta, declare the following:

I hold the following degree:
a. B.Sc., Chemical Engineering (1979), University of Saskatchewan, Saskatoon, Saskatchewan, Canada
I am a registered professional:
a. Professional Engineer (P.Eng.), Province of Alberta, Canada
b. Certified SPE Petroleum Engineer
I am a member of the following professional organizations:
a. Association of Professional Engineers and Geoscientists of Alberta (APEGA)
b. Society of Petroleum Engineers (SPE)
I have 39 years experience in the petroleum industry.
I am a qualified reserves evaluator and reserves auditor as defined in Canadian National Instrument 51-101 and a Competent Person pursuant to Chapter 18 of the Hong Kong Stock Exchange Listing Rules.
My contribution to the report entitled “Independent Competent Person’s Report of Certain P&NG Reserves in Alberta, Canada of Canlin Energy Corporation for MIE Holdings Corporation (As of January 1, 2018)” is based on my engineering knowledge and the data provided to me by the Company, from public sources, and from the non-confidential files of Sproule. I did not undertake a field inspection of the properties.
I have no interest, direct or indirect, nor do I expect to receive any interest, direct or indirect, in the properties described in the above-named report or in the securities of Canlin Energy Corporation or MIE Holdings Corporation in compliance with Chapter 18 of the Hong Kong Stock Exchange Listing Rules.

Barrett R. Hanson, P.Eng., SPEC

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COMPETENT PERSON’S REPORT

APPENDIX II

Introduction — Page 3

Alec Kovaltchouk, P.Geo.

I, Alec Kovaltchouk, VP, Geoscience of Sproule, 900, 140 Fourth Avenue SW, Calgary, Alberta, declare the following:

I hold the following degree:
a. M.Sc. Geochemistry (1981) University of Lviv, Lviv, Ukraine
I am a registered professional:
a. Professional Geoscientist (P.Geo.), Province of Alberta, Canada
I am a member of the following professional organizations:
a. Association of Professional Engineers and Geoscientists of Alberta (APEGA)
b. Canadian Society of Petroleum Geologists (CSPG)
I have 34 years experience in the petroleum industry.
I am a qualified reserves evaluator and reserves auditor as defined in Canadian National Instrument 51-101 and a Competent Person pursuant to Chapter 18 of the Hong Kong Stock Exchange Listing Rules.
My contribution to the report entitled “Independent Competent Person’s Report of Certain P&NG Reserves in Alberta, Canada of Canlin Energy Corporation for MIE Holdings Corporation (As of January 1, 2018)” is based on my engineering knowledge and the data provided to me by the Company, from public sources, and from the non-confidential files of Sproule. I did not undertake a field inspection of the properties.
I have no interest, direct or indirect, nor do I expect to receive any interest, direct or indirect, in the properties described in the above-named report or in the securities of Canlin Energy Corporation or MIE Holdings Corporation in compliance with Chapter 18 of the Hong Kong Stock Exchange Listing Rules.

Alec Kovaltchouk, P.Geo.

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APPENDIX II

Introduction — Page 4

Nora T. Stewart, P.Eng.

I, Nora T. Stewart, Senior VP, Reserves Certification and Director of Sproule, 900, 140 Fourth Avenue SW, Calgary, Alberta, declare the following:

I hold the following degree:
a. B.A.Sc. Civil Engineering (1976) University of Toronto, Toronto ON, Canada
I am a registered professional:
a. Professional Engineer (P.Eng.) Province of Alberta, Canada
b. Professional Engineer (P.Eng.) Province of Ontario, Canada
I am a member of the following professional organizations:
a. Association of Professional Engineers and Geoscientists of Alberta (APEGA)
b. Professional Engineers Ontario (PEO)
c. Society of Petroleum Evaluation Engineers (SPEE)
d. Society of Petroleum Engineers (SPE)
I have 40 years experience in the petroleum industry.
I am a qualified reserves evaluator and reserves auditor as defined in Canadian National Instrument 51-101 and a Competent Person pursuant to Chapter 18 of the Hong Kong Stock Exchange Listing Rules.
My contribution to the report entitled “Independent Competent Person’s Report of Certain P&NG Reserves in Alberta, Canada of Canlin Energy Corporation for MIE Holdings Corporation (As of January 1, 2018)” is based on my engineering knowledge and the data provided to me by the Company, from public sources, and from the non-confidential files of Sproule. I did not undertake a field inspection of the properties.
I have no interest, direct or indirect, nor do I expect to receive any interest, direct or indirect, in the properties described in the above-named report or in the securities of Canlin Energy Corporation or MIE Holdings Corporation in compliance with Chapter 18 of the Hong Kong Stock Exchange Listing Rules.

Nora T. Stewart, P.Eng.

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COMPETENT PERSON’S REPORT

APPENDIX II

Introduction — Page 5

3.3 Credentials of Sproule

Sproule is one of the world’s largest independent subsurface petroleum consulting and evaluation firms with over 65 years of experience in the petroleum industry. Sproule is recognized as a premier reserve evaluator for TSX-listed companies, which file their reserves annually pursuant to Canadian National Instrument 51-101 (“NI 51-101”). In 2016/17, Sproule conducted reserve evaluations for over 60 TSX-listed companies in accordance with NI 51-101 regulations. Sproule also has an active advisory practice providing technical and valuation advice to clients with respect to M&A transactions involving a variety of petroleum assets worldwide. For the second consecutive year, Sproule has won Deloitte’s award for “Best Managed Company”.

3.4 Field Operations

In the preparation of this evaluation, a field inspection of the properties was not performed. The relevant geoscience and engineering data were made available by the Company or obtained from public sources and the non-confidential files at Sproule. No material information regarding the reserves evaluation would have been obtained by an on-site visit.

3.5 Nature and Source of Information

All historical production, revenue and expense data, product prices actually received, and other data that were obtained from the Company or from public sources were accepted as represented, without any further investigation by Sproule.
Property descriptions, details of interests held, and well data, as supplied by the Company, were accepted as represented. No investigation was made into either the legal titles held or any operating agreements in place relating to the subject properties.
Lessor and overriding royalties and other burdens were obtained from the Company. No further investigation was undertaken by Sproule.
A Representation Letter to confirm the accuracy, completeness, and availability of data furnished to Sproule during the preparation of this report was provided by the Company, and is included as Appendix E.
Sproule has no responsibility for estimates based on analyses of erroneous data supplied by the Company or MIE.

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COMPETENT PERSON’S REPORT

APPENDIX II

Introduction — Page 6

Sproule has no responsibility for any results presented that would be affected by information that exists but was not made available to us.
Sproule has no responsibility to update our report for events and circumstances occurring after the preparation date of the report or for data that becomes available to us after the preparation date of the report.

3.6 Reporting Standards

This report has been prepared by Sproule using current geological and engineering knowledge, techniques and computer software. It has been prepared within the Code of Ethics of the Association of Professional Engineers and Geoscientists of Alberta (“APEGA”). This report adheres in all material aspects to the “best practices” recommended in the COGE Handbook which are in accordance with principles and definitions established by the Calgary Chapter of the Society of Petroleum Evaluation Engineers. The COGE Handbook is incorporated by reference in NI 51-101.

3.7 Effective and Preparation Dates

The effective date of the reserves is January 1, 2018. The preparation date of this Competent Person’s Report is April 2, 2018.

3.8 Evaluation Procedures

The Company provided Sproule with lease operating statements containing historical data for twelve months for each of the years 2014 to 2016 and for the first four months for 2017. These statements were used to determine certain economic parameters.
The forecasts of product prices used in this evaluation were based on Sproule’s December 31, 2017 price forecasts.
Abandonment and reclamation costs for existing wells with economic developed reserves, and future economic proposed development have been provided by the Company and included in this report and have both been forecast at the entity level.

The Company has not identified any material dedicated facilities for which abandonment and reclamation costs have been included in this report.

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APPENDIX II

Introduction — Page 7

This report does not include abandonment and reclamation costs associated with active producing wells, which are not economic to produce under the forecast prices utilized in this report, active service wells, inactive wells, and various active or inactive gathering and processing facilities, that the Company holds an interest in, that were not identified as being material dedicated facilities by the Company.

No allowances for salvage were incorporated into the abandonment and reclamation costs contained in this report.

The development forecast presented in this evaluation was based on capital budgets and a development program as presented by the Company under the scope of this evaluation and engagement. The development forecast presented in this report may not represent the full development potential of the lands evaluated.
For this evaluation, Sproule worked on the reserves evaluation model, Value Navigator version 2016.2.0.45. The functionality of the program is not the responsibility of Sproule, and results were accepted as calculated by the model. Sproule’s responsibility is limited to the quality of the data input and reasonableness of the outcoming results.

3.9 Evaluation Results

The analysis of individual properties as reported herein was conducted within the context and scope of an evaluation of a unique group of entities in aggregate. Use of this report outside of this scope may not be appropriate.
The accuracy of reserves estimates and associated economic analysis is, in part, a function of the quality and quantity of available data and of engineering and geological interpretation and judgment. Given the data provided at the time this report was prepared, the estimates presented herein are considered reasonable. However, they should be accepted with the understanding that reservoir and financial performance subsequent to the date of the estimates may necessitate revision. These revisions may be material.
The net present values of the reserves presented in this report simply represent discounted future cash flow values at several discount rates. Though net present values form an integral part of fair market value estimations, without consideration for other economic criteria, they are not to be construed as Sproule’s opinion of fair market value.
The dollar values presented throughout the report are in Canadian dollars, unless otherwise stated.
Due to rounding, certain totals may not be consistent from one presentation to the next.

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COMPETENT PERSON’S REPORT

APPENDIX II

Introduction — Page 8

3.10 Reserve Definitions

The reserve definitions are included in Appendix A.

3.11 Abbreviations

The abbreviations are included in Appendix B.

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COMPETENT PERSON’S REPORT

APPENDIX II

Summary of Assets — Page 1

4. Summary of Assets

4.1 Location of Assets

The evaluated assets are located in west-central Alberta, between 55 and 175 kilometres west of the City of Edmonton. The evaluated assets consist of the Company’s interests in a total of 66,592 acres of gross petroleum and natural gas rights comprised of a number of individual leases. These assets lie on the western edge of the Western Canadian Sedimentary Basin and produce oil and gas from several different formations including the Edmonton, Belly River, Cardium, Second White Specks, Viking, Upper Mannville, Lower Mannville, Ostracod, Jurassic, Blue Sky, Gething, Ellerslie, Notikewin, Rock Creek, Nordegg, Poker Chip and Blueridge formations. From the Company interest lands, light to medium gravity oil is produced mainly from the Cardium and Rock Creek formations, while non-associated gas is produced mainly from the Notikewin, Gething and Rock Creek formations. The oil is recovered under primary production by solution gas drive.

The Carrot Creek area holds mainly gas reserves with associated natural gas liquids, with most wells producing from pools which are described by the provincial regulator as multi-zone commingled pools, although each well may only be producing from one or two zones contained within the commingled pool.

The Cyn-Pem area holds mainly light to medium oil reserves with associated solution gas and natural gas liquids, produced from the Cardium Formation by solution gas drive using artificial lift, all through horizontal wellbores.

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APPENDIX II

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Summary of Assets — Page 2
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Figure 4.1-1 – Location Map – Carrot Creek and Cyn-Pem Areas showing the Company interest lands

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APPENDIX II

Summary of Assets — Page 3

4.2 Ownership and Acreage

Table 4.2-1 provides a summary of the Company’s average working interest, the Project gross (100 percent working interest) acreage and the Company’s net acreage in Carrot Creek and Cyn-Pem areas.

Table 4.2-1 – Summary of Canlin’s Working Interest

Project Gross Developed and Canlin Net Developed Acreage

Area	Canlin Average Working Interest2 (%)	Canlin Gross1 Acreage (acres)	Canlin Net Acreage (acres)
Carrot Creet 71.55 62,072 44,412 Cyn-Pem 45.73 4,520 2,067

Canlin Gross acreage represents the 100 percent working interest acreage
Canlin Average Working Interest is calculated by dividing the Canlin Net Acreage by the Canlin Gross acreage.

The Company also holds lease interests in these areas that are undeveloped which total 27,047 gross and 15,969 net acres in both areas combined, some of which are not assigned reserves.

4.3 Reserves and Net Present Value

Table 4.3-1 provides a summary of the Project gross, Canlin gross and Canlin net proved and proved plus probable reserves and associated net present value before deduction of income taxes using escalated prices and costs, as of January 1, 2018.

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COMPETENT PERSON’S REPORT

APPENDIX II

Summary of the Evaluation of the P.&N.G. Reserves
Canlin Energy Corporation
As Of Date : 2017-12-31
Table 4.3-1
M$
M$
M$
M$
MBbl/MLt
MBbl/MLt
MBbl/MLt
MMcf
MMcf
MMcf
MMcf
MMcf
MMcf
MBbl
MBbl
MBbl
@ 15%
@ 10%
@ 5%
@ 0%
Net
Gross
Reserves
Net
Gross
Reserves
Net
Gross
Reserves
Net
Gross
Reserves
Before Income Taxes
Company Reserves
Remaining
Company Reserves
Remaining
Company Reserves
Remaining
Company Reserves
Remaining
Net Present Values
Natural Gas Liquids / Sulphur
Solution Gas
Non-Assoc, Assoc Gas
Lt, Med, Heavy Oil, Bitumen
Canlin Energy Corporation
52359
61427
73784
90434
633.6
864.8
1129.7
991
1117
2259
18172
19375
24638
340.7
368.6
674.5
PDP
112
99
69
4
2.8
4.2
17.4
14
14
40
79
88
381
2.8
2.8
6.6
PNP
2508
6709
13608
25610
368.5
416.4
482.5
0
0
0
9242
9826
11385
0.0
0.0
0.0
PUD
54979
68235
87460
116049
1004.9
1285.3
1629.6
1004
1131
2299
27494
29289
36403
343.5
371.4
681.0
TP
8475
12568
20088
34398
224.8
276.9
369.8
339
379
817
5789
6197
8024
100.0
112.4
217.2
PADP
66
78
90
96
1.0
1.3
4.7
6
6
17
24
26
98
1.3
1.3
2.9
PANP
2363
7434
16579
35014
467.4
538.7
566.6
0
0
0
11876
12713
13372
0.0
0.0
0.0
PAUD
10903
20080
36757
69508
693.2
816.9
941.1
345
385
834
17689
18935
21494
101.3
113.7
220.1
TPA
65882
88315
124217
185557
1698.1
2102.2
2570.7
1349
1516
3133
45183
48225
57897
444.8
485.1
901.1
TPP
Carrot Creek
43921
51593
62210
76993
610.1
828.5
1065.2
254
268
813
18151
19351
24528
57.5
59.0
171.9
PDP
112
99
69
4
2.8
4.2
17.4
14
14
40
79
88
381
2.8
2.8
6.6
PNP
2508
6709
13608
25610
368.5
416.4
482.5
0
0
0
9242
9826
11385
0.0
0.0
0.0
PUD
46541
58401
75886
102607
981.4
1249.1
1565.0
268
282
853
27473
29265
36294
60.3
61.8
178.5
TP
7405
10938
17476
30172
216.8
266.6
350.3
137
146
418
5776
6182
7956
26.7
28.5
80.3
PADP
66
78
90
96
1.0
1.3
4.7
6
6
17
24
26
98
1.3
1.3
2.9
PANP
2363
7434
16579
35014
467.4
538.7
566.6
0
0
0
11876
12713
13372
0.0
0.0
0.0
PAUD
9833
18450
34145
65283
685.2
806.6
921.7
143
153
435
17676
18920
21425
28.0
29.8
83.2
TPA
56374
76851
110031
167890
1666.6
2055.6
2486.7
411
435
1288
45149
48185
57720
88.3
91.6
261.7
TPP
Cyn Pem
8438
9834
11574
13442
23.5
36.3
64.6
736
849
1446
21
25
109
283.2
309.6
502.6
PDP
1070
1630
2612
4226
8.0
10.3
19.4
202
232
399
13
15
68
73.3
83.9
136.9
PADP
9508
11464
14186
17667
31.5
46.6
84.0
938
1081
1845
34
40
178
356.5
393.5
639.4
TPP

Version : 16.2.0.45
DB : Canlin22221.vndl
Canlin Energy Corporation
Run Time : 18/04/02 10:06
Run By : carolinh
Price : 2017-12-31 SAL Prices
Scenario : NI51-101
Project : 22221 - Report :
D1
Page : 1 of 1

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APPENDIX II

Summary of Assets — Page 4

4.4 Project Gross Field Production Profiles

In July 2017, Carrot Creek was producing approximately 150 bopd at about 55 percent water cut from 15 wells and approximately 13,400 mcfd of raw gas from a further 87 wells.

Cyn-Pem was producing approximately 175 bopd from 18 wells and approximately 750 mcfd of gas from 1 well in July 2017. Production schedules are included in Section 6.4.3. Discussion of the overall development plan is included in Section 6.5.

The Project gross (100 percent working interest) historical production profile for Carrot Creek and CynPem including the total proved production forecast is included in Figures 4.4-1 and 4.4-2 for oil and gas production, respectively.

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2500 100
Calendar Day Oil ‐ bbl/day 90
2000 Average Daily Oil Forecast ‐ 80
bbl/day
70
Watercut
1500 60
50
1000 40
30
500 20
10
0 0
Figure 4.4-1 – Project Gross Production History with Total Proved Oil Production Forecast for Carrot
Creek and Cyn-Pem Assets
Mar‐79 Aug‐81 Jan‐84 Jun‐86 Nov‐88 Apr‐91 Sep‐93 Feb‐96 Jul‐98 Dec‐00 May‐03 Oct‐05 Mar‐08 Aug‐10 Jan‐13 Jun‐15 Nov‐17 Apr‐20 Sep‐22 Feb‐25 Jul‐27 Dec‐29 May‐32 Oct‐34 Mar‐37 Aug‐39
----- End of picture text -----

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APPENDIX II

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Summary of Assets — Page 5
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30000
Calendar Day Gas ‐ Mcf/day
Forecast Average Daily Gas
25000
20000
15000
10000
5000
0
Mar‐79 Jul‐81 Nov‐83 Mar‐86 Jul‐88 Nov‐90 Mar‐93 Jul‐95 Nov‐97 Mar‐00 Jul‐02 Nov‐04 Mar‐07 Jul‐09 Nov‐11 Mar‐14 Jul‐16 Nov‐18 Mar‐21 Jul‐23 Nov‐25 Mar‐28 Jul‐30 Nov‐32 Mar‐35 Jul‐37 Nov‐39
----- End of picture text -----

Figure 4.4-2 - Project Gross Production History with Total Proved Gas Production Forecast for Carrot Creek and Cyn-Pem Assets

Figures 4.4-3 and 4.4-4 shows the Project gross (100 percent working interest) historical production profile for Carrot Creek and Cyn-Pem including the total proved plus probable reserve oil and gas production forecasts, respectively.

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2500 100
Calendar Day Oil ‐ bbl/day 90
2000 80
Average Daily Oil Forecast ‐
bbl/day 70
Watercut
1500 60
50
1000 40
30
500 20
10
0 0
Figure 4.4-3 – Project Gross Production History with Total Proved Plus Probable Oil Production Forecast
for Carrot Creek and Cyn-Pem Assets
Mar‐79 Nov‐81 Jul‐84 Mar‐87 Nov‐89 Jul‐92 Mar‐95 Nov‐97 Jul‐00 Mar‐03 Nov‐05 Jul‐08 Mar‐11 Nov‐13 Jul‐16 Mar‐19 Nov‐21 Jul‐24 Mar‐27 Nov‐29 Jul‐32 Mar‐35 Nov‐37 Jul‐40 Mar‐43 Nov‐45
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APPENDIX II

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Summary of Assets — Page 6
30000
Calendar Day Gas ‐ Mcf/day
Forecast Average Daily Gas
25000
20000
15000
10000
5000
0
Mar‐79 Oct‐81 May‐84 Dec‐86 Jul‐89 Feb‐92 Sep‐94 Apr‐97 Nov‐99 Jun‐02 Jan‐05 Aug‐07 Mar‐10 Oct‐12 May‐15 Dec‐17 Jul‐20 Feb‐23 Sep‐25 Apr‐28 Nov‐30 Jun‐33 Jan‐36 Aug‐38 Mar‐41 Oct‐43 May‐46
----- End of picture text -----

Figure 4.4-4 – Project Gross Production History with Total Proved Plus Probable Gas Production Forecast for Carrot Creek and Cyn-Pem Assets

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APPENDIX II

Regional Geological and Engineering Discussion — Page 1

5. Regional Geological Discussion

5.1 Regional Petroleum History

(Significant portions of this section have been copied directly from Reference 1)

The Western Canada Sedimentary Basin (“WCSB”) comprises the eastern Canadian Cordillera and two major sedimentary basins: a northwest-trending trough in front of the Cordilleran Fold and Thrust Belt (extending eastward to the Canadian Shield) called the Alberta Basin; and the cratonic Williston Basin, centered in North Dakota and extending into southern Saskatchewan and southwest Manitoba.

The Carrot Creek and Cyn-Pem areas generally lie within the Central Plains depositional region (part of the Alberta Basin) of the WCSB. The Alberta Basin is a large, petroleum-rich sedimentary basin along the eastern edge of the Rocky Mountains in western Canada. It extends from British Columbia through Alberta and Saskatchewan into Manitoba. The basin was formed when the Earth’s crust sank along the continental side of the Rocky Mountains during the Devonian Period (about 415 to 360 million years ago). From that time until the Late Cretaceous Period (about 100 to 65 million years ago), the region was covered by the sea at various intervals. Marine sediments gradually accumulated in the deepest parts of the basin, and large reefs composed of marine fossils and algae formed along its margins. Uplift of the region beginning about 65 million years ago halted sedimentation and exposed the basin deposits to erosional forces.

The formation of the Rocky Mountains’ fold and thrust belt had a profound effect on Alberta's hydrocarbon potential by producing the structural traps, some of which are filled or partially filled with hydrocarbons, mainly gas. In the Alberta Basin, tectonic loading depressed the western edge of the North American craton and resulted in a regional westward dip, which inclined the stratigraphic traps into a favourable orientation so that they could be filled with hydrocarbons generated farther west.

5.2 Regional and Basin Generalized Geology, Evident Petroleum System

The Carrot Creek and Cyn-Pem areas produce from multiple oil and gas bearing sands of Upper Cretaceous to Jurassic age. Productive formations in the area are the Upper Cretaceous Cardium and Viking formations of the Colorado Group, Lower Cretaceous Notikewin, Wilrich, and Gething/Ellerslie formations of the Mannville equivalent of the Fort St John Group, and the Jurassic Rock Creek Formation.

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APPENDIX II

Regional Geological and Engineering Discussion — Page 2

5.2.1 Geological Settings

The distribution of shales, generally acting as both source rocks and cap rocks, and reservoir rocks of different lithology in the Southern Plains, the Central Plains, North Central Mountains and Foothills and Northwest Plains regions of Alberta are displayed on the stratigraphic column shown in Figure 5.2.1-1.

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Figure 5.2.1-1 Stratigraphic Correlation Chart of Western Alberta

5.2.1.1 Jurassic Rock Creek Member

(Significant portions of this section have been copied directly from Reference 2)

The Jurassic and lowest Cretaceous sedimentary rocks form significant oil and gas reservoirs in central and southern Alberta and southwestern Saskatchewan, and some are hydrocarbon source rocks in Western Canada. Jurassic rocks occur in three major epicratonic depositional settings: on western parts of

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APPENDIX II

Regional Geological and Engineering Discussion — Page 3

the pre-orogenic, essentially stable cratonic platform or shelf; in the succeeding foreland trough or foredeep superimposed on the same area - the Rocky Mountain Trough; and in the Williston Basin.

In west-central and southwestern Alberta and southeastern British Columbia, shallow-marine shelf sandstone and shale cycles were deposited in the Aalenian and Bajocian Rock Creek Member. The lateral variations in the lithologies and thicknesses of the Rock Creek suggest local differences in paleotopography, depositional mechanisms and perhaps subsidence. Tidal reworking of some of the Rock Creek sands has been interpreted (Stronach, 1984)[3] .

The Bajocian Rock Creek Member, with the blocky log character and abrupt base, is a typical quartzose sandstone unit of much of west-central Alberta, but in many places several sandstones are interbedded with units of siltstone, shale and bivalve coquinas, and the base varies from abrupt to gradational (Marion, 1984; Losert, 1986)[4,5] . Some, at least, of the shale interbeds near its eastern edge yield Aalenian palynomorphs and are probably easterly derived arenaceous facies equivalents of the Poker Chip Shale.

In west-central Alberta, the multiple Lower Bajocian sandstones and shales of the Rock Creek Member gradually thicken westward to over 30 metres in the subsurface. They are in part equivalent to the lower Highwood shale of southwestern Alberta. Their northern boundary coincides approximately with the northern limit of the underlying Nordegg carbonate facies. Upper parts of the underlying Poker Chip Shale comprise western equivalents of the lower Rock Creek Member west of Edmonton. South of Calgary, the single Rock Creek sandstone unit exceeds 10 metres in thickness in outcrop. Equivalent strata are absent over the Sweetgrass Arch.

5.2.1.2 Cretaceous Mannville Group

(Significant portions of this section have been copied directly from Reference 6)

The Mannville Group and equivalent strata comprise the oldest Cretaceous rocks over most of the Western Canada Sedimentary Basin and represent a major episode of subsidence and sedimentation following a long period of uplift, exposure and erosion of older strata. Throughout the text all strata within the generally unconformity-bounded interval are referred to as the Mannville. Precise age determinations are difficult to make because most fossiliferous marine strata are restricted to the northern part of the basin, and index fossils are rare in the continental to brackish sections farther south. Mannville strata blanket the entire basin, ranging from less than 40 m thick in some areas of the plains to more than 700 m thick in the Rocky Mountain Foothills. The section is erosionally truncated along its eastern and northeastern limits. Mannville strata are not mapped as a distinct unit in northwestern Alberta and north eastern British Columbia, where they grade into marine shales that cannot be readily distinguished from younger and older marine strata.

Mannville deposition took place over a profound unconformity surface that truncates strata ranging from lowermost Cretaceous in the foothills to lower Paleozoic at the eastern margin of the basin. Huge valley systems that cut into the unconformity surface influenced sedimentation patterns of the entire Mannville, as

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discussed below. Although it has been suggested that relief on the unconformity was controlled by tectonic factors (e.g., Christopher, 1984)[7] , Cant and Stockmal (1989)[8] considered that differential erosion of dipping Paleozoic carbonate units also may have influenced valley and highland formation across the central plains.

Enormous reserves of coal, natural gas, and conventional and heavy oils are found in the Mannville. Oil and gas are trapped in numerous fluvial and valley-fill reservoir sandstones in the south, and in more regionally extensive shoreline sandstone complexes throughout northern and central regions. The latter category includes the giant heavy oil and oil sands accumulations of Alberta and Saskatchewan.

5.2.1.3 Cretaceous Colorado Group

(Significant portions of this section have been copied directly from Reference 9)

The Albian to Santonian Colorado Group was deposited within the Western Canada Foreland Basin during an approximate 25 to 30 million year period. Global sea level was high during this time, with specific sealevel maxima in the Late Albian, Early Turonian and Middle Santonian (Caldwell, 1984; Haq et al., 1987)[10,11] . Deposition at this time was also coincident with a regional tectonic downflexing of the North American craton (Lambeck et al., 1987)[12] . The major marine inundations were separated by four major regressive pulses represented by the Peace River-Viking, Dunvegan, Cardium-Bad Heart and Milk River formations. During the high stands, warm Tethyan water from the Gulf of Mexico mixed with the cooler boreal water extending south from the Arctic to form a shallow epeiric seaway.

The Colorado Group contains several sandstone and conglomerate units, some of which are prolific hydrocarbon producers. These include, in ascending order, the Basal Colorado Sandstone, Spinney Hill Sandstone, Viking Formation, St. Walburg Sandstone, Barons Sandstone, Dunvegan Formation, sandstones of the lower Kaskapau Formation (Doe Creek Member), sandstones of the Second White Speckled Shale (the Phillips Sandstone), Cardium Formation, the Medicine Hat Sandstone and the Alder son Member of the Lea Park Formation. Within the Colorado Group, the First and Second White Speckled Shales, the Fish Scales Zone, and shale at the base of the Shaftesbury Formation are more radioactive than overlying and underlying shales, have high total organic carbon contents, and have considerable hydrocarbon generating potential. An interval such as the Second White Speckled Shale is potentially both a source and a reservoir rock for hydrocarbons.

The Colorado Group thins eastward from about 700m in south western Alberta to 200m in the Manitoba Escarpment. In northwest Alberta, the Colorado Group exceeds 1500m in thickness where it overlies the Peace River Arch, which was subsiding during much of the Cretaceous. Regional cross sections constructed across the basin show the eastward thinning of the Colorado Group away from the Cordillera, with maximum thickening occurring in the northwest. The distribution of the Harmon, Cadotte and Paddy members is restricted to the general vicinity of the Peace River Arch where the Joli Fou Formation is absent.

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5.2.2 Source Rocks

(Significant portions of this section have been copied directly from Reference 13)

To facilitate discussion of petroleum in the Western Canada Sedimentary Basin, a petroleum system terminology is used. According to Magoon (1988)[14] , "a petroleum system includes all those geologic elements and processes that are essential for an oil and gas deposit to exist." These basic elements include source rock, maturation, migration path, reservoir rock, trap, and seal. The WCSB comprises a number of discrete petroleum systems linked to a number of source rocks. Each petroleum system is named after the source rock, where possible, and the limits of the system are defined by the extent of migration of petroleum from that discrete source.

The following petroleum systems are present within the WCSB:

Ordovician Petroleum System with generally thin source facies of “kukersites”;
Keg River/Brightholme Petroleum System with the source facies of a basinal, marine laminate;
Duvernay Petroleum System with the source facies of bituminous, slightly argillaceous carbonates interbedded with gray-green, calcareous shales;
Exshaw-Bakken and Lodgepole Petroleum Systems with the source facies of organic-rich, black, basinal laminites;
Doig Petroleum System with phosphatic and radioactive facies;
Nordegg Jurassic Petroleum System with variably phosphatic marlstone and calcareous mudstone;
Mannville Petroleum System with the coal rich deposits;
Colorado Group Petroleum System with a thick marine shale succession.

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6. Local Geological and Engineering Discussion

6.1 Reserves

Table 6.1-1 provides a summary of the proved and proved plus probable reserves attributed to the Company’s interests in the Carrot Creek and Cyn-Pem areas at the effective date of the report, January 1, 2018.

Table 6.1-1 Summary of Oil, Gas and NGL Reserves as of January 1, 2018

(Forecast Prices and Costs)

Reserve Category	Oil	Oil	Gas	Gas	NGL	NGL
	Gross (Mstb)	Net (Mstb)	Gross (MMcf)	Net (MMcf)	Gross (Mstb)	Net (Mstb)
Carrot Creek and Cyn-Pem
Total Proved Total Proved Plus Probable	371.4 343.5 485.1 444.8		30,420 28,498 49,741 46,532		1,285.3 1,004.9 2,070.7 1,672.7

6.2 Rights to Explore and Extract Hydrocarbons

The details of the P&NG rights are summarized in Section 8.2.2.

6.3 Geology

Figures 6.3-1 and 6.3-2 show a detailed view of the Company’s interest lands within the Carrot Creek and Cyn-Pem areas, respectively, showing location of the Company’s interest wells and wells owned by others on adjacent lands.

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Figure 6.3-1 – Map of the Company’s Interest Lands in the Carrot Creek area and wells in the area. Canlin interest wells are bold.

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Figure 6.3-2 – Map of the Company’s Interest Lands in the Cyn-Pem area showing wells in, and adjacent to the Canlin interest lands.

6.3.1 Geological Characteristics

The geological maps contained in this section were prepared by Canlin and have not been audited by Sproule, not have they been used in the evaluation. They are provided herein for illustrative purposes only.

6.3.1.1 Cardium Formation

(Significant portions of this section have been copied directly from Reference 15)

The Cardium formation is comprised of a series of coarsening upward shallow marine shoreface sands, deposited with a north-south regional trend, deposited within the Western Interior Seaway. Reservoir quality is highly variable with grain size ranging from conglomerate to siltstone. Sediment was sourced via rapid influx from the west.

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Figure 6.3.1.1 – Carrot Creek and Cyn-Pem Areas – Cardium Formation Net Pay showing 1 meter sandstone contours, based on cutoffs of 75 gamma API units and 6% porosity in red and the pay edges in black, and 4 meter conglomerate contours, based on a cutoff of 3% porosity in purple.(Source: Canlin)

6.3.1.2 Notikewin Formation

(Significant portions of this section have been copied directly from Reference 3)

The Notikewin is comprised of a series of stacked fluvial to fluvio-deltaic channel sands, within a northsouth trending, structurally influenced depositional complex, in the Upper Cretaceous Mannville Group. Reservoir quality is highly variable due to the presence/absence of secondary cementation formed during the burial process, hence supporting the need for horizontal development for optimal reservoir exploitation .

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Figure 6.3.1.2 – Carrot Creek Area – Notikewin Formation porosity thickness in 4.16 %-meter contour interval based on cutoffs of 75 gamma API units and 6% porosity. (Source: Canlin)

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6.3.1.3 Wilrich Formation

(Portions of this section have been copied directly from Reference 16)

The Wilrich Formation in the Carrot Creek area is composed of shales and sands deposited during the overall southward transgression of the Boreal Sea. The formation was deposited as part of a laterally extensive, NE trending prograding marine shoreface complex. Coeval, during mini regressions, south-north trending channels entered the basin reworking existing sediment and depositing fluvial influenced channel facies. Porosities range from 3 to 8 percent and permeability’s in the range of 0.01 to 0.1 milliDarcies. The Upper Wilrich shoreface sands and channel sands are currently the primary target for horizontal well development drilling programs across the area. The Wilrich in this area does not contribute significant production at the present but offers significant upside potential.

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Figure Figure 6.3.1.3 – Carrot Creek Area - Wilrich Formation porosity thickness in 10 percent- meter contour intervals based on cutoffs of 75 gamma API units and 6% porosity with red shaded areas representing possible channelized sands. (Source: Canlin)

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6.3.1.4 Gething/Ellerslie Formation

The Gething (Ellerslie) is comprised of a series of stacked fluvial and tidally influenced channel sands, deposited within a north-south trending, structurally confined valley complex, in the Lower Cretaceous Mannville Group. Reservoir quality is highly variable within the channel trends, hence horizontal well length allows for larger sample of the reservoir and is key to economic exploitation. Primary risk associated with the horizontal development of this reservoir is mainly associated to the potential of encountering laterally discontinuous, lower permeability sandstone bodies. Mitigation of this risk is provided through high resolution geological mapping using 3D seismic data character modeling in support of planning horizontal drill paths, accompanied by reservoir pressure data from offsetting producing wells when available.

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Figure 6.3.1.4 – Carrot Creek Area - Gething Formation Net Pay in 5 meter contour intervals based on cutoffs of 75 gamma API units and 6% porosity. (Source: Canlin)

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6.3.1.5 Rock Creek

The Rock Creek is comprised of multiple, stacked platform shallow shelf marine sands and muds, separated by a series of disconformable surfaces. Three of these disconformable surfaces have been locally mapped and presents drill opportunities targeting the ‘Middle’ and ‘Basal’ Rock Creek formations. The ‘Middle’ Rock Creek Formation is believed to be a laterally extensive NW-SE trending sandbody. The Basal Rock Creek Formation becomes more developed on the West side of the Carrot Creek area.

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Figure 6.3.1.5-1 – Carrot Creek Area– Upper Rock Creek Net Pay in 2 metre contour intervals, assuming cutoffs of 75 gamma API units, 6% porosity and 10 ohm resistivity, showing the erosional edge in dashed red lines. (Source: Canlin)

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Figure 6.3.1.5-2 – Carrot Creek Area – Middle Rock Creek Net Pay in 2 meter contour intervals based on cutoffs of of 75 gamma API units and 6% porosity. (Source: Canlin)

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Figure 6.3.1.5-3 – Carrot Creek Area - Lower Rock Creek Net Pay in 2 meter contour intervals based on cutoffs of of 75 gamma API units and 6% porosity. (Source: Canlin)

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6.3.2 Reservoir Characteristics

The average reservoir parameters of each of the major horizons within the Carrot Creek and Cyn-Pem areas are summarized in Table 6.3.2-1. Note the Wilrich Formation has not been included on this table due to the low contribution of the formation to current production.

Table 6.3.2-1 Reservoir Parameters of the Main Reservoirs – Carrot Creek and Cyn-Pem Areas

	Formation		Thickness	Porosity	Permeability		Recovery
	Cardium		3-8m	6-9%	0.1-1mD	9.5-21MPA	Primary
	Notikewin	Up to 25m gross(individual beds are 6-8m)		8-16%	0.1-1mD	18.5MPA	Primary
Gething/Ellerslie		9-20m		8-18%	1-20mD	15.0mPa	Primary
Rock Creek		4-6m Per bed 25m gross stacked		4-8%	0.1-1mD	18-19.5Mpa	Primary

6.3.3 Exploration

The lands surrounding the Carrot Creek and Cyn-Pem areas are very well developed for oil and gas production. As a result there has been no exploration activity conducted by the Company in either of these areas. Development activities have targeted known hydrocarbon reservoirs.

6.4 Production

6.4.1 Production Commencement

Production from the lands currently held by the Company in the Carrot Creek area commenced in 1981. Production from the Cardium Formation in the Carrot Creek area has been on-going since 1963.

Production from the Company lands in Cyn-Pem commenced in 1979. Production from the Cardium Formation in the Cyn-Pem area has been ongoing since 1962.

6.4.2 Extraction Methods

The Carrot Creek area has been developed in the past with vertical wells on primary depletion. There is water within the reservoir systems, but it has not exhibited the characteristics of active or large water zone pressure support. Some of the tighter formations, such as the Notikewin Formation are being developed with horizontal wells to maximize access in the wellbore to reservoir areas without secondary cementation.

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The Cardium Formation in the Cyn-Pem area was initially developed with vertical wells on primary depletion. The Cardium Sand is very wide spread through-out this region of the Province of Alberta and in general has been the subject of various EOR schemes due to the tight nature of most of the sands. Horizontal drilling in the Cardium Formation with single stage fracture treatments has been taking place since approximately 2000, developing into tighter spacing and multistage fracture treatments since the late 2000s to early 2010s as it was found the drainage radius of older wells was limited.

6.4.3 Production Schedule

Table 6.4.3-1 shows the Project gross (100 percent working interest) proved and proved plus probable production schedule for the combined Carrot Creek and Cyn-Pem areas.

Table 6.4.3-1 – Summary of Project Gross Total Proved Production Forecasts

		Project Gross1 Production Forecasts	Project Gross1 Production Forecasts	Project Gross1 Production Forecasts	Project Gross1 Production Forecasts	Project Gross1 Production Forecasts	Project Gross1 Production Forecasts	Project Gross1 Production Forecasts
		Carrot Creek and Cyn-Pem Areas
Reserves Category		Proved
Year		Daily Production Volumes				Production Volume
	Oil	Raw Gas	Condensate	Barrel of Oil Equivalent	Oil	Raw Gas	Condensate	Barrel of Oil Equivalent
	bpd	mcfd	bpd	boepd	mbbls	mmcf	mbbls	mbbls
2018	251 218 188 165 146 129 114 102 92 83 74 68 61 51 44 39 33 4 0 0 0 0	12484 14737 15883 11532 9406 7977 6889 5948 5224 4620 4015 3492 3039 2686 2364 2067 1821 1486 542 503 468 436	110 133 146 105 85 72 62 54 47 42 36 32 28 25 22 19 17 14 5 5 5 4	2441.6 2806.9 2981.4 2192.2 1798.6 1530.2 1324.3 1147.6 1010.5 895.3 780.1 681.6 594.8 523.2 460.0 402.4 352.8 266.3 95.6 88.7 82.5 77.0	91.6 79.4 68.9 60.4 53.2 46.9 41.7 37.4 33.7 30.4 27.3 24.8 22.2 18.6 16.2 14.2 11.9 1.5 0.0 0.0 0.0 0.0	4557 5379 5813 4209 3433 2912 2521 2171 1907 1686 1469 1274 1109 980 865 755 665 542 198 184 171 159	40.1 48.6 53.4 38.3 31.1 26.3 22.8 19.7 17.3 15.3 13.4 11.6 10.1 9.0 7.9 6.9 6.1 5.2 1.9 1.8 1.7 1.5	891.2 1024.5 1091.2 800.2 656.5 558.5 484.7 418.9 368.8 326.8 285.5 248.8 217.1 191.0 168.4 146.9 128.8 97.2 35.0 32.4 30.1 28.1
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
Total					680.4	42961	389.9	8230.4

Project Gross means 100 percent interest.
Barrel of oil equivalent of gas uses a conversion ration of 6 Mcf:1 bbl.

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Table 6.4.3-2 – Summary of Project Gross Total Proved + Probable Production Forecasts

Table 6.4.3-2 – Summary of Project Gross Total Proved + Probable Production Forecasts	Table 6.4.3-2 – Summary of Project Gross Total Proved + Probable Production Forecasts	Table 6.4.3-2 – Summary of Project Gross Total Proved + Probable Production Forecasts	Table 6.4.3-2 – Summary of Project Gross Total Proved + Probable Production Forecasts	Table 6.4.3-2 – Summary of Project Gross Total Proved + Probable Production Forecasts	Table 6.4.3-2 – Summary of Project Gross Total Proved + Probable Production Forecasts	Table 6.4.3-2 – Summary of Project Gross Total Proved + Probable Production Forecasts	Table 6.4.3-2 – Summary of Project Gross Total Proved + Probable Production Forecasts	Table 6.4.3-2 – Summary of Project Gross Total Proved + Probable Production Forecasts

		Project Gross1 Production Forecasts
		Carrot Creek and Cyn-Pem Areas
Reserves Category		Proved +			Probable
Year		Daily Production Volumes				Production Volume
	Oil	Raw Gas	Condensate	Barrel of Oil Equivalent	Oil	Raw Gas	Condensate	Barrel of Oil Equivalent
	bpd	mcfd	bpd	boepd	mbbls	mmcf	mbbls	mbbls
2018	258 230 205 184 166 151 137 126 115 106 98 91 85 80 75 68 62 53 48 41 38 35 8 7 0 0 0 0 0 0	13799 20507 21929 16651 13276 11312 9901 8750 7847 7088 6403 5759 5171 4699 4292 3881 3497 3149 2899 2598 2356 2130 1885 1732 698 656 618 583 550 498	122 188 203 154 122 103 90 80 71 64 58 52 47 43 39 35 32 29 27 24 22 20 18 17 7 6 6 6 5 5	2680.2 3836.6 4063.7 3112.3 2500.2 2139.8 1877.9 1663.7 1493.8 1351.6 1223.0 1103.0 994.0 905.5 828.9 750.4 676.4 607.1 558.1 497.6 452.1 409.5 340.2 312.3 123.2 115.8 109.0 102.8 97.0 87.9	94.3 84.0 75.2 67.0 60.5 55.2 50.3 45.9 41.8 38.7 35.7 33.2 31.0 29.1 27.3 25.0 22.5 19.4 17.7 14.9 13.8 12.7 2.9 2.5 0.0 0.0 0.0 0.0 0.0 0.0	5037 7485 8026 6078 4846 4129 3624 3194 2864 2587 2344 2102 1888 1715 1571 1416 1276 1149 1061 948 860 778 690 632 255 240 226 213 201 182	44.6 68.8 74.4 56.0 44.4 37.7 33.0 29.1 26.0 23.5 21.3 19.1 17.2 15.6 14.2 12.8 11.6 10.6 9.8 8.8 7.9 7.2 6.6 6.1 2.5 2.3 2.2 2.1 1.9 1.8	978.3 1400.3 1487.3 1136.0 912.6 781.0 687.3 607.2 545.2 493.3 447.6 402.6 362.8 330.5 303.4 273.9 246.9 221.6 204.3 181.6 165.0 149.5 124.5 114.0 45.0 42.3 39.9 37.5 35.4 32.1
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047

Total					900.7	67615	619.1	12788.9

Project Gross means 100 percent interest.
Barrel of oil equivalent of gas uses a conversion ration of 6 Mcf:1 bbl

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6.5 Overall Development Plan

The Company owns and operates a gas plant within the Carrot Creek area with backup processing capacity available from other operators in the area, all interconnected by existing infrastructure. Figure 6.5.1 shows the existing infrastructure owned or accessible by the Company to process and transport gas production to market. The Company anticipates the infrastructure will be suitable to handle their production volumes until field depletion and abandonment, with modifications as necessary to manage declining production volumes.

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Figure 6.5.1 – Carrot Creek and Cyn-Pem areas – Canlin owned or accessible infrastructure.

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The development plan for the Carrot Creek Field is focused on development drilling within existing pools where offsetting production has indicated sufficient additional potential exists to justify capital expenditures. All undeveloped locations will be horizontal and of one mile in length or slightly less as necessary to conform to offset spacing regulations and will be multi-stage fracture stimulated.

Table 6.5-1 – Summary of Undeveloped Well Locations by Formation – Carrot Creek Area

Field	Formation	Undeveloped Well Locations	Undeveloped Well Locations
		1P	2P
Carrot Creek	Notikewin	3 2 7	3 2 9
	Rock Creek
	Gething
	Total	12	14

Tables 6.5-1 shows only the formations where undeveloped well locations have been assigned. The development forecast presented in this evaluation was based on capital budgets and a development program as presented by the Company under the scope of this evaluation and engagement. The development forecast presented in this report may not represent the full development potential of the lands evaluated.

Table 6.5-2 summarizes the timing and number of undeveloped well locations forecast to be drilled by year.

Table 6.5-2 – Timing of Undeveloped Well Locations by Year

	2018	2019	2020
Proved	2 8 2 4 8 2
Proved Plus Probable

6.6 Methods of Estimation

The technically recoverable oil and gas volumes from all developed wells were estimated from production decline curve analyses (DCA) where sufficient data was available to establish production trends. The technical recoverable volumes for undeveloped wells and wells with short production histories were estimated by analogy or a combination of volumetrically and analogy, comparing to other wells in the same formation in the general area.

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Local Geological and Engineering Discussion — Page 17

6.6.1. Decline Curve Analysis Estimation Method

DCA was completed on all producing and non-producing oil and gas wells with significant history to estimate the recoverable volumes. Production up to July 31, 2017 was reviewed on an individual well basis. Nonproducing wells with assigned reserves were scheduled based on capital budgets and a development program as presented by the Company under the scope of this evaluation and engagement. The DCA results were considered reasonable considering other analytical techniques.

6.6.2 Analogy Estimation Method

Analogy estimation was completed on all undeveloped gas wells in the Carrot Creek area. The initial rate and ultimate recovery of all wells completed and produced from the same formation as that targeted by the undeveloped well within the general area were reviewed. The average rate and recovered volumes of the wells reviewed were used to estimate the production profile for the undeveloped locations. Some adjustments to the volumes were made where an existing producer in the immediate vicinity of the undeveloped location demonstrated better than the average rate and recovery for that formation in the area. In areas where the zone was reasonably well developed, the ultimate gas-originally-in-place and ultimate recovery factors were assessed at a high level to ensure reasonableness. Further adjustments to volumes were made based on variations in volumetric parameters in the vicinity of the target locations.

For the Notikewin Formation, the estimated ultimate recovery (“EUR”) for the undeveloped locations was 2.05 and 2.55 Bcf for the proved and proved plus probable cases, respectively, with an increase for one location to 3.2 and 4.0 Bcf.

The EUR for the Rock Creek Formation undeveloped locations was estimated at 1.9 and 2.4 Bcf for the proved and proved plus probable cases, respectively.

The EUR for the Gething Formation locations were estimated between a low of 0.67 and 0.83 Bcf to a high of 2.20 and 2.85 BCF, for proved and proved plus probable cases respectively, all based on volumetric estimates on a well by well basis and the performance of offsetting existing producers, both vertical and horizontal.

6.6.3 Volumetric Estimation Method

Undeveloped Gething Formation locations EURs were estimated by volumetrics using net pays derived from mapping based of other Gething Formation well penetrations in the area. Estimates of porosity and water saturation were obtained from the interpretation of well logs from the existing well penetrations. Recovery factors were estimated at 75 to 85 percent, for proved and proved plus probable cases, based on decline analysis of currently producing wells, however, drainage areas were adjusted based on the

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Local Geological and Engineering Discussion — Page 18

performance of adjacent producers in the same formation, without encroaching on the adjacent producers’ interpreted drainage area.

6.7 Volumes of Sales Products

Forecasts of technical volumes of gas were converted to sales volumes for reserves determination by applying a gas surface loss of 9.5 percent for the Carrot Creek area and 15 percent for the Cyn-Pem area to account for gas volumes used for fuel and flare and shrinkage due to the removal of gas by-products.

Volumes of gas sold in Western Canada are transacted on the basis of heat content of the gas. The actual gas sales revenues and volumes from the revenue statements were analyzed and compared to the actual posted sales price at the AECO-C sales hub to estimate the apparent heat content of the gas as sold. Sproule derived a sales volume heat content of 1135 BTU/scf for gas from the Carrot Creek area and 1000 BTU/scf for the Cyn-Pem area.

The Company’s proved and probable by-product reserves and production forecasts were based on the recovery rates determined from revenue statements (barrels per MMcf of natural gas) or from natural gas compositional analysis and the natural gas reserves and production forecasts. Condensate volumes were estimated by applying a constant condensate-gas ratio against all producing gas wells to be consistent with the product yield interpreted from the revenue statements. The yields of the respective by-products for the two areas are presented in the Table 6.7-1 below.

Table 6.7-1 – Gas By-Product Yields from Sales Gas Volumes

Product	Sales Gas Yield (bbls/MMcf)	Sales Gas Yield (bbls/MMcf)
	Carrot Creek	Cyn-Pem
C2- Ethane	0.15 0.00 7.50 4.60 10.90 16.00 10.10 14.70 9.701 0.00
C3-Propane
C4-Butane
C5+-Pentanes plus
Condensate1

Condensate yield only established on raw gas volumes

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APPENDIX II

General Business Discussion — Page 1

7. General Business Discussion

7.1 General Description of the Company

Canlin Energy Corporation is a medium to large size petroleum and natural gas company with producing assets located throughout the Western Canada Sedimentary Basin, extending east into the north end of the Williston Basin. The assets owned by Canlin are generally of a mature state, with production from some wells having commenced in the 1950’s.

7.2 Statement of Long Term Prospects

The Company’s broad base of mineral rights has given them the opportunity to participate in a number of developing oil and gas plays in Western Canada that have occurred due to the technological development of multi-stage fracture stimulations in horizontal wellbores. The highest profile play at the current time being in the Montney Formation. The number of potential drilling locations that the Company has identified on their current land holdings allows them to plan development activity well beyond the time period allowed for the booking of proved and proved plus probable undeveloped reserves under NI 51-101.

7.3 Assessment of Technical Staff

Canlin operates many of their properties throughout Western Canada and has very experienced and qualified technical and operations staff. Canlin has conducted on-shore drilling programs with very challenging and complex geological conditions and has demonstrated their capability to adequately handle them safely and within budget. The management team in Calgary provides guidance and oversight on all upstream activities.

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Economic Evaluation Discussion — Page 1

8. Economic Evaluation Discussion

8.1 Discounted Net Present Values

The net present values of the reserves are presented in millions of Canadian dollars and are based on annual projections of the future net revenue. Table 8.1-1 summarizes the net present values of Canlin’s assets at various discount rates before deduction of income taxes.

Table 8.1-1 – Summary of Net Present Value Before Income Taxes

Table 8.1-1 – Summary of Net Present Value Before Income Taxes	Table 8.1-1 – Summary of Net Present Value Before Income Taxes	Table 8.1-1 – Summary of Net Present Value Before Income Taxes	Table 8.1-1 – Summary of Net Present Value Before Income Taxes	Table 8.1-1 – Summary of Net Present Value Before Income Taxes	Table 8.1-1 – Summary of Net Present Value Before Income Taxes
As of January 1, 2018(Forecast Prices and Costs)
Reserves Category	Canlin Net Present Values of Future Net Revenue
	Before Income Taxes Discounted at(%/Year)
	0 (MM$Cdn)	5 (MM$Cdn)	10 (MM$Cdn)	15 (MM$Cdn)	20 (MM$Cdn)
Alberta, Canada Total Proved Total Proved Plus Probable	116.0 87.5 68.2 55.0 45.5 185.6 124.2 88.3 65.9 51.0

8.2 Fiscal Terms

8.2.1 Ownership

The Company’s interests in the petroleum and natural gas leases in the Carrot Creek area varies from a 15 percent gross overriding royalty interest up to 100 percent working interest. The Company’s average working interest in the evaluated lands is 71.55 percent.

The Company’s interests in the Cyn-Pem area varies from 34.153 percent to 69.70 percent working interest, averaging 45.73 percent.

The working interest lands are subject to Crown lessor royalties, with some lands burdened by an additional overriding royalty.

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Economic Evaluation Discussion — Page 2

8.2.2 Petroleum and Natural Gas Leases, Royalties and Taxes

The Province of Alberta in Canada, as representative of the Crown, owns the majority of the mineral rights on lands within its’ borders. The Province administers the rights to Petroleum and Natural Gas through a tenure system where the right to develop and produce the respective commodity is granted to a lessee. The details of the system are described by the Province on their website (Reference 8) as follows:

The tenure system facilitates the leasing of rights that enable companies to explore for and develop petroleum and natural gas from Alberta's resources, for the benefit of the province's residents. The Alberta tenure system is looked upon by industry as one of the best in the world.

Alberta's Crown petroleum and natural gas rights are issued in the form of licences or leases through a competitive bid auction system. Public offerings (or sales) of petroleum and natural gas rights are held every two weeks. Notice of the parcels being offered are published on the department's website approximately eight weeks prior to the sale.

The Crown attaches several expectations to the licences and leases issued:

Annual rent of $3.50 per hectare must be paid for each hectare covered by the agreement;
Tenure holders must meet all regulatory requirements;
Lands in a licence are earned by the drilling of a well;
A lease is proven productive at the end of its five-year term by drilling, producing, mapping, being part of a unit agreement or by paying offset compensation;
If a lease is proven productive, it will continue indefinitely beyond the end of the term;
The tenure ends when an agreement holder can no longer prove his agreement is capable of producing oil or gas in paying quantities or is lost through rental or royalty payment default or by voluntary surrender.

The primary term of all leases is 5 years with the right to continue indefinitely if commercial production of the lease product is continuing.

The lessor and overriding royalties applied in this evaluation were based on existing agreements and government regulations. The Crown royalty rates were based upon existing provincial regulations.

Alberta provincial regulations were revised as of January 1, 2017 to emulate a revenue minus cost royalty structure across all hydrocarbons. The structure incorporates a Drilling and Completion Cost Allowance (C[] ), based on average industry drilling and completion costs, as a proxy for well costs. A company will pay a flat royalty of 5% on a well’s early production until the well’s total revenue, from all hydrocarbon products, equals C[] . Afterwards, the company will pay higher royalty rates that vary depending on the resource and market prices but will not exceed 36% for gas and natural gas liquids or 40% for oil and condensate. Royalty

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rates will drop to match declining production rates when the well reaches a Maturity Threshold (Reference 9).

Wells drilled between July 13, 2016 and December 31, 2016 were given the right to exercise an “early optin” to the new royalty framework, otherwise all wells drilled prior to the start date of the new regulations are subject to the previous royalty structure, including any incentive programs, but will transition to the new royalty structure after 10 years from the implementation date of the new program (Reference 10).

The Crown lessor royalties also allow for the deduction of the capital and operating costs necessary to process and transport to market the royalty share of production. The eligible operating cost and third party processing component of this Gas Cost Allowance (GCA) used has been estimated at $2.51/Mcf based on historical information supplied by the Company in its accounting data or estimated based on variable gas operating costs and/or third party processing costs as identified in the Company’s operating statements.

The Capital component of the GCA has been provided by the Company and applied to reduce the Corporate crown gas royalties payable. In Value Navigator this appears as other income.

All of the Company’s leases in the evaluation are Crown leases and subject to Crown royalties.

Property taxes are applied against the assessed value of the wells and tangible assets.

Income taxes are assessed at the corporate level.

8.3 Economic Assumptions

8.3.1 Production Term

All wells are forecast to produce until they are no longer economic. There are no lease or operating terms currently in place that would provide contractual limitations to the production forecast.

8.3.2 Pricing

The forecast of oil prices used in this evaluation were based on Sproule’s December 31, 2017 price forecasts for Western Canada. Sproule develops a proprietary price forecast for a range of international and North American oil and gas benchmarks and marker prices. Sproule’s approach is based on a combination of short-term market based methods and long-term forecasts based on Sproule’s view on market fundamentals.

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Economic Evaluation Discussion — Page 4

8.3.2.1 Oil Pricing

Sproule's long-term forecast has been set at $73.00 US per barrel for West Texas Intermediate (WTI) in 2021 with an escalation rate of 2.0% thereafter.

In the near term the Canadian economy faces many headwinds in combination with the US Federal Reserve tightening monetary policy leading to weakness in the Canadian dollar. We expect the Canadian dollar to continue to be correlated to the price of oil over the forecast period. The exchange rate ($U.S. per $Canadian) reflects a long-term projection of $0.85.

Sproule’s price outlook for Canadian crudes sees the current differential between WTI and Canadian Light Sweet (CWS) narrowing over the forecast period. With pipeline infrastructure experiencing delays, rail has proven to be an effective method to improve takeaway capacity. The low capital investment required, short time frame for constructing a new loading terminal and the ability to access key markets flexibly suggest that rail will continue to play an important role in the transportation of crude. While Canadian light oil faces competition from US LTO plays, new market opportunities are arising for Canadian heavy crudes. US Gulf Coast refiners are increasingly seeking Canadian heavy oil as imports from Venezuela and Mexico decline. The dynamics affecting Canadian oil prices are reflected in a long-term narrowing of the CLS differential to 96% of WTI and the WCS differential to 83% of CLS.

8.3.2.2 Gas Pricing

The NYMEX futures price for gas bought and sold at Henry Hub in Louisiana is the dominant index for North American gas prices. In Alberta and Saskatchewan, the AECO price is a reflection of the market price for natural gas sold locally, while the BC Westcoast Station 2 price is critical to the BC producer. Natural gas prices are generally reflective of regional factors affecting supply and demand.

In the United States, Sproule expects a long-term price of $4.00 US per Mmbtu by 2020 for Henry Hub, reflecting long-term full cycle marginal costs, with an escalation rate of 2.0% thereafter.

Supply growth in the US has put pressure on the future of Canadian natural gas prices as market access becomes more limited for the Canadian producer. In Canada, industrial demand growth for natural gas is weak compared to the United States. LNG export projects represent a significant opportunity for Canada but face challenges in their development including high costs and lengthy regulatory approval processes. The estimated first shipment date from Canadian LNG projects has become uncertain. Several projects have now been cancelled.

The long-term price of Alberta AECO-C is expected to be $3.65 CAD per Mmbtu in 2020 with a 2.0% escalation rate thereafter. Detailed price forecasts for natural gas are set out in Table 8.3.2-1. The actual plantgate price will vary with the heat content of the natural gas and the cost of transportation from the

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Economic Evaluation Discussion — Page 5

plantgate to the trading hub. In the absence of actual natural gas price statistics, the differential is based on the price of natural gas in the area.

8.3.2.3 Natural Gas By-Products

The methodology utilized in Sproule’s price forecast is based on shrinkage value and corresponds to the price of gas at AECO. Propane value is a function of gas value as well as differentials from mid-continent markets. Butane and condensate tend to be priced with reference to crude prices as the dominant demand drivers are refining and diluent markets. The prices for these by-products were adjusted in this report to reflect the actual prices received at the plant gate.

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Economic Evaluation Discussion — Page 6

Table 8.3.2-1 – Summary of Pricing Forecast and Assumptions as of December 31, 2017

Year	Canadian(4) Light Sweet Crude 40 API ($Cdn/bbl)	Western(6) Canada Select 20.5 API ($Cdn/bbl)	Alberta AECO-C Spot ($Cdn/MMbtu)	Edmonton Pentanes Plus ($Cdn/bbl)	Edmonton Butane(5) ($Cdn/bbl)	Edmonton Propane(5) ($Cdn/bbl)	Operating Cost Inflation Rate(2) (%/Yr)	Capital Cost Inflation Rate(2) (%/Yr)	Exchange Rate(3) ($US/$Cdn)
Historical 2013 93.27 74.93 3.13 105.48 69.88 38.37 1.0% 0.7% 0.971 2014 93.99 81.06 4.50 102.39 68.02 44.42 2.0% -1.0% 0.905 2015 57.45 44.83 2.70 61.45 36.81 6.17 1.8% -23.2% 0.783 2016 52.80 38.89 2.18 55.71 34.32 13.60 1.2% -3.4% 0.755 2017 61.84 48.78 2.20 67.21 44.11 28.77 2.2% -3.4% 0.771 Forecast 2018 65.44 51.05 2.85 67.72 48.73 26.06 0.0% 0.0% 0.790 2019 74.51 59.61 3.11 75.61 55.49 32.84 2.0% 2.0% 0.820 2020 78.24 64.94 3.65 78.82 57.65 35.41 2.0% 2.0% 0.850 2021 82.45 68.43 3.80 82.35 60.12 37.85 2.0% 2.0% 0.850 2022 84.10 69.80 3.95 84.07 61.32 39.29 2.0% 2.0% 0.850 2023 85.78 71.20 4.05 85.82 62.55 40.25 2.0% 2.0% 0.850 2024 87.49 72.62 4.15 87.61 63.80 41.23 2.0% 2.0% 0.850 2025 89.24 74.07 4.25 89.43 65.07 42.23 2.0% 2.0% 0.850 2026 91.03 75.55 4.36 91.29 66.37 43.26 2.0% 2.0% 0.850 2027 92.85 77.06 4.46 93.19 67.70 44.30 2.0% 2.0% 0.850 2028 94.71 78.61 4.57 95.12 69.06 45.36 2.0% 2.0% 0.850 Escalation Rate of 2.0% thereafter

(1) This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer. See Appendix B for more details.

(2) Inflation rates for forecasting prices and costs.

(3) Exchange rates used to generate the benchmark reference prices in this table.

(4) Edmonton Par prior to 2014.

(5) Source Change 2013-01.

(6) Source Change 2013-07.

Notes:

Product sale prices will reflect these reference prices with further adjustments for quality and transportation to point of sale.

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Economic Evaluation Discussion — Page 7

Table 8.3.2-2 – Summary of Price Offsets to Forecast Price

Product	Price Offset to Marker	Price Offset to Marker
	Carrot Creek	Cyn-Pem
CrudeOil ($/bbl) (Canadian Light Sweet)	-5.30 -3.20 -0.21 -0.09 -9.20 -5.30 -10.00 -3.60 -10.80 -16.00 -12.80 -0.30 4.80 0.00
Sales Gas ($/Mcf)
C2- Ethane ($/bbl)
C3-Propane ($/bbl)
C4-Butane ($/bbl)
C5+-Pentanes plus ($/bbl)
Condensate ($/bbl)

8.3.3 Capital Costs

The Company provided estimates of the capital costs required to develop the undeveloped locations. These estimates are summarized in Tables 8.3.3-1.

Table 8.3.3-1 – Summary of Project Gross[1] Capital Costs in 2018 Dollars for Carrot Creek (MM$Cdn)

	Proved	Proved	Proved	Proved	Proved	Proved Plus Probable	Proved Plus Probable	Proved Plus Probable	Proved Plus Probable	Proved Plus Probable
Year	Number of Wells to be Drilled	Well Drilling Capital	Complete Capital	Well Equipment and Tie-In Capital	Total Capital2	Number of Wells to be Drilled	Well Drilling Capital	Complete Capital	Well Equipment and Tie-In Capital	Total Capital2
2018	2 5.8 2.4 0.6 8.8 8 23.0 9.3 1.8 34.1 2 9.6 4.0 2.6 16.2 12 38.4 15.7 5.0 59.1					4 11.6 4.8 1.2 17.6 8 23.0 9.3 1.8 34.1 2 9.6 4.0 2.6 16.2 14 44.2 18.1 5.6 67.9
2019
2020
Total2

Project Gross means 100 percent interest
Values may not add due to rounding

8.3.4 Operating Costs

The Company provided Sproule with full year operating statements in Canadian dollars for 2014, 2015, and 2016. The operating statement provided for 2017 included actual costs for the first four months of the year. The operating statements were used to calculate the operating costs used for the evaluation, shown in Table 8.3.4-1.

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Economic Evaluation Discussion — Page 8

Table 8.3.4-1 – Summary of Project Gross[1] Operating Cost Assumptions in 2018 Dollars

	Cost Unit	Carrot Creek
Fixed FacilityOperating	$CDN/month	170,8332 30,0003 3,300 4,050 8.80 9.30 0.52 0.50
Fixed Well Operating	$CDN/well/month
Variable Oil Operating	$CDN/bbl
Variable Gas Operating	$CDN/mcf sales

Project Gross means 100 percent interest
Decreasing by 1/3 to $116,833 when production volumes decrease by 50% and by another 1/3 to $75,000 when volumes decrease to 25% of the 2018 starting rates.
Decreasing by 1/3 to $20,000 when production volumes decrease by 50% and by another 1/3 to $13,333 when volumes decrease to 25% of the 2018 starting rates.

8.3.5 Abandonment Costs

Abandonment and reclamation costs represent all costs associated with the process of restoring a company’s properties, which have been disturbed by oil and gas activities, to a standard imposed by applicable government or regulatory authorities. Pursuant to guidance provided by regulatory agencies, the costs included in this evaluation do not represent the total decommissioning liabilities of the Company but only those costs related to abandonment and reclamation of active wells and material dedicated facilities associated with the Company’s active oil and gas activities in a property. Hence, decommissioning liabilities associated with various non-producing wells, gathering systems and various processing facilities may not be included in this evaluation. Examples of material dedicated facilities could be SAGD projects, offshore projects or properties where it is clear that the facilities are dedicated to a given property. This is not meant to include minor facilities such as tanks, dehydrators etc., or non-material facilities that service small or multiple properties.

The Company was requested to provide abandonment and reclamation costs for all existing development, material dedicated facilities, and future development evaluated in this report.

Final abandonment and reclamation costs included in this report have been prepared and included as follows:

Abandonment and reclamation costs for existing wells with economic developed reserves assigned in this report have been estimated by the Company, and were included in the report at the entity level.

The Company identified no material dedicated facilities for which abandonment and reclamation costs have been included.

Abandonment and reclamation costs for future development drilling locations have been estimated by the Company, and were included in the report at the entity level.

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The Company identified no future material dedicated facilities development for which abandonment and reclamation costs have been included.

This report does not include abandonment and reclamation costs associated with active producing wells, which were not economic to produce under the forecast prices utilized in this report, active service wells, inactive wells, and various active or inactive gathering and processing facilities, that the company holds an interest in, that were not identified as being material dedicated facilities by the Company.

No allowances for salvage were incorporated into the abandonment and reclamation costs contained in this report.

The abandonment cost per well used in the report in the Carrot Creek area was either $95,000 or $105,000 per well, based on the depth of the well, and $160,000 per well in the Cyn-Pem area. The abandonment expenditure for all entities was incurred 60 months after the last month of production of that entity.

8.3.6 Sensitivity Analysis

Sproule performed sensitivity analyses on the total proved plus probable case of key assumptions of price and costs, the results of which are presented in Table 8.3.6-1.

Table 8.3.6-1 – Summary of Sensitivity Analyses

(1) Relative to the discount rate of 10 percent

Variable	Sensitivity	Asset Value Impact(1)	Asset Value Impact(1)
		Plus	Minus
$CdnMM Commodity Price +/- 5% 8.8 -8.3 Operating Costs +/- 20% -4.8 10.6 Capital Costs +/- 20% -7.2 8.1

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Social and Environmental Discussion — Page 1

9. Social and Environmental Discussion

Western Canada has a long history of petroleum exploration and production activities and is governed by mature petroleum regulation systems covering both social and environmental issues.

Canlin is proficient and professional in both technical and administrative aspects of the exploration and production activities of the areas and Western Canada. Additionally, Canlin’s Health, Safety and Environment (HSE) policies emphasize sound HSE performance as one of the foundations for sustainable development.

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Basis of Opinion — Page 1

10. Basis of Opinion

10.1 Evaluation Results

The accuracy of reserves estimates and associated economic analysis is, in part, a function of the quality and quantity of available data and of engineering and geological interpretation and judgment. Given the data provided at the time this report was prepared, the estimates presented herein are considered reasonable. However, they should be accepted with the understanding that reservoir and financial performance subsequent to the date of the estimates may necessitate revision. These revisions may be material.

The net present values of the reserves presented in this report simply represent discounted future cash flow values at several discount rates. Though net present values form an integral part of fair market value estimations, without consideration for other economic criteria, they are not to be construed as Sproule’s opinion of fair market value.

The Competent Person’s Report has been prepared within the context of the Competent Person’s understanding of the effects of petroleum legislation, taxation and other regulations.

Interests, burdens, and other data provided by the Company were accepted as represented, without any further investigation by Sproule. Sproule has no reason to believe the data supplied by the Company is inaccurate or misleading. A Representation Letter to confirm the accuracy, completeness, and availability of data furnished to Sproule during the preparation of this report was provided by the Company.

The Competent Person’s Report represents an independent opinion based on the information provided by the Company, from public sources, and from the non-confidential files of Sproule.

The Competent Person’s Report was performed under an Engagement Agreement that contains standard clauses pertaining to indemnification and liability. Sproule is indemnified by the Company and MIE for misstatements owing to the reliance by Sproule on data and interpretations provided by the Company and MIE, whether directly or indirectly from third parties. Sproule is not indemnified for acts of willful misconduct performed by its management or staff.

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Basis of Opinion — Page 2

10.2 Risks

This report may contain forward-looking statements including expectations of future production revenues and capital expenditures. Information concerning reserves may also be deemed to be forward-looking as estimates involve the implied assessment that the reserves described can be profitably produced in the future. These statements are based on current expectations that involve a number of risks and uncertainties, which could cause actual results to differ from those anticipated. These risks include, but are not limited to: the underlying risks of the oil and gas industry (i.e., corporate commitment, regulatory approval, operational risks in development, exploration and production); potential delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserves estimations; the uncertainty of estimates and projections relating to production; costs and expenses; health, safety and environmental factors; commodity prices; and exchange rate fluctuation.

10.2.1 Guidance Note 7

In accordance with Guidance Note 7 of the Stock Exchange of Hong Kong Limited (“SEHKL”), Sproule has completed a risk analysis addressing the areas of risk along with an assessment of the degree of risk for the proved and probable reserves evaluated in this report. These assessments are necessarily subjective and qualitative. SEHKL has classified risk from minor to major, which can be further clarified as:

Major Risk: the factor poses an immediate danger of a failure, which if uncorrected, will have a material effect (>15% to 20%) on the project cash flow and performance and could potentially lead to project failure.
Moderate Risk: the factor, if uncorrected, could have a significant effect (10% to 15%) on the project cash flow and performance unless mitigated by some corrective action.
Minor Risk: the factor, if uncorrected, will have little or no effect (<10%) on project cash flow and performance.

The likelihood of a risk occurring within a 7-year time frame has been assessed as follows:

Likely: will probably occur
Possible: may occur
Unlikely: unlikely to occur

The degree or consequence of a risk and its likelihood are combined into an overall risk assessment matrix by SEHKL as presented in Table 10.2.1-1.

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Basis of Opinion — Page 3

Table 10.2.1-1 – Overall Risk Assessment Matrix

	Table 10.2.1-1 – Overall	Risk Assessment Matrix
Likelihood of Risk (within 7 years)		Consequence Rating
	Minor	Moderate	Major
Likely	Medium	High	High
Possible	Low	Medium	High
Unlikely	Low	Low	Medium

A summary of the main risks associated with the proved and probable reserves evaluated in this report are show below in Table 10.2.1-2.

Table 10.2.1-2 – Project Risk Assessment

Hazard/Risk Issue	Likelihood of Risk Occurring	Consequence Rating	Risk
Geological
Lack of Significant Source	Unlikely	Minor*	Low
Lack of Significant Migration Timing and Preservation	Unlikely	Minor*	Low
Lack of Significant Trap	Unlikely	Minor*	Low
Lack of Significant Reservoir	Unlikely	Minor*	Low
Engineering
Reduction in reserves significantly outside of the certaintylevels of SPE-PRMS	Unlikely	Major	Low
Reduction in production forecasts significantly outside of the certaintylevels of SPE-PRMS	Unlikely	Major	Low
Economic Conditions
Decrease in oil prices	Possible	Moderate	High
Increase in Inflation	Possible	Minor	Low

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Basis of Opinion — Page 4

Table 10.2.1-2 – Project Risk Assessment (cont’d)

Hazard/Risk Issue	Likelihood of Risk Occurring	Consequence Rating	Risk
Exchange Rate Fluctuation	Possible	Minor	Low
Reduced Market	Unlikely	Moderate	Low
Commercial
Change in Corporate Commitment	Unlikely	Moderate	Medium
Delays in Development Plan	Possible	Moderate	Medium
Regulatory Approval	Unlikely	Major	Low
Country Risk	Unlikely	Moderate	Low
Capital and Operating Costs
Increased Capital Cost	Possible	Low	Medium
Underestimation of Operating Costs	Possible	Low	Medium
Environment
Oil Spill	Unlikely	Major	Medium

Consequence Rating classified as Minor, as Risk is already mitigated.

Geological

The overall chance of geological success is the aggregation of the chance of encountering all the individual geological aspects required for the formation of a hydrocarbon accumulation (reservoir, trap, migration timing and preservation). The oil and gas assets in Carrot Creek and Cyn-Pem, evaluated by Sproule, were categorized as proved and probable reserves. These assets are geologically well defined by seismic and well logs, and are on production. The petroleum system related to the evaluated assets is discussed in Section 5.2. The chance of encountering geological aspects in these assets is very high and hence the overall geological risk is assessed to be very low.

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Basis of Opinion — Page 5

Engineering

Proved reserves are those quantities of petroleum which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.

Probable reserves are those additional reserves which are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves. When probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable reserves.

Economic Conditions

Sproule considered several economic risk factors in its assessment. Short-term market volatility in the price of crude oil and natural gas continues to represent commodity price risk. However, long-term market fundamentals for oil point to continued demand growth in world markets such that the market will fully and sustainably rebalance in the 2018 – 2020 timeframe. A catalyst in the movement towards rebalancing was the production cuts made by OPEC during 2017 and the commitment to continue these cuts through to the end of 2018.

Commercial

To be included in the reserves class, a project must be sufficiently defined to establish its commercial viability. There must be a reasonable expectation that all required internal and external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within a reasonable time frame.

The overall commercial risks are tied to corporate commitment, development plan delays, regulatory approval and country risk. The corporate commitment is likely to remain strong given the nature of the operator and the political will to optimize production of domestic petroleum assets. A delay in the

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Basis of Opinion — Page 6

development plan may be possible and could have a moderate impact on cash flows, which at a minimum would be shifted out with the associated impact on the net present value of project cash flows.

Country risk is a broad-based term to cover off any other market risks associated with investing in a particular country, such as a change in government policy, nationalization of assets or similar events. Typical indicators of country risk, such as credit default swap spreads to mature markets, suggest that the overall country risk in Canada is relatively low.

Capital and Operating Costs

It is possible that the project may suffer from increased capital and operating costs, which will have an impact on project cash flows and returns. Based on a sensitivity analysis on the impact of increases to capital and operating costs, quite significant changes would be required before this would have even a moderate impact on cash flows.

Environmental

The consequences of an oil spill in the Carrot Creek and Cyn-Pem areas are relatively low. There are a number of streams and rivers bisecting the area, but all the oil wells require artificial lift to produce and thus any uncontrolled release of fluids can be relatively quickly and easily managed and brought under control. The oil and gas industry in Western Canada has a strong track record of responsible development and the probability of a major spill is viewed as unlikely.

10.3 Exclusivity

This report has been prepared for the exclusive use of Canlin Energy Corporation and MIE Holdings Corporation. It may not be reproduced, distributed, or made available to any other company or person, regulatory body, or organization without the knowledge and written consent of Sproule, and without the complete contents of the report being made available to that party.

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Basis of Opinion — Page 7

10.4 Report Preparation

The report entitled “Independent Competent Person’s Report of Certain P&NG Reserves in Alberta, Canada of Canlin Energy Corporation for MIE Holdings Corporation (As of January 1, 2018)” was prepared by the following Sproule personnel:

_______ Barrett R. Hanson, P.Eng., SPEC Project Leader; Senior Petroleum Engineer _ 03 / 04 _/2018 dd/mm/yr

_______ Alec Kovaltchouk, P.Geo. VP, Geoscience _ 03 / 04 _/2018 dd/mm/yr

10.4.1 Sproule Executive Endorsement

This report has been reviewed and endorsed by the following Executive of Sproule:

_________ Nora T. Stewart, P.Eng. Senior VP, Reserves Certification and Director _ 03 / 04 _/2018 dd/mm/yr

10.4.2 Permit to Practice

Sproule Associates Limited is a member of the Association of Professional Engineers and Geoscientists of Alberta and our permit number is P00417.

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APPENDIX II

References – Page 1

11. References

Wright, G.N et al (1994): Structure and Architecture of the Western Canada Sedimentary Basin; in Geological Atlas of the Western Canada Sedimentary Basin, G.D. Mossop and I. Shetsen (comp.), Canadian Society of Petroleum Geologists and Alberta Research Council, URL http://www.ags.gov.ab.ca/publications/wcsb_atlas/atlas.html, [Accessed March 28, 2018].
Poulton, T.P. et al (1994): Jurassic and Lowermost Cretaceous Strata of the Western Canada Sedimentary Basin; in Geological Atlas of the Western Canada Sedimentary Basin, G.D. Mossop and I. Shetsen (comp.), Canadian Society of Petroleum Geologists and Alberta Research Council, URL http://www.ags.gov.ab.ca/publications/wcsb_atlas/atlas.html, [Accessed March 28, 2018].
Stronach, N.J. 1984. Depositional environments and cycles in the Jurassic Fernie Formation, southern Canadian Rocky Mountains. In: The Mesozoic of Middle North America. D.F. Stott and D.J. Glass (eds.). Calgary, Canadian Society of Petroleum Geologists, Memoir 9, p. 43-67.
Marion, D.J. 1984. The Middle Jurassic Rock Creek Member and associated units in the subsurface of west-central Alberta. In: The Mesozoic of Middle North America. D.F. Stott and D. Glass (eds.). Calgary, Canadian Society of Petroleum Geologists, Memoir 9, p. 319-344.
Losert, J. 1986. Jurassic Rock Creek Member in the subsurface of the Edson area (west-central Alberta). Alberta Research Council, Open File Report 1986-3, 39 p.
Hayes, B.J.R. et al (1994): Cretaceous Mannville Group of the Western Canada Sedimentary Basin; in Geological Atlas of the Western Canada Sedimentary Basin, G.D. Mossop and I. Shetsen (comp.), Canadian Society of Petroleum Geologists and Alberta Research Council, URL http://www.ags.gov.ab.ca/publications/wcsb_atlas/atlas.html, [Accessed March 28, 2018].
Christopher, J.E. 1984. The Lower Cretaceous Mannville Group, northern Williston Basin region, Canada. In: The Mesozoic of Middle North America. D.F. Stott and D.J. Glass (eds). Calgary, Canadian Society of Petroleum Geologists, Memoir 9, p. 109-126.
Cant, D.J. and Stockmal, G.S. 1989. The Alberta foreland basin: relationship between stratigraphy and Cordilleran terrane-accretion events. Canadian Journal of Earth Sciences, v. 26, p. 1964-1975.
Leckie, D.A. et al (1994): Cretaceous Colorado/Alberta Group of the Western Canada Sedimentary Basin; in Geological Atlas of the Western Canada Sedimentary Basin, G.D. Mossop and I. Shetsen (comp.), Canadian Society of Petroleum Geologists and Alberta Research Council, URL http://www.ags.gov.ab.ca/publications/wcsb_atlas/atlas.html, [Accessed March 28, 2018].
Caldwell, W.G.E. 1984. Early Cretaceous transgressions and regressions in the southern Interior Plains. In: The Mesozoic of Middle North America. D.F. Stott and D.J. Glass (eds.). Canadian Society of Petroleum Geologists Memoir 9, p. 173-203.
Haq, B.U., Hardenbol, J., and Vail, P.R. 1987. Chronology of fluctuating sea levels since the Triassic. Science, v. 235, p. 1156-1166.
Lambeck, K., Cloetingh, S., and McQueen, H. 1987. Intraplate stress and apparent changes in sea level: the basins of northwestern Europe: In: Sedimentary Basins and Basin-forming

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APPENDIX II

References – Page 2

Mechanisms. C. Beaumont and A.J. Tankard (eds.). Canadian Society of Petroleum Geologists, Memoir 12, p. 259-268.

Creaney, S. et al (1994): Petroleum Generation and Migration; in Geological Atlas of the Western Canada Sedimentary Basin, G.D. Mossop and I. Shetsen (comp.), Canadian Society of Petroleum Geologists and Alberta Research Council, URL http://www.ags.gov.ab.ca/publications/wcsb_atlas/atlas.html, [Accessed March 28, 2018]
Magoon, L.B. 1988. The petroleum system - a classification scheme for research, exploration, and resource assessment. In: Petroleum Systems of the United States. L.B. Magoon (ed.). United States Geological Survey, Bulletin 1870.
Krause, F.F. et al (1994): Cretaceous Cardium Formation of the Western Canada Sedimentary Formation; in Geological Atlas of the Western Canada Sedimentary Basin, G.D. Mossop and I. Shetsen (comp.), Canadian Society of Petroleum Geologists and Alberta Research Council, URL http://www.ags.gov.ab.ca/publications/wcsb_atlas/atlas.html, [Accessed March 28, 2018]
Smith, D.G. (1994): Paleogeographic Evolution of the Western Canada Foreland Basin; in Geological Atlas of the Western Canada Sedimentary Basin, G.D. Mossop and I. Shetsen (comp.), Canadian Society of Petroleum Geologists and Alberta Research Council, URL http://www.ags.gov.ab.ca/publications/wcsb_atlas/atlas.html, [Accessed March 28, 2018]
What is Tenure? http://www.energy.gov.ab.ca/Tenure/About/Pages/WIT.aspx [accessed March 28, 2018].
Brochure titled “Alberta’s Modernized Royalty Framework Overview”, Alberta Government, published February 23, 2017.
“Alberta at a Crossroads – Royalty Review Advisory Panel Report”, page 60, Royalty Review Panel chaired by Dave Mowat, released January 28, 2016.

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APPENDIX II

Appendix A — Page 1

Appendix A — Reserve Definitions

The following definitions form the basis of our classification of reserves and values presented in this report. The definitions are those set out in National Instrument 51-101 (“NI 51-101”) and/or the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the “COGE Handbook”), maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and incorporated into NI 51-101 by reference.

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on:

analysis of drilling, geological, geophysical and engineering data;
the use of established technology;
specified economic conditions, which are generally accepted as being reasonable, and shall be disclosed; and
a remaining reserve life of 50 years.

Reserves are classified according to the degree of certainty associated with the estimates.

1. Proved Reserves

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.

2. Probable Reserves

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.

3. Possible Reserves

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. Possible reserves have not been considered in this report.

Other criteria that must also be met for the categorization of reserves are provided in Section 5.5 of the COGE Handbook.

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Each of the reserves categories (proved, probable, and possible) may be divided into developed or undeveloped categories.

4. Developed Reserves

Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g., when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.

5. Developed Producing Reserves

Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

6. Developed Non-Producing Reserves

Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.

7. Undeveloped Reserves

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 requirements of the reserves classification (proved, probable, possible) to which they are assigned.

In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator’s assessment as to the reserves that will be recovered from specific wells, facilities, and completion intervals in the pool and their respective development and production status.

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Appendix A — Page 3

8. Levels of Certainty for Reported Reserves

The qualitative certainty levels contained in the definitions in Sections 1, 2 and 3 are applicable to individual reserves entities, which refers to the lowest level at which reserves estimates are made, and to reported reserves, which refers to the highest level sum of individual entity estimates for which reserve estimates are made.

Reported total reserves estimated by deterministic or probabilistic methods, whether comprised of a single reserves entity or an aggregate estimate for multiple entities, should target the following levels of certainty under a specific set of economic conditions:

a. There is a 90% probability that at least the estimated proved reserves will be recovered.
b. There is a 50% probability that at least the sum of the estimated proved reserves plus probable reserves will be recovered.
c. There is a 10% probability that at least the sum of the estimated proved reserves plus probable reserves plus possible reserves will be recovered.

A quantitative measure of the probability associated with a reserves estimate is generated only when a probabilistic estimate is conducted. The majority of reserves estimates will be performed using deterministic methods that do not provide a quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in Section 5.5.3 of the COGE Handbook. Whether deterministic or probabilistic methods are used, evaluators are expressing their professional judgement as to what are reasonable estimates.

9. Remaining Recoverable Reserves are the total remaining recoverable reserves associated with the acreage in which the Company has an interest.

10. Company Gross Reserves are the Company’s working interest share of the remaining reserves, before deduction of any royalties.

11. Company Net Reserves are the gross remaining reserves of the properties in which the Company has an interest, less all Crown, freehold, and overriding royalties and interests owned by others plus all royalty interest volumes received.

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Appendix A — Page 4

12. Net Production Revenue is income derived from the sale of net reserves of oil, non-associated and associated gas, and gas by-products, less all capital and operating costs.

13. Fair Market Value is defined as the price at which a purchaser seeking an economic and commercial return on investment would be willing to buy, and a vendor would be willing to sell, where neither is under compulsion to buy or sell and both are competent and have reasonable knowledge of the facts.

14. Barrels of Oil Equivalent (BOE) Reserves – BOE is the sum of the oil reserves, plus the gas reserves divided by a factor of 6, plus the natural gas liquid reserves, all expressed in barrels or thousands of barrels. Equivalent reserves can also be expressed in thousands of cubic feet of gas equivalent (McfGE) using a conversion ratio of 1 bbl:6 Mcf.

15. Oil (or Crude Oil) – a mixture consisting mainly of pentanes and heavier hydrocarbons that exists in the liquid phase in reservoirs and remains liquid at atmospheric pressure and temperature. Crude oil may contain small amounts of sulphur and other non-hydrocarbons, but does not include liquids obtained from the processing of natural gas. Crude oil volumes are further divided into Product Types, for reporting purposes.

16. Gas (or Natural Gas) – a mixture of lighter hydrocarbons that exist either in the gaseous phase or in solution in crude oil in reservoirs, but are gaseous at atmospheric conditions. Natural gas may contain sulphur or other non-hydrocarbon compounds. Natural Gas volumes are further divided into Product Types, for reporting purposes.

17. Non-Associated Gas – an accumulation of natural gas in a reservoir where there is no crude oil.

18. Associated Gas – the gas cap overlying a crude oil accumulation in a reservoir.

19. Solution Gas – gas dissolved in crude oil.

20. Natural Gas By Products – those components that can be removed from natural gas including, but not limited to, ethane, propane, butanes, pentanes plus, condensate, and small quantities of nonhydrocarbons.

21. Product Types - sub-classify the principle product types of petroleum, crude oil, gas and byproducts, into specific groupings based on the properties of the hydrocarbon and the properties of the accumulation and reservoir rock from which it is found. Regulatory agencies may define in legislation the production types they require to be used for reporting purposes in their jurisdiction. The Canadian Securities Associations (CSA) defines the following Product Types for reporting purposes in National Instrument 51-101, effective July 1, 2015.

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Appendix A — Page 5

Crude Oil

I) Light Crude Oil means crude oil with a relative density greater than 31.1 degrees API gravity;
II) Medium Crude Oil means crude oil with a relative density greater than 22.3 degrees API gravity and less than or equal to 31.1 degrees API gravity;
III) Heavy Crude Oil means crude oil with a relative density greater than 10 degrees API gravity and less than or equal to 22.3 degrees API gravity;
IV) Tight Oil means crude oil:
a. contained in dense organic rich rocks, including low-permeability shales, siltstones and carbonates, in which the crude oil is primarily contained in microscopic pore spaces that are poorly connected to one another, and
b. that typically requires the use of hydraulic fracturing to achieve economic production rates;
V) Bitumen means a naturally occurring solid or semi-solid hydrocarbon:
a. consisting mainly of heavier hydrocarbons, with a viscosity greater than 10,000 millipascal-seconds (mPa·s) or 10,000 centipoise (cP) measured at the hydrocarbon’s original temperature in the reservoir and at atmospheric pressure on a gas-free basis, and
b. that is not primarily recoverable at economic rates through a well without the implementation of enhanced recovery methods;
VI) Synthetic Crude Oil means a mixture of liquid hydrocarbons derived by upgrading bitumen, kerogen or other substances such as coal, or derived from gas to liquid conversion and may contain sulphur or other compounds;

Natural Gas

VII) Conventional Natural Gas means natural gas that has been generated elsewhere and has migrated as a result of hydrodynamic forces and is trapped in discrete accumulations by seals that may be formed by localized structural, depositional or erosional geological features;
VIII) Coal Bed Methane means natural gas that
a) primarily consists of methane, and
b) is contained in a coal deposit;
IX) Shale Gas means natural gas:
a) contained in dense organic-rich rocks, including low-permeability shales, siltstones and carbonates, in which the natural gas is primarily adsorbed on the kerogen or clay minerals, and
b) that usually requires the use of hydraulic fracturing to achieve economic production rates;

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Appendix A — Page 6

X) Synthetic Gas means a gaseous fluid:

a) generated as a result of the application of an in-situ transformation process to coal or other hydrocarbon-bearing rock, and b) comprised of not less than 10% by volume of methane; XI) Gas Hydrate means a naturally occurring crystalline substance composed of water and gas in an ice-lattice structure;

By-Products

XII) Natural Gas Liquids means those hydrocarbon components that can be recovered from natural gas as a liquid including, but not limited to, ethane, propane, butanes, pentanes plus, and condensates.

XIII) Sulphur is a non-hydrocarbon elemental by-product of gas processing and oil refining.

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Appendix B — Page 1

Appendix B — Abbreviations, Units, Conversion Factors and Formation Names

Abbreviations

ARF	Alberta royalty framework (pre 2017)
AOF	absolute open flow
BOE	barrels of oil equivalent
bpd	barrels per day
bopd	barrels of oil per day
bwpd	barrels of water per day
Cr	Crown
DPIIP	discovered petroleum initially-in-place
DSU	drilling spacing unit
FH	Freehold
GCA	gas cost allowance
GOR	gas-oil ratio
GORR	gross overriding royalty
LPG	liquid petroleum gas
LRR	lease royalty rate
McfGE	thousands of cubic feet of gas equivalent
Mcfpd	thousands of cubic feet per day
MPR	maximum permissive rate
MRF	Alberta modernized royalty framework (post 2016)
MRL	maximum rate limitation
NC	‘new’ Crown
NCI	net carried interest
NGL	natural gas liquids
NORR	net overriding royalty
NPI	net profits interest
NRA	no reserves assigned
NRI	net revenue interest
NPV	net present value
OC	‘old’ Crown
ORRI	overriding royalty interest
P&NG	petroleum and natural gas
PSU	production spacing unit
PVT	pressure-volume-temperature
TPIIP	total petroleum initially-in-place
Unecon	uneconomic reserves evaluation case
UPIIP	undiscovered petroleum initially-in-place
WI	working interest

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Appendix B — Page 2

Imperial and Metric Units

ial and Metric Units
Imperial Units	Prefixes	Metric Units
M (103) thousand MM (106) million B (109) billion T (1012) trillion Q (1015) quadrillion		k (103) kilo M (106) mega G (109) giga T (1012) tera P (1015) peta
in. inches ft feet mi miles	Length	cm centimetres m metres km kilometres
ft2 square feet ac acres	Area	m2 square metres ha hectares
cf or ft3 cubic feet scf standard cubic feet gal gallons Mcf thousand cubic feet MMcf million cubic feet Bcf billion cubic feet bbl barrels Mbbl thousand barrels stb stock tank barrels	Volume	m3 cubic metres L litres e6m3 million cubic metres m3 cubic metres e3m3 thousand cubic metres stm3 stock tank cubic metres
bbl/d barrels per day Mbbl/d thousand barrels per day Mcf/d thousand cubic feet per day MMcf/d million cubic feet per day	Rate	m3/d cubic metre per day e3m3/d thousand cubic metres e3m3/d thousand cubic metres e6m3/d million cubic metres
Btu British thermal units	Energy	J joules
oz ounces lb pounds ton tons lt long tons	Mass	g grams kg kilograms t tonnes
psi pounds per square inch psia pounds per square inch absolute psig pounds per square inch gauge	Pressure	Pa pascals kPa kilopascals (103)
°F degrees Fahrenheit °R degrees Rankine	Temperature	°C degrees Celsius K degrees Kelvin
M$ thousand dollars	Dollars	k$ 1 kilodollar

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Appendix B — Page 3

Imperial and Metric Units (Cont’d)

ial and Metric Units (Cont’d)
Imperial Units	Time	Metric Units
sec second min minute hr hour d day wk week mo month yr year		s second min minute h hour d day week month a annum

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Appendix B — Page 4

Conversion Tables

	Conversion Factors — Metric to Imperial	Conversion Factors — Metric to Imperial
cubic metres (m3) (@ 15°C)	x 6.29010	= barrels (bbl) (@ 60°F),	water
m3 (@ 15°C)	x 6.3300	= bbl (@ 60°F), Ethane
m3 (@ 15°C)	x 6.30001	= bbl (@ 60°F), Propane
m3 (@ 15°C)	x 6.29683	= bbl (@ 60°F), Butanes
m3 (@ 15°C)	x 6.29287	= bbl (@ 60°F), oil, Pentanes Plus
m3 (@ 101.325 kPaa, 15°C)	x 0.0354937	= thousands of cubic feet (Mcf) (@ 14.65			psia, 60°F)
1,000 cubic metres (103m3) (@ 101.325 kPaa, 15°C)	x 35.49373	= Mcf (@ 14.65 psia, 60°F)
hectares (ha)	x 2.4710541	= acres
1,000 square metres (103m2)	x 0.2471054	= acres
10,000 cubic metres (ha.m)	x 8.107133	= acre feet (ac-ft)
m3/103m3 (@ 101.325 kPaa, 15° C)	x 0.0437809	= Mcf/Ac.ft. (@ 14.65 psia, 60°F)
joules (j)	x 0.000948213	= Btu
megajoules per cubic metre (MJ/m3)	x 26.714952	= British thermal	units	per	standard	cubic	foot	(Btu/scf)
(@ 101.325 kPaa, 15°C)		(@ 14.65 psia, 60°F)
dollars per gigajoule ($/GJ)	x 1.054615	= $/Mcf (1,000 Btu gas)
metres (m)	x 3.28084	= feet (ft)
kilometres (km)	x 0.6213712	= miles (mi)
dollars per 1,000 cubic metres ($/103m3)	x 0.0288951	= dollars per thousand cubic feet ($/Mcf) (@ 15.025 psia) B.C.
($/103m3)	x 0.02817399	= $/Mcf (@ 14.65 psia) Alta.
dollars per cubic metre ($/m3)	x 0.158910	= dollars per barrel ($/bbl)
gas/oil ratio (GOR) (m3/m3)	x 5.640309	= GOR (scf/bbl)
kilowatts (kW)	x 1.341022	= horsepower
kilopascals (kPa)	x 0.145038	= psi
tonnes (t)	x 0.9842064	= long tons (LT)
kilograms (kg)	x 2.204624	= pounds (lb)
litres (L)	x 0.2199692	= gallons (Imperial)
litres (L)	x 0.264172	= gallons (U.S.)
cubic metres per million cubic metres (m3/106m3) (C3)	x 0.177496	= barrels per million cubic feet (bbl/MMcf) (@ 14.65 psia)
m3/106m3) (C4)	x 0.1774069	= bbl/MMcf (@ 14.65 psia)
m3/106m3) (C5+)	x 0.1772953	= bbl/MMcf (@ 14.65 psia)
tonnes per million cubic metres (t/106m3) (sulphur)	x 0.0277290	= LT/MMcf (@ 14.65 psia)
millilitres per cubic meter (mL/m3) (C5+)	x 0.0061974	= gallons (Imperial) per thousand cubic feet (gal (Imp)/Mcf)
(mL/m3) (C5+)	x 0.0074428	= gallons (U.S.) per thousand cubic feet (gal (U.S.)/Mcf)
Kelvin (K)	x 1.8	= degrees Rankine (°R)
millipascal seconds (mPa.s)	x 1.0	= centipoise
density (kg/m3), ρ	ρ÷1000x141.5-	= °API
	131.5

3390.22221.BRH.nmt

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COMPETENT PERSON’S REPORT

APPENDIX II

Appendix B — Page 5

Conversion Tables (Cont’d)

Conversion	Factors — Imperial to Metric	Factors — Imperial to Metric
barrels (bbl) (@ 60°F)	x 0.15898	= cubic metres (m3) (@ 15°C), water
bbl (@ 60°F)	x 0.15798	= m3 (@ 15°C), Ethane
bbl (@ 60°F)	x 0.15873	= m3 (@ 15°C), Propane
bbl (@ 60°F)	x 0.15881	= m3 (@ 15°C), Butanes
bbl (@ 60°F)	x 0.15891	= m3 (@ 15°C), oil, Pentanes Plus
thousands of cubic feet (Mcf) (@ 14.65 psia, 60°F)	x 28.17399	= m3 (@ 101.325 kPaa, 15°C)
Mcf (@ 14.65 psia, 60°F)	x 0.02817399	= 1,000 cubic metres (103m3) (@ 101.325 kPaa, 15°C)
acres	x 0.4046856	= hectares (ha)
acres	x 4.046856	= 1,000 square metres (103m2)
acre feet (ac-ft)	x 0.123348	= 10,000 cubic metres (104m3) (ha.m)
Mcf/ac-ft (@ 14.65 psia, 60°F)	x 22.841028	= 103m3/m3 (@ 101.325 kPaa, 15°C)
Btu	x 1054.615	= joules (J)
British thermal units per standard cubic foot (Btu/Scf)	x 0.03743222	= megajoules per cubic metre (MJ/m3)
(@ 14.65 psia, 60°F)		(@ 101.325 kPaa, 15°C)
$/Mcf (1,000 Btu gas)	x 0.9482133	= dollars per gigajoule ($/GJ)
$/Mcf (@ 14.65 psia, 60°F) Alta.	x 35.49373	= $/103m3 (@ 101.325 kPaa, 15°C)
$/Mcf (@ 15.025 psia, 60°F), B.C.	x 34.607860	= $/103m3 (@ 101.325 kPaa, 15°C)
feet (ft)	x 0.3048	= metres (m)
miles (mi)	x 1.609344	= kilometres (km)
dollars per barrel ($/bbl)	x 6.29287	= dollars per cubic metre ($/m3)
GOR (scf/bbl)	x 0.177295	= gas/oil ratio (GOR) (m3/m3)
horsepower	x 0.7456999	= kilowatts (kW)
psi	x 6.894757	= kilopascals (kPa)
long tons (LT)	x 1.016047	= tonnes (t)
pounds (lb)	x 0.453592	= kilograms (kg)
gallons (Imperial)	x 4.54609	= litres (L) (.001 m3)
gallons (U.S.)	x 3.785412	= litres (L) (.001 m3)
barrels per million cubic feet (bbl/MMcf) (@ 14.65 psia) (C3)	x 5.6339198	= cubic metres per million cubic metres (m3/106m3)
bbl/MMcf (C4)	x 5.6367593	= (m3/106m3)
bbl/MMcf (C5+)	x 5.6403087	= (m3/106m3)
LT/MMcf (sulphur)	x 36.063298	= tonnes per million cubic metres (t/106m3)
gallons (Imperial) per thousand cubic feet (gal (Imp)/Mcf) (C5+)	x 161.3577	= millilitres per cubic meter (mL/m3)
gallons (U.S.) per thousand cubic feet (gal (U.S.)/Mcf) (C5+)	x 134.3584	= (mL/m3)
degrees Rankine (°R)	x 0.555556	= Kelvin (K)
centipoises	x 1.0	= millipascal seconds (mPa.s)
°API	(°APIx131.5)x	= density (kg/m3)
	1000/141.5

3390.22221.BRH.nmt

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COMPETENT PERSON’S REPORT

APPENDIX II

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----- Start of picture text -----

Appendix B — Page 6
----- End of picture text -----


	SPROULE	STANDARD FORMATION NAME ABBREVIATIONS - CANADA
ABB.	FORMATION NAME	ABB.	FORMATION NAME	ABB.	FORMATION NAME	ABB.	FORMATION NAME
ABGP	ALBERTA GROUP	EARL	EARLIE	LKRV	LOWER KEG RIVER	RVCG	RAVENSCRAG
ALID	ALIDA	EDMN	EDMONTON	LLTN	LYLETON	SBRS	SUNBURST
ALXO	ALEXO	EKPP	ELK POINT GROUP	LMNV	LOWER MANNVILLE	SBWI	SECOND BOW ISLAND SS
AMRN	AMARANTH	ELDN	ELDON	LPIN	LEPINE	SCLD	SCOLLARD
ARCM	ARCTOMYS	ELKK	ELK	LPRK	LEA PARK	SCLN	SCALLION
ARCS	ARCS	ELKT	ELKTON	LRSV	LOWER SHAUNAVON	SCTR	SCATTER
ASRN	ASHERN	ELRL	ELLERSLIE	LVGS	LIVINGSTONE	SFBR	SHAFTESBURY
ASVL	ASHVILLE	ERLK	ERNESTINA LAKE	LWAT	LOWER WATROUS	SFCR	SWIFT CURRENT
BARO	BARONS SAND	ERNG	ETHERINGTON	LWGR	LOWER GRAND RAPIDS	SHND	SHUNDA
BCDS	BASAL COLORADO SS.	ESND	EASTEND	MASE	MASEFIELD	SKGP	SASKATCHEWAN GROUP
BCHO	BISTCHO	EXSW	EXSHAW	MBGP	MANITOBA GROUP	SKNN	SIKANNI
BCKG	BUCKINGHORSE	FCLZ	FISH SCALE ZONE	MBRL	MOBERLY	SLLN	SULLIVAN
BCLK	BIRCH LAKE	FLHR	FALHER	MCLN	MCLAREN	SLPM	SULPHUR MOUNTAIN
BCMB	BASAL SAND(CAMBRIAN)	FLUM	FLUME	MCMR	MCMURRAY	SLPP	SULPHUR POINT
BCRK	BLACK CREEK	FNGN	FINNEGAN	MCNL	MCCONNELL	SLVP	SLAVE POINT
BDBD	BASAL RED BEDS	FNSQ	FANTASQUE	MDCN	MEDICINE HAT	SMGP	SMOKY GROUP
BDBR	BIRDBEAR	FRBG	FIREBAG	MDGP	MADISON GROUP	SMRR	ST. MARY RIVER
BDLK	BOUNDARY LAKE	FRBR	FROBISHER	MDLK	MEADOW LAKE	SNMN	STONY MOUNTAIN
BDRT	BADHEART	FRCM	FRENCHMAN	MIDL	MIDALE	SNVN	SHAUNAVON
BGRY	BIGORAY MEMBER	FRLM	FAIRHOLME	MILK	MIDDLE INTERLAKE	SPNL	SPINNEY HILL
BGVL	BIG VALLEY	FRMS	FOREMOST	MJLK	MAJEAU LAKE	SPRF	SPEARFISH
BHLL	BEAVERHILL LAKE	FRNG	FERNIE GROUP	MLDD	MILDRED	SPRK	SPARKY
BKKN	BAKKEN	FSMP	FORT SIMPSON	MLKR	MILK RIVER	SPRR	SPRAY RIVER
BLCK	BLACKSTONE	FTJN	FORT ST. JOHN GROUP	MLTN	MOULTON	SPRV	SPIRIT RIVER
BLDN	BALDONNEL	FVEL	FAVEL	MMTN	MIST MOUNTAIN	SRSR	SOURIS RIVER
BLDV	BLOOD RESERVE	FVLM	FORT VERMILION	MNCH	MUNCHO	SSPK	SECOND WHITE SPECKS
BLLY	BELLOY	FWSS	FIRST WHITE SPECKS	MNTE	MONTEITH	SSSH	SASSENACH
BLQZ	BASAL QUARTZ	GBJC	GREY BEDS(JURASSIC)	MNTN	MONTNEY	STLR	STETTLER
BLRG	BLUE RIDGE MEMBER	GDPD	GRAND RAPIDS	MNVL	MANNVILLE	STNL	STONEWALL
BLRV	BELLY RIVER	GDRC	GOODRICH	MORR	MORRO	STON	STONE
BLSK	BLUESKY	GLCC	GLAUCONITIC SS.	MPRK	MOUNTAIN PARK	STPN	STEPHEN
BNFF	BANFF	GLPM	GENERAL PETROLEUM	MRDN	MORDEN	STSK	SOUTHESK
BOYN	BOYNE	GLWD	GILWOOD	MSBR	MOOSEBAR	STTH	SAWTOOTH
BRPW	BEARPAW	GMBL	GRUMBLER	MSKG	MUSKEG	SUCC	SUCCESS
BRSS	BROSSEAU	GNTN	GUNTON	MSKK	MUSKIKI	SULY	SULLY
BRVR	BESA RIVER	GOGG	GOG	MSKW	MUSKWA	SWFT	SWIFT
BRWD	BROWN SAND	GOLT	GOLATA	MSNC	MISSION CANYON	SWNH	SWAN HILLS
BRZU	BRAZEAU	GPPG	GYPSUM SPRINGS	MSTY	MISTY	SWNR	SWAN RIVER
BSLD	BOW ISLAND	GRBD	GREEN BEDS	MTHK	MT. HAWK	TBER	TABER
BSUT	BLACK SHALE UNIT	GRBT	GARBUTT	MTSN	MATTSON	TFLS	TWIN FALLS
BSVN	BOISSEVAIN	GRLG	GRAYLING	MTYT	MT. WHYTE	TLFL	TAYLOR FLAT
BTPK	BEATTIE PEAKS	GRMN	GRAMINIA	MWBL	MOWITCH-BELCOURT	TLSN	TILSTON
BTTL	BATTLE	GRNW	GRANITE WASH	NCSL	NEWCASTLE	TNLM	TUNNEL MOUNTAIN
BVRF	BEAVERFOOT	GRSM	GROSMONT	NKNS	NIKANASSIN	TOAD	TOAD
CARN	CAIRN	GRTT	GROTTO	NNDA	NONDA	TOQY	TORQUAY
CCPD	CONTACT RAPIDS	GTES	GATES	NRDG	NORDEGG	TRFK	THREE FORKS
CDMN	CADOMIN	GTNG	GETHING	NSKU	NISKU	TRLM	TURTLE MOUNTAIN
CDRL	CATHEDRAL	GVBG	GRAVELBOURG	NTKN	NOTIKEWIN	TRRV	TROUT RIVER
CDTT	CADOTTE	HGHD	HIGHWOOD	OCDZ	OSTRACOD ZONE	TRVL	TURNER VALLEY
CHNK	CHINOOK	HLFY	HALFWAY	OLDM	OLDMAN	TTCH	TETCHO
CKGK	COOKING LAKE	HNDO	HONDO	PCCP	POUCE COUPE	TTLN	TATHLINA
CLDK	COLD LAKE	HNSN	HANSON	PCGP	PEACE RIVER GROUP	UBMG	UPPER BLAIRMORE
CLLK	CHARLIE LAKE	HOME	HOME	PCPL	PORCUPINE HILLS	UILK	UPPER INTERLAKE
CLMR	CALMAR	HRLD	HERALD	PDDY	PADDY	UKRV	UPPER KEG RIVER
CLMT	CALMUT	HRMN	HARMON	PECH	PEECHEE	UMNV	UPPER MANNVILLE
CLNY	COLONY	HRRV	HORN RIVER	PGBD	PASSAGE BEDS	UPGR	UPPER GRAND RAPIDS
CLRD	COLORADO	HRVR	HAY RIVER	PIKA	PIKA	USHV	UPPER SHAUNAVON
CLSP	COALSPUR SCOLLARD	HSCN	HORSESHOE CANYON	PIPR	PIPER	UTRV	UPPER TURNER VALLEY
CLWS	CLEARWATER SHALE	HSLR	HASLER	PKCP	POKER CHIP SHALE	VCTR	VICTORIA
CMGS	CUMMINGS	IRTN	IRETON	PKKU	PUSKWASKAU	VGRD	VANGUARD
CMRS	CAMROSE	ISBL	ISHBEl	PKSK	PEKISKO	VKNS	VIKING SAND
CNCG	CHINCHAGA	JDTH	JUDITH RIVER	PKWK	PAKOWKI	VMLR	VERMILION RIVER
CNGO	CHUNGO	JLFU	JOLI FOU	PLCN	PELICAN	VRDN	VIRDEN
CNTH	CYNTHIA MEMBER	JNMR	JEAN MARIE	PLSR	PALLISER	WATT	WATT MOUNTAIN
CNTR	CANTUAR	JPGP	JUMPING POUND	PMBN	PEMBINA	WBMN	WABAMUN
CPSL	CYPRESS HILLS	KEGR	KEG RIVER	PNPT	PINE POINT	WBSK	WABISKAW
CRDM	CARDIUM	KKIS	KAKISA	PPHT	PROPHET	WDMN	WOOD MOUNTAIN
CRFT	CROWFOOT	KNDL	KINDLE	PPLR	POPLAR	WFWL	WATERFOWL
CRLS	CHARLES	KSBY	KISBEY	PRDN	PARDONET	WGTE	WESTGATE
CRSN	CHRISTINA	KSKN	KISKATINAW	PRDX	PERDRIX	WHRS	WHITEHORSE
CRSR	CRUISER	KSKP	KASKAPAU	PRQL	PRESQU'ILE	WKPH	WOKKPASH
CRWS	CROWSNEST	KSKS	KANANASKIS	PRVP	PRAIRIE EVAPORITE	WLCK	WILLOW CREEK
CSFD	CROSSFIELD	KTCH	KOTCHO	PSKP	PASKAPOO	WLRC	WILRICH
CSGN	COSTIGAN	KTNL	KOTANEELEE	RCKK	ROCK CREEK	WNPG	WINNIPEG
CTBK	CUT BANK	KTNY	KOOTENAY	RCLF	RATCLIFFE	WOLF	WOLF LAKE MEMBER
DBLT	DEBOLT	LABI	LA BICHE	RDBV	RED BEDS(DEVONIAN)	WPGP	WAPITI GROUP
DCRK	DOE CREEK	LAMR	LOWER AMARANTH	RDGM	RIDING MOUNTAIN	WPGS	WINNIPEGOSIS
DDWD	DEADWOOD	LBMG	LOWER BLAIRMORE	RDKF	REDKNIFE	WPIB	WAPIABI
DINA	DINA	LBRG	LOTSBERG	RDRV	RED RIVER	WRBR	WINTERBURN
DNVG	DUNVEGAN	LBSK	LOBSTICK MEMBER	REXX	REX	WRLK	WHITEWATER LAKE
DOIG	DOIG	LCLD	LOWER COLORADO	RLDG	ROUTLEDGE	WSEC	WASECA
DPRW	DUPEROW	LDGP	LODGEPOLE	RNBW	RAINBOW	WTMD	WHITEMUD
DSBY	DAWSON BAY	LDMR	LLOYDMINSTER	RNDL	RUNDLE GROUP	WTRS	WATROUS
DTSS	DETRITAL SANDSTONE	LDUC	LEDUC	RRDN	RIERDON	WTRW	WATERWAYS
DUDN	DUNEDIN	LILK	LOWER INTERLAKE	RSRY	ROSERAY	YOMN	YEOMAN
DVRN	DUVERNAY	LIRD	LIARD	RSTN	RESTON	ZAMA	ZAMA

3390.22221.BRH.nmt

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– II-79 –

COMPETENT PERSON’S REPORT

APPENDIX II

Appendix C — Page 1

Appendix C – Cash Flow Reports

This appendix contains detailed cash flow reports containing summaries of reserves and net present values for Canlin’s working interests in the Carrot Creek and Cyn-Pem areas.

Discussion of the fiscal terms and economic assumptions are included in Section 8.0

The cash flow report tables include two pages for each reserve category for the Carrot Creek and CynPem areas, combined, presenting the economic summary and production detail.

P:\Canlin Energy 22221\Report\Appendix C - Cash Flow Reports.doc

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3390.22221.BRH.nmt

– II-80 –

COMPETENT PERSON’S REPORT

APPENDIX II

Consolidated
Canlin Energy Corporation
As Of Date : 2017-12-31
Appendix C
Summary of Reserves and Net Present Values
Total Proved + Probable
Production Start : 2018-01-01
9898.3
0.0
1698.1
870.7
493.9
326.0
7.6
0
0
45183
1349
0.0
0.0
0.0
0.0
444.8
Co. Net
10877.4
0.0
2102.2
1078.4
606.7
409.0
8.1
0
0
48225
1516
0.0
0.0
0.0
0.0
485.1
Co. Gr.
13643.5
0.0
2570.7
1312.2
748.8
500.0
9.8
0
0
57897
3133
0.0
0.0
0.0
0.0
901.1
Gross
MBoe
MLt
MBbl
MBbl
MBbl
MBbl
MBbl
MMcf
MMcf
MMcf
MMcf
MBbl
MBbl
MBbl
MBbl
MBbl
Equiv. Oil
Sulphur
Total NGL
Pentane Plus
Butane
Propane
Ethane
Shale Gas
CBM
Non-Assoc
Assoc Gas
Solution Gas
Tight Oil
Synthetic
Bitumen
Heavy Oil
Lt Med Oil
M$
M$
M$
M$
M$
M$
%
M$
M$
M$
M$
M$
M$
M$
boe/d
Mcf/d
bbl/d
Cash Flow
Reclaim.
Capital
Expenses
Other Exp.
Opex
Royalty
Royalty
Non-Crown
Crown
Revenue
Revenue
Revenue
Revenue
Gross
Gross
Gross
Year
BTax
Aband. &
Total
Total
Total
Total
Total
Other
Gas
Oil
BOE
Comp.
Gas
Comp.
Oil
Comp.
-2681.9
0.0
17054.4
5302.7
0.0
5302.7
11.4
2537.6
275.4
2262.2
22212.7
8628.9
10516.1
3067.7
2148.9
9639
136.1
2018
775.3
0.0
25972.9
6777.0
0.0
6777.0
9.0
3328.3
282.1
3046.2
36853.5
14712.1
18994.2
3147.2
3429.5
15832
121.7
2019
14812.6
0.0
15684.5
7052.1
0.0
7052.1
8.7
3594.0
282.7
3311.2
41143.2
15391.6
22773.5
2978.1
3443.4
15958
109.1
2020
23636.8
0.0
0.0
6374.1
0.0
6374.1
10.2
3407.8
265.0
3142.8
33418.7
12484.8
18122.6
2811.3
2647.9
12205
97.7
2021
18706.4
0.0
0.0
5809.9
0.0
5809.9
11.8
3281.9
243.6
3038.3
27798.1
10250.2
14951.4
2596.5
2108.4
9669
88.4
2022
15897.9
0.0
0.0
5500.2
0.0
5500.2
12.3
2989.4
226.5
2762.9
24387.4
8935.7
13027.6
2424.1
1795.4
8207
80.8
2023
13872.1
0.0
0.0
5311.2
0.0
5311.2
12.8
2825.9
211.8
2614.1
22009.3
8017.6
11724.0
2267.7
1573.7
7179
73.8
2024
12354.3
0.0
0.0
5122.7
0.0
5122.7
12.4
2479.7
197.4
2282.4
19956.8
7226.5
10606.2
2124.1
1395.0
6352
67.9
2025
10747.6
363.0
0.0
5022.6
0.0
5022.6
12.1
2219.2
185.5
2033.7
18352.4
6612.2
9759.6
1980.6
1251.0
5691
62.0
2026
10325.2
315.7
0.0
4975.8
0.0
4975.8
8.0
1356.0
174.8
1181.2
16972.7
6086.3
9013.6
1872.8
1129.8
5133
57.5
2027
9446.1
210.1
0.0
4851.8
0.0
4851.8
7.7
1211.2
163.0
1048.2
15719.2
5608.4
8341.5
1769.3
1017.9
4618
53.0
2028
8491.7
200.4
0.0
4687.6
0.0
4687.6
7.5
1079.8
150.1
929.8
14459.5
5139.6
7639.6
1680.4
917.7
4156
49.5
2029
7704.0
159.3
0.0
4593.6
0.0
4593.6
7.3
985.7
140.6
845.1
13442.6
4750.8
7087.6
1604.2
834.1
3771
46.3
2030
7038.2
66.6
0.0
4541.9
0.0
4541.9
7.3
910.6
131.7
778.9
12557.2
4421.5
6600.7
1535.0
762.9
3444
43.4
2031
6383.4
62.5
0.0
4466.3
0.0
4466.3
7.2
849.7
121.6
728.1
11761.9
4117.0
6169.2
1475.6
697.3
3142
40.7
2032
5311.7
472.4
0.0
4321.3
0.0
4321.3
7.3
791.4
112.8
678.6
10896.6
3791.0
5716.9
1388.8
635.2
2860
37.7
2033
5114.9
98.3
0.0
4279.7
0.0
4279.7
7.3
750.5
106.8
643.6
10243.3
3558.2
5375.7
1309.4
585.3
2635
34.8
2034
4358.2
347.2
0.0
4007.9
0.0
4007.9
7.4
696.4
95.6
600.7
9409.6
3291.9
4962.8
1154.9
528.1
2384
30.1
2035
4275.9
0.0
0.0
3950.1
0.0
3950.1
7.5
665.5
89.0
576.5
8891.5
3103.4
4690.0
1098.0
487.3
2198
27.9
2036
3434.8
403.9
0.0
3534.9
0.0
3534.9
7.6
606.1
76.3
529.8
7979.7
2809.5
4235.5
934.7
431.4
1953
23.3
2037
185556.8
14777.1
58711.9
117533.1
0.0
117533.1
39386.6
3681.1
35705.5
415965.5
152846.2
221975.1
41144.2
Total
5551.8
12077.8
0.0
17050.1
0.0
17050.1
2819.9
148.8
2671.1
37499.6
13909.0
21666.7
1923.9
15 Years
180005.1
2699.3
58711.9
100483.0
0.0
100483.0
36566.7
3532.3
33034.4
378465.9
138937.2
200308.3
39220.4
Sub Total
124217.3
4554.9
54700.7
72522.2
0.0
72522.2
27820.6
2545.1
25275.5
283815.7
105094.9
150611.2
28109.5
5%
Discount
88315.2
1677.6
51183.7
50547.2
0.0
50547.2
21313.8
1909.6
19404.2
213037.5
79450.9
112650.9
20935.7
10%
Discount
78149.1
1180.7
49896.1
44884.4
0.0
44884.4
19468.7
1732.7
17736.0
193579.1
72377.6
102242.5
18959.0
12%
Discount
65882.1
731.2
48078.4
38365.9
0.0
38365.9
17220.9
1520.5
15700.4
170278.5
63886.3
89790.4
16601.9
15%
Discount
56276.0
476.9
46385.1
33489.4
0.0
33489.4
15432.3
1355.0
14077.4
152059.7
57225.5
80060.0
14774.2
18%
Discount
50984.3
367.8
45319.5
30882.2
0.0
30882.2
14431.3
1263.8
13167.5
141985.0
53532.4
74680.5
13772.1
20%
Discount
40577.5
206.5
42854.2
25897.9
0.0
25897.9
12416.7
1083.9
11332.8
121952.8
46163.6
63984.8
11804.3
25%
Discount
$/BOE 6.76
1.1 years
14.0
4.3 years
30.0 years
First Year Co Gr. Operating Costs
Before Tax Payout
Reserve Life Index
Reserve Half Life
Reserve Life

Version : 16.2.0.45
DB : Canlin22221.vndl
Canlin Energy Corporation
Run Time : 18/04/02 15:10
Run By : carolinh
Price : 2017-12-31 SAL Prices
Scenario : NI51-101
Project : 22221 - Report :
H4
Page : 1 of 1

– II-81 –

COMPETENT PERSON’S REPORT

APPENDIX II

			$/Lt MLt MLt MLt Price Co Net Co Grs Gross Sulphur - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - $/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Butane 37.68 32.4 43.1 56.1 44.55 58.5 70.3 82.7 46.73 59.3 71.0 88.5 49.17 43.4 54.2 67.1 50.35 32.7 43.0 53.6 51.57 27.2 36.5 45.7 52.81 23.4 32.1 40.2 54.07 20.8 28.3 35.5 55.36 18.8 25.4 31.8 56.68 19.9 22.9 28.8 58.03 18.1 20.7 26.0 59.41 16.3 18.6 23.4 60.81 14.8 16.9 21.1 62.24 13.6 15.4 19.1 63.71 12.4 14.1 17.4 65.19 11.3 12.8 15.7 66.72 10.4 11.8 14.2 68.29 9.3 10.6 12.8 69.88 8.6 9.8 11.8 71.51 7.6 8.7 10.5 493.9 606.7 748.8 35.2 40.5 46.9 458.7 566.2 701.8 $/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Pentane Plus 63.56 54.9 75.8 96.5 71.44 102.3 125.4 145.4 74.65 104.3 126.8 156.4 78.19 76.1 96.7 118.2 79.92 57.0 76.5 94.1 81.67 47.5 64.9 80.0 83.47 40.9 56.9 70.2 85.29 36.5 50.2 61.9 87.15 33.0 45.0 55.5 89.06 35.5 40.6 50.1 91.00 32.2 36.6 45.3 92.90 29.1 32.9 40.7 94.85 26.5 29.8 36.7 96.82 24.3 27.2 33.2 98.84 22.2 24.9 30.4 100.91 20.1 22.6 27.2 103.01 18.5 20.8 24.8 105.16 16.7 18.9 22.4 107.34 15.5 17.5 20.7 109.57 13.6 15.5 18.4 870.7 1078.4 1312.2 63.8 72.9 84.1 806.8 1005.5 1228.1 Year 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 Total 10 Years Sub Tot $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Heavy Oil - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Bitumen - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -	$/Lt MLt MLt MLt Price Co Net Co Grs Gross Sulphur - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - $/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Butane 37.68 32.4 43.1 56.1 44.55 58.5 70.3 82.7 46.73 59.3 71.0 88.5 49.17 43.4 54.2 67.1 50.35 32.7 43.0 53.6 51.57 27.2 36.5 45.7 52.81 23.4 32.1 40.2 54.07 20.8 28.3 35.5 55.36 18.8 25.4 31.8 56.68 19.9 22.9 28.8 58.03 18.1 20.7 26.0 59.41 16.3 18.6 23.4 60.81 14.8 16.9 21.1 62.24 13.6 15.4 19.1 63.71 12.4 14.1 17.4 65.19 11.3 12.8 15.7 66.72 10.4 11.8 14.2 68.29 9.3 10.6 12.8 69.88 8.6 9.8 11.8 71.51 7.6 8.7 10.5 493.9 606.7 748.8 35.2 40.5 46.9 458.7 566.2 701.8 $/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Pentane Plus 63.56 54.9 75.8 96.5 71.44 102.3 125.4 145.4 74.65 104.3 126.8 156.4 78.19 76.1 96.7 118.2 79.92 57.0 76.5 94.1 81.67 47.5 64.9 80.0 83.47 40.9 56.9 70.2 85.29 36.5 50.2 61.9 87.15 33.0 45.0 55.5 89.06 35.5 40.6 50.1 91.00 32.2 36.6 45.3 92.90 29.1 32.9 40.7 94.85 26.5 29.8 36.7 96.82 24.3 27.2 33.2 98.84 22.2 24.9 30.4 100.91 20.1 22.6 27.2 103.01 18.5 20.8 24.8 105.16 16.7 18.9 22.4 107.34 15.5 17.5 20.7 109.57 13.6 15.5 18.4 870.7 1078.4 1312.2 63.8 72.9 84.1 806.8 1005.5 1228.1 Year 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 Total 10 Years Sub Tot $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Heavy Oil - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Bitumen - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
$/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Propane	16.19 22.91 25.47 27.93 29.38 30.35 31.33 32.34 33.37 34.41 35.48 36.39 37.33 38.26 39.23 40.22 41.22 42.23 43.27 44.32		$/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Pentane Plus	63.56 54.9 75.8 96.5 71.44 102.3 125.4 145.4 74.65 104.3 126.8 156.4 78.19 76.1 96.7 118.2 79.92 57.0 76.5 94.1 81.67 47.5 64.9 80.0 83.47 40.9 56.9 70.2 85.29 36.5 50.2 61.9 87.15 33.0 45.0 55.5 89.06 35.5 40.6 50.1 91.00 32.2 36.6 45.3 92.90 29.1 32.9 40.7 94.85 26.5 29.8 36.7 96.82 24.3 27.2 33.2 98.84 22.2 24.9 30.4 100.91 20.1 22.6 27.2 103.01 18.5 20.8 24.8 105.16 16.7 18.9 22.4 107.34 15.5 17.5 20.7 109.57 13.6 15.5 18.4
	21.8 39.8 40.4 29.3 21.8 18.0 15.3 13.6 12.3 12.5 11.4 10.3 9.4 8.6 7.9 7.1 6.6 6.0 5.6 4.9	326.0 23.6 302.4
	28.8 47.6 48.1 36.7 29.0 24.6 21.6 19.0 17.1 15.4 13.9 12.4 11.3 10.3 9.4 8.6 7.9 7.1 6.6 5.9	409.0 27.6 381.4
	37.1 55.5 59.6 45.1 35.9 30.5 26.8 23.6 21.1 19.1 17.2 15.5 13.9 12.6 11.6 10.4 9.4 8.5 7.8 7.0	500.0 31.9 468.1
$/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Ethane	- - 0.91 1.33 1.76 2.03 2.31 2.59 2.88 3.17 3.47 3.72 3.98 4.25 4.51 4.79 5.07 5.35 5.65 5.94		$/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Butane	37.68 32.4 43.1 56.1 44.55 58.5 70.3 82.7 46.73 59.3 71.0 88.5 49.17 43.4 54.2 67.1 50.35 32.7 43.0 53.6 51.57 27.2 36.5 45.7 52.81 23.4 32.1 40.2 54.07 20.8 28.3 35.5 55.36 18.8 25.4 31.8 56.68 19.9 22.9 28.8 58.03 18.1 20.7 26.0 59.41 16.3 18.6 23.4 60.81 14.8 16.9 21.1 62.24 13.6 15.4 19.1 63.71 12.4 14.1 17.4 65.19 11.3 12.8 15.7 66.72 10.4 11.8 14.2 68.29 9.3 10.6 12.8 69.88 8.6 9.8 11.8 71.51 7.6 8.7 10.5
	0.5 6 0.9 9 0.9 0 0.7 7 0.5 6 0.5 5 0.4 4 0.3 4 0.3 3 0.3 3 0.3 3 0.2 2 0.2 2 0.2 2 0.2 2 0.2 2 0.1 2 0.1 1 0.1 1 0.1 1	7.6 1 0.5 5 7.0 5
	0. 0. 1. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0.	8. 0. 7.
	0.7 1.1 1.2 0.9 0.7 0.6 0.5 0.5 0.4 0.4 0.3 0.3 0.3 0.2 0.2 0.2 0.2 0.2 0.2 0.1	9.8 0.6 9.1
$/Mcf MMcf MMcf MMcf Price Co Net Co Grs Gross Solution Gas	2.85 3.12 3.69 3.83 3.98 4.08 4.18 4.28 4.38 4.48 4.58 4.67 4.77 4.86 4.96 5.06 5.14 5.23 5.34 5.44		$/Lt MLt MLt MLt Price Co Net Co Grs Gross Sulphur	- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
	153 137 122 104 92 84 76 69 63 57 51 47 44 41 39 35 31 25 23 19	1349 37 1311
	171 153 136 117 103 94 85 78 70 65 57 53 50 46 44 40 35 29 26 22	1516 43 1473
	369 328 290 247 217 196 178 161 144 132 116 108 101 94 88 80 67 51 47 39	3133 80 3053
$/Mcf MMcf MMcf MMcf Mcf/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Gas	3.00 3.29 3.90 4.07 4.24 4.36 4.47 4.58 4.71 4.82 4.95 5.05 5.16 5.27 5.38 5.49 5.61 5.72 5.85 5.96		$/Bbl Price	- - - - - - - - - - - - - - - - - - - -
	3106 5304 5381 4072 3188 2696 2357 2087 1876 1687 1528 1374 1247 1139 1043 945 871 792 732 650	45183 3106 42077	MBbl Co Net	- - - - - - - - - - - - - - - - - - - -
	3347 5626 5705 4338 3426 2902 2542 2241 2007 1809 1633 1464 1327 1211 1106 1004 926 841 778 691	48225 3301 44923	MBbl MBbl Bbl/d Count Co Grs Gross Gr. Daily Gr. Well Bitumen	- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
	4176 6434 6963 5242 4158 3530 3092 2723 2442 2203 1992 1785 1608 1454 1327 1188 1083 985 913 813	57897 3787 54110
	11440 17629 19025 14363 11393 9671 8447 7460 6689 6036 5442 4891 4404 3982 3626 3255 2968 2699 2494 2226
	84 90 94 94 91 87 84 81 80 80 80 76 74 68 68 64 59 58 54 53
Year $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Light & Medium Oil	61.76 70.84 74.58 78.82 80.49 82.18 83.90 85.66 87.47 89.30 91.18 93.07 95.00 96.97 98.99 101.06 103.16 105.29 107.47 109.69		Year $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Heavy Oil	2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
	46.8 41.1 36.9 32.8 29.8 27.3 25.0 22.9 20.9 19.1 17.6 16.4 15.3 14.3 13.5 12.4 11.4 9.8 9.1 7.5	444.8 14.9 429.8
	49.7 44.4 39.9 35.7 32.3 29.5 27.0 24.8 22.6 21.0 19.4 18.1 16.9 15.8 14.9 13.7 12.7 11.0 10.2 8.5	485.1 17.0 468.1
	94.3 84.0 75.2 67.0 60.5 55.2 50.3 46.0 41.8 38.7 35.7 33.2 31.0 29.1 27.3 25.0 22.8 19.3 17.8 14.9	901.1 31.9 869.3
	2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 258 33 230 33 205 33 184 33 166 31 151 31 137 31 126 30 115 29 106 28 98 27 91 27 85 27 80 27 75 27 68 27 63 25 53 23 49 20 41 18

– II-82 –

COMPETENT PERSON’S REPORT

APPENDIX II

Consolidated
Canlin Energy Corporation
As Of Date : 2017-12-31
Appendix C
Summary of Reserves and Net Present Values
Total Proved + Probable
Production Start : 2018-01-01
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
Income
Other Exp.
Opex
MinTax
Resource
Production
Crown Adj
Crown
Other
Royalty
Sulphur
NGL
Gas
Oil
Year
Operating
Royalties
Revenue
14372.5
0.0
5302.7
0.0
275.4
0.0
412.3
2674.5
1670.0
51.5
0.0
6907.5
10516.1
3067.7
2018
26748.2
0.0
6777.0
0.0
282.1
0.0
553.3
3599.5
1483.4
51.3
0.0
13177.4
18994.2
3147.2
2019
30497.2
0.0
7052.1
0.0
282.7
0.0
555.0
3866.2
1327.8
52.0
0.0
14011.8
22773.5
2978.1
2020
23636.8
0.0
6374.1
0.0
265.0
0.0
468.1
3610.9
1186.4
47.7
0.0
11250.8
18122.6
2811.3
2021
18706.4
0.0
5809.9
0.0
243.6
0.0
425.5
3463.8
1070.9
43.6
0.0
9135.7
14951.4
2596.5
2022
15897.9
0.0
5500.2
0.0
226.5
0.0
375.5
3138.4
961.2
39.7
0.0
7934.8
13027.6
2424.1
2023
13872.1
0.0
5311.2
0.0
211.8
0.0
344.6
2958.7
857.9
36.4
0.0
7123.3
11724.0
2267.7
2024
12354.3
0.0
5122.7
0.0
197.4
0.0
292.4
2574.8
761.4
33.5
0.0
6431.6
10606.2
2124.1
2025
11110.6
0.0
5022.6
0.0
185.5
0.0
255.9
2289.7
683.9
31.1
0.0
5897.2
9759.6
1980.6
2026
10640.9
0.0
4975.8
0.0
174.8
0.0
216.8
1398.0
614.8
28.9
0.0
5442.5
9013.6
1872.8
2027
9656.2
0.0
4851.8
0.0
163.0
0.0
191.4
1239.6
554.8
27.1
0.0
5026.5
8341.5
1769.3
2028
8692.1
0.0
4687.6
0.0
150.1
0.0
168.5
1098.3
504.4
25.3
0.0
4609.9
7639.6
1680.4
2029
7863.3
0.0
4593.6
0.0
140.6
0.0
152.6
997.7
451.7
23.8
0.0
4275.3
7087.6
1604.2
2030
7104.8
0.0
4541.9
0.0
131.7
0.0
140.1
919.0
409.5
22.4
0.0
3989.6
6600.7
1535.0
2031
6445.9
0.0
4466.3
0.0
121.6
0.0
129.7
857.8
365.5
21.2
0.0
3730.3
6169.2
1475.6
2032
5784.0
0.0
4321.3
0.0
112.8
0.0
119.2
797.8
319.6
11.3
0.0
3460.1
5716.9
1388.8
2033
5213.1
0.0
4279.7
0.0
106.8
0.0
111.4
755.1
298.8
0.0
0.0
3259.4
5375.7
1309.4
2034
4705.4
0.0
4007.9
0.0
95.6
0.0
102.5
703.3
277.1
0.0
0.0
3014.8
4962.8
1154.9
2035
4275.9
0.0
3950.1
0.0
89.0
0.0
96.7
673.2
254.3
0.0
0.0
2849.1
4690.0
1098.0
2036
3838.7
0.0
3534.9
0.0
76.3
0.0
87.4
617.2
230.6
0.0
0.0
2578.9
4235.5
934.7
2037
259045.8
0.0
117533.1
0.0
3681.1
0.0
5662.9
41368.4
14977.0
546.6
0.0
137322.6
221975.1
41144.2
Total
17629.6
0.0
17050.1
0.0
148.8
0.0
463.9
3135.0
692.9
0.0
0.0
13216.1
21666.7
1923.9
15 Years
241416.2
0.0
100483.0
0.0
3532.3
0.0
5199.0
38233.4
14284.1
546.6
0.0
124106.5
200308.3
39220.4
Sub Total
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
Cum.
Tax
Tax
Reclaim.
/Severance
Revenue
Revenue
Capital
COGPE
CDE
CEE
Capital
Year
BTax
Before
Sask.
Aband. &
AdValorem
Cum. Net
Net
Total
Other
-2681.9
-2681.9
0.0
0.0
0.0
-2681.9
-2681.9
17054.4
0.0
17054.4
0.0
0.0
2018
-1906.6
775.3
0.0
0.0
0.0
-1906.6
775.3
25972.9
0.0
25370.4
0.0
602.5
2019
12906.0
14812.6
0.0
0.0
0.0
12906.0
14812.6
15684.5
0.0
14657.8
0.0
1026.8
2020
36542.8
23636.8
0.0
0.0
0.0
36542.8
23636.8
0.0
0.0
0.0
0.0
0.0
2021
55249.2
18706.4
0.0
0.0
0.0
55249.2
18706.4
0.0
0.0
0.0
0.0
0.0
2022
71147.1
15897.9
0.0
0.0
0.0
71147.1
15897.9
0.0
0.0
0.0
0.0
0.0
2023
85019.2
13872.1
0.0
0.0
0.0
85019.2
13872.1
0.0
0.0
0.0
0.0
0.0
2024
97373.5
12354.3
0.0
0.0
0.0
97373.5
12354.3
0.0
0.0
0.0
0.0
0.0
2025
108121.2
10747.6
0.0
363.0
0.0
108484.2
11110.6
0.0
0.0
0.0
0.0
0.0
2026
118446.4
10325.2
0.0
315.7
0.0
119125.0
10640.9
0.0
0.0
0.0
0.0
0.0
2027
127892.5
9446.1
0.0
210.1
0.0
128781.2
9656.2
0.0
0.0
0.0
0.0
0.0
2028
136384.2
8491.7
0.0
200.4
0.0
137473.3
8692.1
0.0
0.0
0.0
0.0
0.0
2029
144088.2
7704.0
0.0
159.3
0.0
145336.6
7863.3
0.0
0.0
0.0
0.0
0.0
2030
151126.3
7038.2
0.0
66.6
0.0
152441.4
7104.8
0.0
0.0
0.0
0.0
0.0
2031
157509.7
6383.4
0.0
62.5
0.0
158887.3
6445.9
0.0
0.0
0.0
0.0
0.0
2032
162821.4
5311.7
0.0
472.4
0.0
164671.3
5784.0
0.0
0.0
0.0
0.0
0.0
2033
167936.3
5114.9
0.0
98.3
0.0
169884.4
5213.1
0.0
0.0
0.0
0.0
0.0
2034
172294.4
4358.2
0.0
347.2
0.0
174589.8
4705.4
0.0
0.0
0.0
0.0
0.0
2035
176570.3
4275.9
0.0
0.0
0.0
178865.6
4275.9
0.0
0.0
0.0
0.0
0.0
2036
180005.1
3434.8
0.0
403.9
0.0
182704.3
3838.7
0.0
0.0
0.0
0.0
0.0
2037
185556.8
0.0
14777.1
0.0
200333.9
58711.9
0.0
57082.6
0.0
1629.2
Total
5551.8
0.0
12077.8
0.0
17629.6
0.0
0.0
0.0
0.0
0.0
15 Years
180005.1
0.0
2699.3
0.0
182704.3
58711.9
0.0
57082.6
0.0
1629.2
Sub Total

– II-83 –

COMPETENT PERSON’S REPORT

APPENDIX II

Consolidated Canlin Energy Corporation As Of Date : 2017-12-31 Summary of Reserves and Net Present Values Appendix C-A Total Proved Production Start : 2018-01-01 MBoe MLt MBbl MBbl MBbl MBbl MBbl MMcf MMcf MMcf MMcf MBbl MBbl MBbl MBbl MBbl Equiv. Oil Sulphur Total NGL Pentane Plus Butane Propane Ethane Shale Gas CBM Non-Assoc Assoc Gas Solution Gas Tight Oil Synthetic Bitumen Heavy Oil Lt Med Oil	6098.1 0.0 1004.9 512.6 293.9 193.9 4.6 0 0 27494 1004 0.0 0.0 0.0 0.0 343.5 Co. Net 6726.8 0.0 1285.3 658.5 372.3 249.6 4.9 0 0 29289 1131 0.0 0.0 0.0 0.0 371.4 Co. Gr. 8761.0 0.0 1629.6 830.5 476.7 316.3 6.2 0 0 36403 2299 0.0 0.0 0.0 0.0 681.0 Gross M$ M$ M$ M$ M$ M$ % M$ M$ M$ M$ M$ M$ M$ boe/d Mcf/d bbl/d Cash Flow Reclaim. Capital Expenses Other Exp. Opex Royalty Royalty Non-Crown Crown Revenue Revenue Revenue Revenue Gross Gross Gross Year BTax Aband. & Total Total Total Total Total Other Gas Oil BOE Comp. Gas Comp. Oil Comp.	12706.9 0.0 0.0 5016.9 0.0 5016.9 11.8 2375.8 265.2 2110.6 20099.6 7823.8 9291.4 2984.4 1911.2 8519 132.3 2018 -7792.9 0.0 25972.9 5589.5 0.0 5589.5 10.6 2811.6 264.9 2546.7 26581.1 10567.5 13029.2 2984.5 2385.4 10867 115.4 2019 20058.2 0.0 887.7 5753.5 0.0 5753.5 9.7 2867.8 258.7 2609.1 29567.2 11066.6 15747.9 2752.7 2407.5 11041 100.8 2020 15391.5 0.0 0.0 5082.0 0.0 5082.0 11.1 2562.4 238.1 2324.3 23035.9 8599.0 11873.8 2563.0 1760.9 8003 89.0 2021 12641.8 0.0 0.0 4771.1 0.0 4771.1 11.8 2340.3 217.6 2122.7 19753.2 7298.3 10131.8 2323.1 1448.7 6556 79.0 2022 10518.6 154.9 0.0 4536.0 0.0 4536.0 12.3 2124.3 197.8 1926.5 17333.9 6381.8 8843.4 2108.7 1234.9 5575 70.3 2023 9223.5 32.0 0.0 4308.8 0.0 4308.8 12.1 1869.8 179.7 1690.0 15434.0 5661.0 7851.0 1922.0 1067.7 4811 62.5 2024 7644.1 380.9 0.0 4058.6 0.0 4058.6 11.9 1637.9 160.9 1477.0 13721.5 5007.2 6950.8 1763.6 926.7 4165 56.4 2025 6949.7 87.3 0.0 3941.2 0.0 3941.2 11.6 1446.1 145.2 1300.9 12424.4 4508.4 6284.3 1631.8 817.2 3667 51.1 2026 6387.5 256.9 0.0 3855.1 0.0 3855.1 7.1 804.5 132.8 671.7 11304.0 4086.1 5707.9 1509.9 725.8 3252 46.3 2027 5493.0 359.7 0.0 3727.3 0.0 3727.3 6.9 715.4 121.9 593.4 10295.3 3705.2 5195.2 1395.0 643.2 2878 41.8 2028 4636.7 447.5 0.0 3588.3 0.0 3588.3 6.8 633.0 109.9 523.0 9305.4 3330.5 4673.7 1301.2 569.9 2544 38.3 2029 4128.0 317.8 0.0 3360.7 0.0 3360.7 6.8 566.1 101.7 464.4 8372.5 2981.0 4186.0 1205.5 500.5 2229 34.7 2030 3706.5 175.2 0.0 3132.1 0.0 3132.1 6.7 503.8 89.6 414.3 7517.6 2686.6 3761.1 1069.9 440.5 1963 30.2 2031 3310.4 94.7 0.0 2916.3 0.0 2916.3 6.7 453.2 78.2 375.0 6774.6 2423.3 3398.0 953.3 388.1 1731 26.3 2032 2575.6 378.8 0.0 2640.3 0.0 2640.3 6.7 403.3 65.9 337.4 5998.0 2147.3 3016.2 834.5 338.0 1509 22.6 2033 2001.1 591.5 0.0 2427.6 0.0 2427.6 6.8 364.5 56.3 308.2 5384.7 1951.3 2723.1 710.3 297.8 1335 18.9 2034 1902.8 229.5 0.0 1547.8 0.0 1547.8 6.2 241.6 9.1 232.4 3921.7 1602.6 2275.2 44.0 228.9 1090 1.2 2035 23.2 908.2 0.0 445.9 0.0 445.9 7.0 103.5 0.0 103.5 1480.9 559.5 921.3 0.0 90.0 431 0.0 2036 115.8 739.7 0.0 446.2 0.0 446.2 7.0 98.0 0.0 98.0 1399.7 529.6 870.1 0.0 83.6 400 0.0 2037	116048.5 12249.6 26860.6 72042.1 0.0 72042.1 25106.9 2693.5 22413.4 252307.7 93901.7 128348.7 30057.3 Total -5573.6 7095.1 0.0 896.8 0.0 896.8 184.0 0.0 184.0 2602.4 984.9 1617.5 0.0 7 Years 121622.1 5154.5 26860.6 71145.3 0.0 71145.3 24922.9 2693.5 22229.4 249705.4 92916.8 126731.3 30057.3 Sub Total	87460.2 4966.4 25064.5 50573.8 0.0 50573.8 19279.4 2019.0 17260.4 187344.2 70062.7 94880.4 22401.1 5% Discount 68234.9 2247.5 23469.9 38069.9 0.0 38069.9 15535.1 1595.7 13939.5 147557.4 55437.6 74482.7 17637.0 10% Discount 62360.5 1686.2 22881.5 34523.1 0.0 34523.1 14400.2 1469.9 12930.3 135851.6 51126.9 68494.8 16229.8 12% Discount 54978.8 1129.5 22046.3 30235.8 0.0 30235.8 12971.0 1313.7 11657.3 121361.4 45783.4 61089.9 14488.1 15% Discount 48954.5 782.9 21263.6 26870.0 0.0 26870.0 11796.4 1187.5 10608.9 109667.4 41463.0 55118.8 13085.5 18% Discount 45537.0 624.0 20768.6 25011.1 0.0 25011.1 11124.6 1116.2 10008.4 103065.3 39020.1 51749.4 12295.8 20% Discount 38593.9 373.7 19616.6 21338.9 0.0 21338.9 9740.9 971.8 8769.2 89663.9 34050.5 44912.6 10700.9 25% Discount $/BOE 7.19 8.8 3.4 years 22.0 years First Year Co Gr. Operating Costs Reserve Life Index Reserve Half Life Reserve Life
						Version : 16.2.0.45 DB : Canlin22221.vndl Canlin Energy Corporation Run Time : 18/04/02 15:10 Run By : carolinh Price : 2017-12-31 SAL Prices Scenario : NI51-101 Project : 22221 - Report : H4 Page : 1 of 1

– II-84 –

COMPETENT PERSON’S REPORT

APPENDIX II

			$/Lt MLt MLt MLt Price Co Net Co Grs Gross Sulphur - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - $/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Butane 37.65 27.9 38.2 50.8 44.50 38.1 48.4 59.6 46.68 39.6 49.3 64.2 49.11 27.3 35.7 46.7 50.29 21.7 29.3 38.2 51.51 18.1 24.9 32.4 52.74 15.7 21.6 28.1 54.01 13.5 18.6 24.1 55.31 12.0 16.4 21.2 56.63 12.9 14.6 18.8 57.98 11.5 12.9 16.3 59.35 10.2 11.4 14.1 60.75 8.9 10.0 12.4 62.19 7.8 8.8 10.9 63.68 6.9 7.8 9.6 65.17 6.0 6.8 8.3 66.71 5.3 6.0 7.4 68.52 4.2 4.8 5.8 70.11 1.7 1.9 2.2 71.73 1.5 1.8 2.0 293.9 372.3 476.7 2.8 3.2 3.6 291.1 369.1 473.1 $/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Pentane Plus 63.57 47.0 66.9 87.0 71.45 65.7 85.8 103.7 74.67 69.0 87.6 112.8 78.21 47.2 63.2 81.5 79.94 37.6 51.8 66.4 81.69 31.4 44.0 56.3 83.49 27.3 38.1 48.7 85.32 23.7 32.9 42.0 87.18 21.1 29.0 36.9 89.09 22.9 25.7 32.6 91.03 20.4 22.8 28.4 92.94 18.1 20.1 24.5 94.89 15.8 17.6 21.5 96.86 14.0 15.5 19.0 98.87 12.4 13.7 16.8 100.93 10.7 11.9 14.5 103.03 9.5 10.6 12.9 105.08 7.8 8.7 10.6 107.27 3.0 3.4 3.9 109.50 2.8 3.2 3.6 512.6 658.5 830.5 5.1 5.8 6.5 507.6 652.8 823.9 Year 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 Total 2 Years Sub Tot $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Heavy Oil - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Bitumen - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -	$/Lt MLt MLt MLt Price Co Net Co Grs Gross Sulphur - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - $/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Butane 37.65 27.9 38.2 50.8 44.50 38.1 48.4 59.6 46.68 39.6 49.3 64.2 49.11 27.3 35.7 46.7 50.29 21.7 29.3 38.2 51.51 18.1 24.9 32.4 52.74 15.7 21.6 28.1 54.01 13.5 18.6 24.1 55.31 12.0 16.4 21.2 56.63 12.9 14.6 18.8 57.98 11.5 12.9 16.3 59.35 10.2 11.4 14.1 60.75 8.9 10.0 12.4 62.19 7.8 8.8 10.9 63.68 6.9 7.8 9.6 65.17 6.0 6.8 8.3 66.71 5.3 6.0 7.4 68.52 4.2 4.8 5.8 70.11 1.7 1.9 2.2 71.73 1.5 1.8 2.0 293.9 372.3 476.7 2.8 3.2 3.6 291.1 369.1 473.1 $/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Pentane Plus 63.57 47.0 66.9 87.0 71.45 65.7 85.8 103.7 74.67 69.0 87.6 112.8 78.21 47.2 63.2 81.5 79.94 37.6 51.8 66.4 81.69 31.4 44.0 56.3 83.49 27.3 38.1 48.7 85.32 23.7 32.9 42.0 87.18 21.1 29.0 36.9 89.09 22.9 25.7 32.6 91.03 20.4 22.8 28.4 92.94 18.1 20.1 24.5 94.89 15.8 17.6 21.5 96.86 14.0 15.5 19.0 98.87 12.4 13.7 16.8 100.93 10.7 11.9 14.5 103.03 9.5 10.6 12.9 105.08 7.8 8.7 10.6 107.27 3.0 3.4 3.9 109.50 2.8 3.2 3.6 512.6 658.5 830.5 5.1 5.8 6.5 507.6 652.8 823.9 Year 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 Total 2 Years Sub Tot $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Heavy Oil - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Bitumen - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
$/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Propane	16.21 22.94 25.50 27.96 29.41 30.38 31.37 32.37 33.40 34.44 35.51 36.43 37.36 38.29 39.25 40.23 41.23 42.11 43.15 44.21		$/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Pentane Plus	63.57 47.0 66.9 87.0 71.45 65.7 85.8 103.7 74.67 69.0 87.6 112.8 78.21 47.2 63.2 81.5 79.94 37.6 51.8 66.4 81.69 31.4 44.0 56.3 83.49 27.3 38.1 48.7 85.32 23.7 32.9 42.0 87.18 21.1 29.0 36.9 89.09 22.9 25.7 32.6 91.03 20.4 22.8 28.4 92.94 18.1 20.1 24.5 94.89 15.8 17.6 21.5 96.86 14.0 15.5 19.0 98.87 12.4 13.7 16.8 100.93 10.7 11.9 14.5 103.03 9.5 10.6 12.9 105.08 7.8 8.7 10.6 107.27 3.0 3.4 3.9 109.50 2.8 3.2 3.6
	18.7 25.8 26.9 18.4 14.5 12.0 10.3 8.9 7.9 8.1 7.2 6.4 5.6 4.9 4.4 3.8 3.4 2.8 1.1 1.0	193.9 1.9 192.0
	25.5 32.6 33.2 24.0 19.6 16.7 14.4 12.5 11.0 9.7 8.6 7.6 6.7 5.9 5.2 4.5 4.0 3.3 1.3 1.2	249.6 2.2 247.4
	33.4 39.7 43.0 31.1 25.3 21.4 18.5 16.0 14.0 12.4 10.8 9.3 8.1 7.2 6.3 5.5 4.9 4.0 1.5 1.4	316.3 2.5 313.8
$/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Ethane	- - 0.91 1.33 1.76 2.03 2.31 2.59 2.88 3.17 3.47 3.72 3.98 4.25 4.51 4.79 5.07 5.35 5.65 5.94		$/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Butane	37.65 27.9 38.2 50.8 44.50 38.1 48.4 59.6 46.68 39.6 49.3 64.2 49.11 27.3 35.7 46.7 50.29 21.7 29.3 38.2 51.51 18.1 24.9 32.4 52.74 15.7 21.6 28.1 54.01 13.5 18.6 24.1 55.31 12.0 16.4 21.2 56.63 12.9 14.6 18.8 57.98 11.5 12.9 16.3 59.35 10.2 11.4 14.1 60.75 8.9 10.0 12.4 62.19 7.8 8.8 10.9 63.68 6.9 7.8 9.6 65.17 6.0 6.8 8.3 66.71 5.3 6.0 7.4 68.52 4.2 4.8 5.8 70.11 1.7 1.9 2.2 71.73 1.5 1.8 2.0
	0.5 5 0.6 6 0.6 7 0.4 5 0.4 4 0.3 3 0.3 3 0.2 2 0.2 2 0.2 2 0.2 2 0.1 1 0.1 1 0.1 1 0.1 1 0.1 1 0.1 1 0.1 1 0.0 0 0.0 0	4.6 9 0.0 0 4.6 9
	0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0.	4. 0. 4.
	0.6 0.8 0.8 0.6 0.5 0.4 0.4 0.3 0.3 0.2 0.2 0.2 0.2 0.1 0.1 0.1 0.1 0.1 0.0 0.0	6.2 0.0 6.1
$/Mcf MMcf MMcf MMcf Price Co Net Co Grs Gross Solution Gas	2.84 3.11 3.66 3.82 3.97 4.06 4.15 4.24 4.35 4.45 4.54 4.62 4.72 4.81 4.91 5.02 5.11 5.72 - -		$/Lt MLt MLt MLt Price Co Net Co Grs Gross Sulphur	- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
	146 125 105 92 81 70 61 53 48 43 37 33 30 25 21 18 15 1 - -	1004
	163 140 118 103 90 79 69 60 54 49 42 38 34 29 24 21 17 1 - -	1131
	354 302 248 214 186 161 138 120 107 96 80 69 61 51 42 37 30 3 - -	2299
$/Mcf MMcf MMcf MMcf Mcf/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Gas	3.00 3.29 3.90 4.07 4.24 4.36 4.47 4.59 4.71 4.82 4.95 5.05 5.16 5.27 5.38 5.49 5.61 5.72 5.85 5.96		$/Bbl Price	- - - - - - - - - - - - - - - - - - - -
	2731 3600 3701 2649 2154 1827 1585 1371 1209 1069 950 837 733 647 574 500 444 375 149 138	27494 249 27245	MBbl Co Net	- - - - - - - - - - - - - - - - - - - -
	2947 3827 3923 2818 2303 1955 1692 1461 1284 1138 1011 891 779 688 609 530 470 397 158 146	29289 263 29026	MBbl MBbl Bbl/d Count Co Grs Gross Gr. Daily Gr. Well Bitumen	- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
	3750 4547 4991 3585 2913 2467 2134 1836 1611 1422 1241 1070 939 832 736 637 567 483 179 166	36403 299 36105
	10274 12456 13637 9822 7980 6758 5830 5029 4413 3895 3392 2932 2572 2279 2011 1745 1553 1322 490 455
	80 85 87 82 81 77 74 70 66 65 62 57 49 48 44 39 36 32 7 7
Year $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Light & Medium Oil	61.79 70.88 74.64 78.86 80.53 82.24 83.98 85.74 87.54 89.38 91.27 93.17 95.10 97.06 99.06 101.09 103.21 103.49 - -		Year $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Heavy Oil	2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
	45.5 39.0 34.2 30.1 26.8 23.9 21.3 19.1 17.3 15.4 13.9 12.7 11.5 10.0 8.7 7.5 6.2 0.4 - -	343.5
	48.3 42.1 36.9 32.5 28.8 25.6 22.9 20.6 18.6 16.9 15.3 14.0 12.7 11.0 9.6 8.3 6.9 0.4 - -	371.4
	91.6 79.4 68.9 60.4 53.2 46.9 41.7 37.4 33.7 30.4 27.3 24.8 22.2 19.0 16.4 14.2 12.0 1.5 - -	681.0
	2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 251 32 218 32 188 31 165 31 146 31 129 30 114 28 102 27 92 27 83 26 74 26 68 24 61 24 52 22 45 19 39 17 33 16 4 2 0 - 0 -

– II-85 –

COMPETENT PERSON’S REPORT

APPENDIX II

Consolidated
Canlin Energy Corporation
As Of Date : 2017-12-31
Summary of Reserves and Net Present Values
Appendix C-A
Total Proved
Production Start : 2018-01-01
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
Income
Other Exp.
Opex
MinTax
Resource
Production
Crown Adj
Crown
Other
Royalty
Sulphur
NGL
Gas
Oil
Year
Operating
Royalties
Revenue
12706.9
0.0
5016.9
0.0
265.2
0.0
394.4
2505.1
1670.0
50.3
0.0
6103.5
9291.4
2984.4
2018
18180.0
0.0
5589.5
0.0
264.9
0.0
404.6
2951.4
1483.4
48.7
0.0
9035.3
13029.2
2984.5
2019
20945.9
0.0
5753.5
0.0
258.7
0.0
393.4
3002.5
1327.8
48.0
0.0
9690.8
15747.9
2752.7
2020
15391.5
0.0
5082.0
0.0
238.1
0.0
308.4
2632.7
1186.4
42.6
0.0
7370.0
11873.8
2563.0
2021
12641.8
0.0
4771.1
0.0
217.6
0.0
275.0
2397.7
1070.9
37.8
0.0
6189.7
10131.8
2323.1
2022
10673.6
0.0
4536.0
0.0
197.8
0.0
242.8
2169.3
961.2
33.3
0.0
5387.3
8843.4
2108.7
2023
9255.4
0.0
4308.8
0.0
179.7
0.0
207.8
1897.8
857.9
29.6
0.0
4773.5
7851.0
1922.0
2024
8025.1
0.0
4058.6
0.0
160.9
0.0
177.2
1654.1
761.4
26.3
0.0
4219.5
6950.8
1763.6
2025
7037.0
0.0
3941.2
0.0
145.2
0.0
154.5
1455.4
683.9
23.6
0.0
3800.8
6284.3
1631.8
2026
6644.4
0.0
3855.1
0.0
132.8
0.0
125.0
796.7
614.8
21.3
0.0
3450.0
5707.9
1509.9
2027
5852.7
0.0
3727.3
0.0
121.9
0.0
110.4
703.9
554.8
16.2
0.0
3134.2
5195.2
1395.0
2028
5084.2
0.0
3588.3
0.0
109.9
0.0
96.9
620.0
504.4
1.3
0.0
2824.9
4673.7
1301.2
2029
4445.7
0.0
3360.7
0.0
101.7
0.0
85.2
549.6
451.7
0.0
0.0
2529.3
4186.0
1205.5
2030
3881.7
0.0
3132.1
0.0
89.6
0.0
75.4
489.7
409.5
0.0
0.0
2277.1
3761.1
1069.9
2031
3405.1
0.0
2916.3
0.0
78.2
0.0
67.6
442.6
365.5
0.0
0.0
2057.8
3398.0
953.3
2032
2954.4
0.0
2640.3
0.0
65.9
0.0
59.8
397.2
319.6
0.0
0.0
1827.8
3016.2
834.5
2033
2592.6
0.0
2427.6
0.0
56.3
0.0
53.8
362.0
298.8
0.0
0.0
1652.5
2723.1
710.3
2034
2132.3
0.0
1547.8
0.0
9.1
0.0
44.5
277.0
221.7
0.0
0.0
1380.9
2275.2
44.0
2035
931.5
0.0
445.9
0.0
0.0
0.0
17.5
121.0
0.0
0.0
0.0
559.5
921.3
0.0
2036
855.5
0.0
446.2
0.0
0.0
0.0
16.5
114.6
0.0
0.0
0.0
529.6
870.1
0.0
2037
155158.7
0.0
72042.1
0.0
2693.5
0.0
3341.8
25755.2
13743.7
379.0
0.0
79779.0
128348.7
30057.3
Total
1521.5
0.0
896.8
0.0
0.0
0.0
31.0
214.9
0.0
0.0
0.0
984.9
1617.5
0.0
7 Years
153637.2
0.0
71145.3
0.0
2693.5
0.0
3310.9
25540.2
13743.7
379.0
0.0
78794.1
126731.3
30057.3
Sub Total
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
Cum.
Tax
Tax
Reclaim.
/Severance
Revenue
Revenue
Capital
COGPE
CDE
CEE
Capital
Year
BTax
Before
Sask.
Aband. &
AdValorem
Cum. Net
Net
Total
Other
12706.9
12706.9
0.0
0.0
0.0
12706.9
12706.9
0.0
0.0
0.0
0.0
0.0
2018
4914.0
-7792.9
0.0
0.0
0.0
4914.0
-7792.9
25972.9
0.0
25972.9
0.0
0.0
2019
24972.2
20058.2
0.0
0.0
0.0
24972.2
20058.2
887.7
0.0
887.7
0.0
0.0
2020
40363.7
15391.5
0.0
0.0
0.0
40363.7
15391.5
0.0
0.0
0.0
0.0
0.0
2021
53005.4
12641.8
0.0
0.0
0.0
53005.4
12641.8
0.0
0.0
0.0
0.0
0.0
2022
63524.1
10518.6
0.0
154.9
0.0
63679.0
10673.6
0.0
0.0
0.0
0.0
0.0
2023
72747.5
9223.5
0.0
32.0
0.0
72934.4
9255.4
0.0
0.0
0.0
0.0
0.0
2024
80391.7
7644.1
0.0
380.9
0.0
80959.5
8025.1
0.0
0.0
0.0
0.0
0.0
2025
87341.4
6949.7
0.0
87.3
0.0
87996.6
7037.0
0.0
0.0
0.0
0.0
0.0
2026
93728.9
6387.5
0.0
256.9
0.0
94641.0
6644.4
0.0
0.0
0.0
0.0
0.0
2027
99221.9
5493.0
0.0
359.7
0.0
100493.6
5852.7
0.0
0.0
0.0
0.0
0.0
2028
103858.7
4636.7
0.0
447.5
0.0
105577.8
5084.2
0.0
0.0
0.0
0.0
0.0
2029
107986.6
4128.0
0.0
317.8
0.0
110023.5
4445.7
0.0
0.0
0.0
0.0
0.0
2030
111693.2
3706.5
0.0
175.2
0.0
113905.2
3881.7
0.0
0.0
0.0
0.0
0.0
2031
115003.5
3310.4
0.0
94.7
0.0
117310.3
3405.1
0.0
0.0
0.0
0.0
0.0
2032
117579.2
2575.6
0.0
378.8
0.0
120264.7
2954.4
0.0
0.0
0.0
0.0
0.0
2033
119580.2
2001.1
0.0
591.5
0.0
122857.3
2592.6
0.0
0.0
0.0
0.0
0.0
2034
121483.1
1902.8
0.0
229.5
0.0
124989.7
2132.3
0.0
0.0
0.0
0.0
0.0
2035
121506.3
23.2
0.0
908.2
0.0
125921.1
931.5
0.0
0.0
0.0
0.0
0.0
2036
121622.1
115.8
0.0
739.7
0.0
126776.6
855.5
0.0
0.0
0.0
0.0
0.0
2037
116048.5
0.0
12249.6
0.0
128298.1
26860.6
0.0
26860.6
0.0
0.0
Total
-5573.6
0.0
7095.1
0.0
1521.5
0.0
0.0
0.0
0.0
0.0
7 Years
121622.1
0.0
5154.5
0.0
126776.6
26860.6
0.0
26860.6
0.0
0.0
Sub Total

– II-86 –

COMPETENT PERSON’S REPORT

APPENDIX II

Consolidated Canlin Energy Corporation As Of Date : 2017-12-31 Summary of Reserves and Net Present Values Appendix C-B Proved Developed Producing Production Start : 2018-01-01 MBoe MLt MBbl MBbl MBbl MBbl MBbl MMcf MMcf MMcf MMcf MBbl MBbl MBbl MBbl MBbl Equiv. Oil Sulphur Total NGL Pentane Plus Butane Propane Ethane Shale Gas CBM Non-Assoc Assoc Gas Solution Gas Tight Oil Synthetic Bitumen Heavy Oil Lt Med Oil	4168.1 0.0 633.6 319.5 188.0 123.0 3.1 0 0 18172 991 0.0 0.0 0.0 0.0 340.7 Co. Net 4648.7 0.0 864.8 441.5 252.7 167.3 3.3 0 0 19375 1117 0.0 0.0 0.0 0.0 368.6 Co. Gr. 6287.0 0.0 1129.7 572.6 334.5 218.4 4.2 0 0 24638 2259 0.0 0.0 0.0 0.0 674.5 Gross M$ M$ M$ M$ M$ M$ % M$ M$ M$ M$ M$ M$ M$ boe/d Mcf/d bbl/d Cash Flow Reclaim. Capital Expenses Other Exp. Opex Royalty Royalty Non-Crown Crown Revenue Revenue Revenue Revenue Gross Gross Gross Year BTax Aband. & Total Total Total Total Total Other Gas Oil BOE Comp. Gas Comp. Oil Comp.	12673.2 0.0 0.0 4972.8 0.0 4972.8 11.8 2365.0 263.9 2101.1 20011.0 7796.5 9248.0 2966.5 1902.1 8479 131.5 2018 11658.7 0.0 0.0 4669.7 0.0 4669.7 13.3 2495.8 261.8 2234.0 18824.2 7407.1 8482.7 2934.3 1592.4 7082 113.4 2019 11047.0 0.0 0.0 4456.3 0.0 4456.3 13.4 2393.3 256.2 2137.1 17896.6 6633.0 8554.9 2708.7 1353.7 6007 99.1 2020 9695.9 0.0 0.0 4208.8 0.0 4208.8 13.3 2128.6 236.3 1892.3 16033.3 5929.6 7579.7 2524.0 1156.0 5115 87.7 2021 8490.4 0.0 0.0 4034.7 0.0 4034.7 13.0 1873.6 216.0 1657.6 14398.7 5279.0 6830.6 2289.1 1002.2 4426 77.9 2022 7201.8 154.9 0.0 3886.0 0.0 3886.0 12.8 1653.5 196.3 1457.3 12896.3 4707.2 6098.5 2090.5 873.6 3849 69.6 2023 6351.9 32.0 0.0 3722.4 0.0 3722.4 12.7 1468.0 178.3 1289.7 11574.2 4200.3 5452.0 1922.0 761.3 3345 62.5 2024 5221.4 272.9 0.0 3502.1 0.0 3502.1 12.5 1290.4 159.6 1130.8 10286.7 3708.9 4814.2 1763.6 659.8 2889 56.4 2025 4673.2 87.3 0.0 3407.3 0.0 3407.3 12.4 1156.3 144.0 1012.2 9324.0 3339.3 4353.0 1631.8 582.3 2543 51.1 2026 4332.1 256.9 0.0 3340.5 0.0 3340.5 6.6 560.2 131.7 428.4 8489.7 3025.5 3954.3 1509.9 517.6 2256 46.3 2027 3724.8 256.8 0.0 3241.9 0.0 3241.9 6.5 504.2 121.9 382.3 7727.6 2739.1 3593.6 1395.0 458.3 1994 41.8 2028 2943.1 447.5 0.0 3115.3 0.0 3115.3 6.5 448.8 109.9 338.9 6954.6 2445.3 3208.1 1301.2 403.7 1749 38.3 2029 2582.7 317.8 0.0 2896.3 0.0 2896.3 6.5 401.9 101.7 300.2 6198.7 2162.6 2830.6 1205.5 350.2 1510 34.7 2030 2295.6 175.2 0.0 2674.4 0.0 2674.4 6.5 355.9 89.6 266.3 5501.0 1926.4 2504.6 1069.9 303.9 1310 30.2 2031 2035.6 72.1 0.0 2463.1 0.0 2463.1 6.5 317.5 78.2 239.3 4888.2 1712.0 2222.9 953.3 263.4 1135 26.3 2032 1409.0 357.9 0.0 2190.9 0.0 2190.9 6.6 278.6 65.9 212.7 4236.4 1482.8 1919.1 834.5 223.6 962 22.6 2033 909.0 591.5 0.0 1980.5 0.0 1980.5 6.7 248.3 56.3 192.0 3729.3 1326.4 1692.6 710.3 192.5 831 18.9 2034 897.3 229.5 0.0 1101.9 0.0 1101.9 5.6 132.6 9.1 123.5 2361.3 1012.9 1304.3 44.0 131.7 625 1.2 2035 -908.2 908.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 0.0 2036 -739.7 739.7 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0 0.0 2037	90434.5 10960.2 0.0 59864.8 0.0 59864.8 20072.2 2676.5 17395.7 181331.8 66834.0 84643.8 29854.0 Total -6060.1 6060.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 3 Years 96494.6 4900.1 0.0 59864.8 0.0 59864.8 20072.2 2676.5 17395.7 181331.8 66834.0 84643.8 29854.0 Sub Total	73783.5 4524.8 0.0 42667.7 0.0 42667.7 15809.5 2005.1 13804.4 136785.5 50725.7 63835.7 22224.2 5% Discount 61427.1 2063.6 0.0 32426.0 0.0 32426.0 12975.7 1584.1 11391.7 108892.4 40610.5 50800.5 17481.3 10% Discount 57465.9 1549.4 0.0 29488.7 0.0 29488.7 12100.8 1459.1 10641.7 100604.8 37597.6 46925.8 16081.4 12% Discount 52358.8 1037.1 0.0 25919.6 0.0 25919.6 10987.9 1303.8 9684.0 90303.3 33845.6 42107.9 14349.8 15% Discount 48076.7 717.0 0.0 23104.5 0.0 23104.5 10063.8 1178.4 8885.3 81962.0 30800.7 38205.3 12956.0 18% Discount 45598.2 570.2 0.0 21545.4 0.0 21545.4 9531.2 1107.6 8423.6 77245.0 29075.4 35997.7 12171.8 20% Discount 40438.4 339.2 0.0 18457.8 0.0 18457.8 8425.2 964.2 7461.0 67660.5 25560.7 31510.9 10588.9 25% Discount $/BOE 7.16 6.1 3.6 years 18.0 years First Year Co Gr. Operating Costs Reserve Life Index Reserve Half Life Reserve Life
						Version : 16.2.0.45 DB : Canlin22221.vndl Canlin Energy Corporation Run Time : 18/04/02 15:10 Run By : carolinh Price : 2017-12-31 SAL Prices Scenario : NI51-101 Project : 22221 - Report : H4 Page : 1 of 1

– II-87 –

COMPETENT PERSON’S REPORT

APPENDIX II

			$/Lt MLt MLt MLt Price Co Net Co Grs Gross Sulphur - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - $/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Butane 37.65 27.8 38.0 50.2 44.39 22.4 31.8 42.2 46.54 18.6 27.1 36.1 48.99 15.8 23.0 30.9 50.18 13.7 19.9 26.6 51.40 11.9 17.3 23.2 52.63 10.4 15.1 20.3 53.90 9.0 13.0 17.4 55.19 7.9 11.5 15.3 56.51 9.2 10.2 13.5 57.86 8.2 9.0 11.8 59.22 7.2 7.9 10.1 60.61 6.2 6.8 8.8 62.05 5.3 5.9 7.6 63.54 4.6 5.1 6.6 65.02 3.9 4.4 5.6 66.56 3.4 3.8 4.8 68.52 2.5 2.7 3.5 188.0 252.7 334.5 $/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Pentane Plus 63.57 46.8 66.6 86.1 71.47 37.2 55.6 72.3 74.70 30.9 47.4 61.8 78.23 26.3 40.2 52.8 79.96 23.0 34.8 45.5 81.72 20.1 30.2 39.6 83.52 17.7 26.4 34.5 85.35 15.3 22.7 29.7 87.21 13.6 20.0 26.2 89.12 16.2 17.7 23.1 91.07 14.4 15.7 20.3 92.98 12.5 13.8 17.2 94.94 10.8 11.9 14.9 96.91 9.4 10.3 13.0 98.92 8.1 9.0 11.3 100.98 6.9 7.6 9.5 103.08 5.9 6.5 8.3 105.08 4.5 5.0 6.4 319.5 441.5 572.6 Year 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Total $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Heavy Oil - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Bitumen - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -	$/Lt MLt MLt MLt Price Co Net Co Grs Gross Sulphur - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - $/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Butane 37.65 27.8 38.0 50.2 44.39 22.4 31.8 42.2 46.54 18.6 27.1 36.1 48.99 15.8 23.0 30.9 50.18 13.7 19.9 26.6 51.40 11.9 17.3 23.2 52.63 10.4 15.1 20.3 53.90 9.0 13.0 17.4 55.19 7.9 11.5 15.3 56.51 9.2 10.2 13.5 57.86 8.2 9.0 11.8 59.22 7.2 7.9 10.1 60.61 6.2 6.8 8.8 62.05 5.3 5.9 7.6 63.54 4.6 5.1 6.6 65.02 3.9 4.4 5.6 66.56 3.4 3.8 4.8 68.52 2.5 2.7 3.5 188.0 252.7 334.5 $/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Pentane Plus 63.57 46.8 66.6 86.1 71.47 37.2 55.6 72.3 74.70 30.9 47.4 61.8 78.23 26.3 40.2 52.8 79.96 23.0 34.8 45.5 81.72 20.1 30.2 39.6 83.52 17.7 26.4 34.5 85.35 15.3 22.7 29.7 87.21 13.6 20.0 26.2 89.12 16.2 17.7 23.1 91.07 14.4 15.7 20.3 92.98 12.5 13.8 17.2 94.94 10.8 11.9 14.9 96.91 9.4 10.3 13.0 98.92 8.1 9.0 11.3 100.98 6.9 7.6 9.5 103.08 5.9 6.5 8.3 105.08 4.5 5.0 6.4 319.5 441.5 572.6 Year 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Total $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Heavy Oil - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Bitumen - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
$/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Propane	16.21 23.00 25.58 28.02 29.47 30.44 31.43 32.43 33.46 34.51 35.58 36.50 37.44 38.37 39.32 40.32 41.31 42.11		$/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Pentane Plus	63.57 46.8 66.6 86.1 71.47 37.2 55.6 72.3 74.70 30.9 47.4 61.8 78.23 26.3 40.2 52.8 79.96 23.0 34.8 45.5 81.72 20.1 30.2 39.6 83.52 17.7 26.4 34.5 85.35 15.3 22.7 29.7 87.21 13.6 20.0 26.2 89.12 16.2 17.7 23.1 91.07 14.4 15.7 20.3 92.98 12.5 13.8 17.2 94.94 10.8 11.9 14.9 96.91 9.4 10.3 13.0 98.92 8.1 9.0 11.3 100.98 6.9 7.6 9.5 103.08 5.9 6.5 8.3 105.08 4.5 5.0 6.4
	18.6 15.0 12.4 10.5 9.1 7.9 6.9 5.9 5.2 5.7 5.1 4.4 3.8 3.3 2.9 2.4 2.1 1.6	123.0
	25.3 21.1 18.0 15.3 13.2 11.5 10.0 8.6 7.6 6.7 5.9 5.2 4.5 3.9 3.4 2.9 2.5 1.9	167.3
	33.1 27.7 23.6 20.2 17.4 15.1 13.2 11.3 10.0 8.8 7.7 6.5 5.6 4.9 4.3 3.6 3.1 2.4	218.4
$/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Ethane	- - 0.91 1.33 1.76 2.03 2.31 2.59 2.88 3.17 3.47 3.72 3.98 4.25 4.51 4.79 5.07 5.35		$/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Butane	37.65 27.8 38.0 50.2 44.39 22.4 31.8 42.2 46.54 18.6 27.1 36.1 48.99 15.8 23.0 30.9 50.18 13.7 19.9 26.6 51.40 11.9 17.3 23.2 52.63 10.4 15.1 20.3 53.90 9.0 13.0 17.4 55.19 7.9 11.5 15.3 56.51 9.2 10.2 13.5 57.86 8.2 9.0 11.8 59.22 7.2 7.9 10.1 60.61 6.2 6.8 8.8 62.05 5.3 5.9 7.6 63.54 4.6 5.1 6.6 65.02 3.9 4.4 5.6 66.56 3.4 3.8 4.8 68.52 2.5 2.7 3.5
	0.5 5 0.4 4 0.3 4 0.3 3 0.2 3 0.2 2 0.2 2 0.2 2 0.1 1 0.1 1 0.1 1 0.1 1 0.1 1 0.1 1 0.1 1 0.1 1 0.0 0 0.0 0	3.1 3
	0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0.	3.
	0.6 0.5 0.5 0.4 0.3 0.3 0.3 0.2 0.2 0.2 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.0	4.2
$/Mcf MMcf MMcf MMcf Price Co Net Co Grs Gross Solution Gas	2.84 3.11 3.66 3.81 3.96 4.06 4.15 4.24 4.35 4.45 4.54 4.62 4.72 4.81 4.91 5.02 5.11 5.72		$/Lt MLt MLt MLt Price Co Net Co Grs Gross Sulphur	- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
	144 122 102 89 78 69 61 53 48 43 37 33 30 25 21 18 15 1	991
	161 136 115 100 88 78 69 60 54 49 42 38 34 29 24 21 17 1	1117
	349 292 239 207 180 158 138 120 107 96 80 69 61 51 42 37 30 3	2259
$/Mcf MMcf MMcf MMcf Mcf/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Gas	3.00 3.29 3.90 4.07 4.24 4.36 4.47 4.59 4.71 4.82 4.95 5.05 5.16 5.27 5.38 5.49 5.61 5.72		$/Bbl Price	- - - - - - - - - - - - - - - - - -
	2719 2292 1955 1663 1438 1250 1089 938 825 727 646 563 485 422 367 311 269 215	18172	MBbl Co Net	- - - - - - - - - - - - - - - - - -
	2934 2449 2084 1767 1527 1327 1156 995 874 775 687 601 517 449 391 330 286 227	19375	MBbl MBbl Bbl/d Count Co Grs Gross Gr. Daily Gr. Well Bitumen	- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
	3710 3113 2665 2276 1961 1701 1485 1275 1120 989 867 736 637 558 486 409 357 289	24638
	10165 8529 7282 6237 5372 4661 4058 3494 3069 2711 2370 2017 1746 1530 1327 1120 978 792
	78 77 77 73 72 68 65 61 57 56 54 50 42 41 37 32 29 25
Year $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Light & Medium Oil	61.80 70.91 74.66 78.89 80.56 82.25 83.98 85.74 87.54 89.38 91.27 93.17 95.10 97.06 99.06 101.09 103.21 103.49		Year $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Heavy Oil	2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
	45.2 38.3 33.6 29.6 26.4 23.6 21.3 19.1 17.3 15.4 13.9 12.7 11.5 10.0 8.7 7.5 6.2 0.4	340.7
	48.0 41.4 36.3 32.0 28.4 25.4 22.9 20.6 18.6 16.9 15.3 14.0 12.7 11.0 9.6 8.3 6.9 0.4	368.6
	90.9 77.7 67.5 59.2 52.2 46.4 41.7 37.4 33.7 30.4 27.3 24.8 22.2 19.0 16.4 14.2 12.0 1.5	674.5
	2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 249 31 213 30 184 29 162 29 143 29 127 28 114 28 102 27 92 27 83 26 74 26 68 24 61 24 52 22 45 19 39 17 33 16 4 2

– II-88 –

COMPETENT PERSON’S REPORT

APPENDIX II

Consolidated
Canlin Energy Corporation
As Of Date : 2017-12-31
Summary of Reserves and Net Present Values
Appendix C-B
Proved Developed Producing
Production Start : 2018-01-01
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
Income
Other Exp.
Opex
MinTax
Resource
Production
Crown Adj
Crown
Other
Royalty
Sulphur
NGL
Gas
Oil
Year
Operating
Royalties
Revenue
12673.2
0.0
4972.8
0.0
263.9
0.0
393.2
2494.3
1670.0
50.3
0.0
6076.2
9248.0
2966.5
2018
11658.7
0.0
4669.7
0.0
261.8
0.0
298.2
2532.1
1483.4
48.7
0.0
5875.0
8482.7
2934.3
2019
11047.0
0.0
4456.3
0.0
256.2
0.0
249.2
2386.3
1327.8
48.0
0.0
5257.2
8554.9
2708.7
2020
9695.9
0.0
4208.8
0.0
236.3
0.0
205.5
2097.9
1186.4
42.6
0.0
4700.6
7579.7
2524.0
2021
8490.4
0.0
4034.7
0.0
216.0
0.0
178.7
1836.3
1070.9
37.8
0.0
4170.3
6830.6
2289.1
2022
7356.7
0.0
3886.0
0.0
196.3
0.0
156.8
1614.1
961.2
33.3
0.0
3712.7
6098.5
2090.5
2023
6383.8
0.0
3722.4
0.0
178.3
0.0
139.0
1428.6
857.9
29.6
0.0
3312.8
5452.0
1922.0
2024
5494.2
0.0
3502.1
0.0
159.6
0.0
121.6
1252.4
761.4
26.3
0.0
2921.2
4814.2
1763.6
2025
4760.5
0.0
3407.3
0.0
144.0
0.0
108.9
1121.1
683.9
23.6
0.0
2631.7
4353.0
1631.8
2026
4589.0
0.0
3340.5
0.0
131.7
0.0
86.0
514.5
614.8
21.3
0.0
2389.4
3954.3
1509.9
2027
3981.5
0.0
3241.9
0.0
121.9
0.0
76.1
458.4
554.8
16.2
0.0
2168.2
3593.6
1395.0
2028
3390.5
0.0
3115.3
0.0
109.9
0.0
66.5
405.3
504.4
1.3
0.0
1939.7
3208.1
1301.2
2029
2900.4
0.0
2896.3
0.0
101.7
0.0
57.8
358.0
451.7
0.0
0.0
1710.9
2830.6
1205.5
2030
2470.7
0.0
2674.4
0.0
89.6
0.0
50.5
316.8
409.5
0.0
0.0
1516.9
2504.6
1069.9
2031
2107.6
0.0
2463.1
0.0
78.2
0.0
44.6
283.9
365.5
0.0
0.0
1346.5
2222.9
953.3
2032
1766.9
0.0
2190.9
0.0
65.9
0.0
38.6
251.3
319.6
0.0
0.0
1163.3
1919.1
834.5
2033
1500.6
0.0
1980.5
0.0
56.3
0.0
34.1
226.1
298.8
0.0
0.0
1027.6
1692.6
710.3
2034
1126.8
0.0
1101.9
0.0
9.1
0.0
26.1
149.5
221.7
0.0
0.0
791.3
1304.3
44.0
2035
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2036
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2037
101394.7
0.0
59864.8
0.0
2676.5
0.0
2331.3
19727.1
13743.7
379.0
0.0
52711.3
84643.8
29854.0
Total
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
3 Years
101394.7
0.0
59864.8
0.0
2676.5
0.0
2331.3
19727.1
13743.7
379.0
0.0
52711.3
84643.8
29854.0
Sub Total
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
Cum.
Tax
Tax
Reclaim.
/Severance
Revenue
Revenue
Capital
COGPE
CDE
CEE
Capital
Year
BTax
Before
Sask.
Aband. &
AdValorem
Cum. Net
Net
Total
Other
12673.2
12673.2
0.0
0.0
0.0
12673.2
12673.2
0.0
0.0
0.0
0.0
0.0
2018
24331.9
11658.7
0.0
0.0
0.0
24331.9
11658.7
0.0
0.0
0.0
0.0
0.0
2019
35378.9
11047.0
0.0
0.0
0.0
35378.9
11047.0
0.0
0.0
0.0
0.0
0.0
2020
45074.8
9695.9
0.0
0.0
0.0
45074.8
9695.9
0.0
0.0
0.0
0.0
0.0
2021
53565.3
8490.4
0.0
0.0
0.0
53565.3
8490.4
0.0
0.0
0.0
0.0
0.0
2022
60767.1
7201.8
0.0
154.9
0.0
60922.0
7356.7
0.0
0.0
0.0
0.0
0.0
2023
67118.9
6351.9
0.0
32.0
0.0
67305.8
6383.8
0.0
0.0
0.0
0.0
0.0
2024
72340.3
5221.4
0.0
272.9
0.0
72800.1
5494.2
0.0
0.0
0.0
0.0
0.0
2025
77013.4
4673.2
0.0
87.3
0.0
77560.5
4760.5
0.0
0.0
0.0
0.0
0.0
2026
81345.5
4332.1
0.0
256.9
0.0
82149.5
4589.0
0.0
0.0
0.0
0.0
0.0
2027
85070.3
3724.8
0.0
256.8
0.0
86131.1
3981.5
0.0
0.0
0.0
0.0
0.0
2028
88013.4
2943.1
0.0
447.5
0.0
89521.6
3390.5
0.0
0.0
0.0
0.0
0.0
2029
90596.1
2582.7
0.0
317.8
0.0
92422.0
2900.4
0.0
0.0
0.0
0.0
0.0
2030
92891.6
2295.6
0.0
175.2
0.0
94892.8
2470.7
0.0
0.0
0.0
0.0
0.0
2031
94927.2
2035.6
0.0
72.1
0.0
97000.4
2107.6
0.0
0.0
0.0
0.0
0.0
2032
96336.2
1409.0
0.0
357.9
0.0
98767.3
1766.9
0.0
0.0
0.0
0.0
0.0
2033
97245.3
909.0
0.0
591.5
0.0
100267.9
1500.6
0.0
0.0
0.0
0.0
0.0
2034
98142.6
897.3
0.0
229.5
0.0
101394.7
1126.8
0.0
0.0
0.0
0.0
0.0
2035
97234.3
-908.2
0.0
908.2
0.0
101394.7
0.0
0.0
0.0
0.0
0.0
0.0
2036
96494.6
-739.7
0.0
739.7
0.0
101394.7
0.0
0.0
0.0
0.0
0.0
0.0
2037
90434.5
0.0
10960.2
0.0
101394.7
0.0
0.0
0.0
0.0
0.0
Total
-6060.1
0.0
6060.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
3 Years
96494.6
0.0
4900.1
0.0
101394.7
0.0
0.0
0.0
0.0
0.0
Sub Total

– II-89 –

COMPETENT PERSON’S REPORT

APPENDIX II

Consolidated
Canlin Energy Corporation
As Of Date : 2017-12-31
Summary of Reserves and Net Present Values
Appendix C-C
Proved Developed Non-Producing
Production Start : 2018-08-01
21.1
0.0
2.8
1.4
0.8
0.6
0.0
0
0
79
14
0.0
0.0
0.0
0.0
2.8
Co. Net
24.0
0.0
4.2
2.1
1.2
0.8
0.0
0
0
88
14
0.0
0.0
0.0
0.0
2.8
Co. Gr.
94.0
0.0
17.4
8.8
5.1
3.5
0.1
0
0
381
40
0.0
0.0
0.0
0.0
6.6
Gross
MBoe
MLt
MBbl
MBbl
MBbl
MBbl
MBbl
MMcf
MMcf
MMcf
MMcf
MBbl
MBbl
MBbl
MBbl
MBbl
Equiv. Oil
Sulphur
Total NGL
Pentane Plus
Butane
Propane
Ethane
Shale Gas
CBM
Non-Assoc
Assoc Gas
Solution Gas
Tight Oil
Synthetic
Bitumen
Heavy Oil
Lt Med Oil
M$
M$
M$
M$
M$
M$
%
M$
M$
M$
M$
M$
M$
M$
boe/d
Mcf/d
bbl/d
Cash Flow
Reclaim.
Capital
Expenses
Other Exp.
Opex
Royalty
Royalty
Non-Crown
Crown
Revenue
Revenue
Revenue
Revenue
Gross
Gross
Gross
Year
BTax
Aband. &
Total
Total
Total
Total
Total
Other
Gas
Oil
BOE
Comp.
Gas
Comp.
Oil
Comp.
33.6
0.0
0.0
44.1
0.0
44.1
12.2
10.8
1.3
9.5
88.6
27.4
43.3
17.9
21.6
95
1.9
2018
73.4
0.0
0.0
107.7
0.0
107.7
11.9
24.6
3.1
21.5
205.6
61.9
93.6
50.2
18.2
78
2.0
2019
53.5
0.0
0.0
86.3
0.0
86.3
11.1
17.5
2.6
15.0
157.3
41.5
71.8
44.0
12.1
50
1.6
2020
37.9
0.0
0.0
58.8
0.0
58.8
10.3
11.1
1.8
9.3
107.8
24.8
43.9
39.1
7.5
30
1.4
2021
25.6
0.0
0.0
58.3
0.0
58.3
10.1
9.4
1.7
7.7
93.3
21.2
38.1
34.0
6.3
25
1.2
2022
15.3
0.0
0.0
40.9
0.0
40.9
11.5
7.3
1.5
5.7
63.5
16.6
28.8
18.1
4.4
18
0.6
2023
9.9
0.0
0.0
18.1
0.0
18.1
16.5
5.5
1.4
4.1
33.5
12.7
20.8
0.0
2.7
13
0.0
2024
-102.2
108.0
0.0
18.0
0.0
18.0
16.5
4.7
1.3
3.4
28.5
10.8
17.8
0.0
2.2
11
0.0
2025
2.5
0.0
0.0
17.9
0.0
17.9
16.6
4.1
1.2
2.9
24.5
9.2
15.3
0.0
1.9
9
0.0
2026
1.2
0.0
0.0
16.4
0.0
16.4
9.6
1.9
1.1
0.8
19.5
7.3
12.1
0.0
1.4
7
0.0
2027
-102.9
102.9
0.0
0.7
0.0
0.7
14.2
0.1
0.1
0.0
0.9
0.3
0.5
0.0
0.1
0
0.0
2028
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0
0.0
2029
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0
0.0
2030
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0
0.0
2031
-22.6
22.6
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0
0.0
2032
-20.9
20.9
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0
0.0
2033
4.4
254.5
0.0
467.1
0.0
467.1
97.0
17.0
80.0
822.9
233.7
386.0
203.3
Total
68.6
157.5
0.0
395.0
0.0
395.0
82.5
13.9
68.7
703.6
199.0
327.7
176.9
5%
Discount
99.0
101.1
0.0
340.4
0.0
340.4
71.6
11.6
60.0
612.1
172.8
283.6
155.7
10%
Discount
105.8
85.5
0.0
322.2
0.0
322.2
67.9
10.9
57.0
581.3
164.1
268.9
148.4
12%
Discount
112.2
67.0
0.0
297.9
0.0
297.9
63.0
9.9
53.1
540.1
152.4
249.3
138.4
15%
Discount
115.4
53.0
0.0
276.9
0.0
276.9
58.8
9.1
49.7
504.0
142.3
232.3
129.4
18%
Discount
116.4
45.5
0.0
264.3
0.0
264.3
56.2
8.6
47.6
482.4
136.2
222.2
124.0
20%
Discount
115.8
31.7
0.0
237.0
0.0
237.0
50.7
7.6
43.1
435.2
123.0
200.1
112.0
25%
Discount
$/BOE 14.55
3.2
1.7 years
10.4 years
First Year Co Gr. Operating Costs
Reserve Life Index
Reserve Half Life
Reserve Life

– II-90 –

COMPETENT PERSON’S REPORT

APPENDIX II

			$/Lt MLt MLt MLt Price Co Net Co Grs Gross Sulphur - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - $/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Butane 37.93 0.1 0.2 0.5 44.69 0.2 0.3 1.1 46.85 0.1 0.2 0.8 49.32 0.1 0.1 0.6 50.52 0.1 0.1 0.5 51.75 0.1 0.1 0.4 53.00 0.0 0.1 0.3 54.27 0.0 0.0 0.3 55.57 0.0 0.0 0.2 56.90 0.0 0.0 0.2 58.26 0.0 0.0 0.0 0.8 1.2 5.1 $/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Pentane Plus 63.01 0.2 0.3 0.9 70.81 0.4 0.6 1.9 73.83 0.3 0.4 1.4 76.95 0.1 0.2 1.1 78.64 0.1 0.2 0.9 80.91 0.1 0.1 0.7 83.43 0.1 0.1 0.6 85.25 0.1 0.1 0.5 87.11 0.1 0.1 0.4 89.01 0.0 0.1 0.3 90.94 0.0 0.0 0.0 1.4 2.1 8.8 Year 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Total $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Heavy Oil - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Bitumen - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -	$/Lt MLt MLt MLt Price Co Net Co Grs Gross Sulphur - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - $/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Butane 37.93 0.1 0.2 0.5 44.69 0.2 0.3 1.1 46.85 0.1 0.2 0.8 49.32 0.1 0.1 0.6 50.52 0.1 0.1 0.5 51.75 0.1 0.1 0.4 53.00 0.0 0.1 0.3 54.27 0.0 0.0 0.3 55.57 0.0 0.0 0.2 56.90 0.0 0.0 0.2 58.26 0.0 0.0 0.0 0.8 1.2 5.1 $/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Pentane Plus 63.01 0.2 0.3 0.9 70.81 0.4 0.6 1.9 73.83 0.3 0.4 1.4 76.95 0.1 0.2 1.1 78.64 0.1 0.2 0.9 80.91 0.1 0.1 0.7 83.43 0.1 0.1 0.6 85.25 0.1 0.1 0.5 87.11 0.1 0.1 0.4 89.01 0.0 0.1 0.3 90.94 0.0 0.0 0.0 1.4 2.1 8.8 Year 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Total $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Heavy Oil - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Bitumen - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
$/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Propane	16.06 22.84 25.41 27.85 29.29 30.25 31.23 32.23 33.26 34.30 35.36		$/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Pentane Plus	63.01 0.2 0.3 0.9 70.81 0.4 0.6 1.9 73.83 0.3 0.4 1.4 76.95 0.1 0.2 1.1 78.64 0.1 0.2 0.9 80.91 0.1 0.1 0.7 83.43 0.1 0.1 0.6 85.25 0.1 0.1 0.5 87.11 0.1 0.1 0.4 89.01 0.0 0.1 0.3 90.94 0.0 0.0 0.0
	0.1 0.2 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0	0.6
	0.1 0.2 0.2 0.1 0.1 0.1 0.0 0.0 0.0 0.0 0.0	0.8
	0.4 0.8 0.6 0.4 0.4 0.3 0.2 0.2 0.2 0.1 0.0	3.5
$/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Ethane	- - 0.91 1.33 1.76 2.03 2.31 2.59 2.88 3.17 3.47		$/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Butane	37.93 0.1 0.2 0.5 44.69 0.2 0.3 1.1 46.85 0.1 0.2 0.8 49.32 0.1 0.1 0.6 50.52 0.1 0.1 0.5 51.75 0.1 0.1 0.4 53.00 0.0 0.1 0.3 54.27 0.0 0.0 0.3 55.57 0.0 0.0 0.2 56.90 0.0 0.0 0.2 58.26 0.0 0.0 0.0
	0.0 0 0.0 0 0.0 0 0.0 0 0.0 0 0.0 0 0.0 0 0.0 0 0.0 0 0.0 0 0.0 0	0.0 0
	0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0.	0.
	0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0	0.1
$/Mcf MMcf MMcf MMcf Price Co Net Co Grs Gross Solution Gas	3.00 3.29 3.90 4.07 4.24 4.36 - - - - -		$/Lt MLt MLt MLt Price Co Net Co Grs Gross Sulphur	- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
	2 4 3 2 2 1 - - - - -	14
	2 4 3 3 2 1 - - - - -	14
	5 10 9 7 6 3 - - - - -	40
$/Mcf MMcf MMcf MMcf Mcf/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Gas	3.00 3.29 3.90 4.07 4.24 4.36 4.47 4.59 4.71 4.82 4.95		$/Bbl Price	- - - - - - - - - - -
	12 23 14 7 6 5 4 3 3 2 0	79	MBbl Co Net	- - - - - - - - - - -
	13 25 15 8 7 6 5 4 3 3 0	88	MBbl MBbl Bbl/d Count Co Grs Gross Gr. Daily Gr. Well Bitumen	- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
	40 81 61 46 38 32 27 22 19 15 1	381
	259 221 168 127 105 87 73 61 51 40 2
	3 3 3 2 2 2 2 2 2 2 1
Year $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Light & Medium Oil	60.14 69.21 72.94 77.15 78.80 80.48 - - - - -		Year $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Heavy Oil	2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
	0.3 0.7 0.6 0.5 0.4 0.2 - - - - -	2.8
	0.3 0.7 0.6 0.5 0.4 0.2 - - - - -	2.8
	0.7 1.7 1.4 1.2 1.0 0.5 - - - - -	6.6
	2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 5 2 5 2 4 2 3 2 3 2 1 2 - - - - - - - - 0 -

– II-91 –

COMPETENT PERSON’S REPORT

APPENDIX II

Consolidated
Canlin Energy Corporation
As Of Date : 2017-12-31
Summary of Reserves and Net Present Values
Appendix C-C
Proved Developed Non-Producing
Production Start : 2018-08-01
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
Income
Other Exp.
Opex
MinTax
Resource
Production
Crown Adj
Crown
Other
Royalty
Sulphur
NGL
Gas
Oil
Year
Operating
Royalties
Revenue
33.6
0.0
44.1
0.0
1.3
0.0
1.2
10.7
0.0
0.0
0.0
27.4
43.3
17.9
2018
73.4
0.0
107.7
0.0
3.1
0.0
2.5
23.9
0.0
0.0
0.0
61.9
93.6
50.2
2019
53.5
0.0
86.3
0.0
2.6
0.0
1.7
16.6
0.0
0.0
0.0
41.5
71.8
44.0
2020
37.9
0.0
58.8
0.0
1.8
0.0
1.1
10.4
0.0
0.0
0.0
24.8
43.9
39.1
2021
25.6
0.0
58.3
0.0
1.7
0.0
0.9
8.7
0.0
0.0
0.0
21.2
38.1
34.0
2022
15.3
0.0
40.9
0.0
1.5
0.0
0.7
6.5
0.0
0.0
0.0
16.6
28.8
18.1
2023
9.9
0.0
18.1
0.0
1.4
0.0
0.5
4.7
0.0
0.0
0.0
12.7
20.8
0.0
2024
5.9
0.0
18.0
0.0
1.3
0.0
0.5
3.9
0.0
0.0
0.0
10.8
17.8
0.0
2025
2.5
0.0
17.9
0.0
1.2
0.0
0.4
3.3
0.0
0.0
0.0
9.2
15.3
0.0
2026
1.2
0.0
16.4
0.0
1.1
0.0
0.2
1.0
0.0
0.0
0.0
7.3
12.1
0.0
2027
0.0
0.0
0.7
0.0
0.1
0.0
0.0
0.0
0.0
0.0
0.0
0.3
0.5
0.0
2028
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2029
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2030
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2031
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2032
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2033
258.8
0.0
467.1
0.0
17.0
0.0
9.8
89.8
0.0
0.0
0.0
233.7
386.0
203.3
Total
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
Cum.
Tax
Tax
Reclaim.
/Severance
Revenue
Revenue
Capital
COGPE
CDE
CEE
Capital
Year
BTax
Before
Sask.
Aband. &
AdValorem
Cum. Net
Net
Total
Other
33.6
33.6
0.0
0.0
0.0
33.6
33.6
0.0
0.0
0.0
0.0
0.0
2018
107.1
73.4
0.0
0.0
0.0
107.1
73.4
0.0
0.0
0.0
0.0
0.0
2019
160.6
53.5
0.0
0.0
0.0
160.6
53.5
0.0
0.0
0.0
0.0
0.0
2020
198.5
37.9
0.0
0.0
0.0
198.5
37.9
0.0
0.0
0.0
0.0
0.0
2021
224.0
25.6
0.0
0.0
0.0
224.0
25.6
0.0
0.0
0.0
0.0
0.0
2022
239.3
15.3
0.0
0.0
0.0
239.3
15.3
0.0
0.0
0.0
0.0
0.0
2023
249.2
9.9
0.0
0.0
0.0
249.2
9.9
0.0
0.0
0.0
0.0
0.0
2024
147.1
-102.2
0.0
108.0
0.0
255.1
5.9
0.0
0.0
0.0
0.0
0.0
2025
149.6
2.5
0.0
0.0
0.0
257.6
2.5
0.0
0.0
0.0
0.0
0.0
2026
150.8
1.2
0.0
0.0
0.0
258.8
1.2
0.0
0.0
0.0
0.0
0.0
2027
47.9
-102.9
0.0
102.9
0.0
258.8
0.0
0.0
0.0
0.0
0.0
0.0
2028
47.9
0.0
0.0
0.0
0.0
258.8
0.0
0.0
0.0
0.0
0.0
0.0
2029
47.9
0.0
0.0
0.0
0.0
258.8
0.0
0.0
0.0
0.0
0.0
0.0
2030
47.9
0.0
0.0
0.0
0.0
258.8
0.0
0.0
0.0
0.0
0.0
0.0
2031
25.3
-22.6
0.0
22.6
0.0
258.8
0.0
0.0
0.0
0.0
0.0
0.0
2032
4.4
-20.9
0.0
20.9
0.0
258.8
0.0
0.0
0.0
0.0
0.0
0.0
2033
4.4
0.0
254.5
0.0
258.8
0.0
0.0
0.0
0.0
0.0
Total

– II-92 –

COMPETENT PERSON’S REPORT

APPENDIX II

Consolidated
Canlin Energy Corporation
As Of Date : 2017-12-31
Summary of Reserves and Net Present Values
Appendix C-D
Proved Undeveloped
Production Start : 2019-04-01
1908.9
0.0
368.5
191.6
105.0
70.3
1.5
0
0
9242
0
0.0
0.0
0.0
0.0
0.0
Co. Net
2054.2
0.0
416.4
215.0
118.4
81.4
1.6
0
0
9826
0
0.0
0.0
0.0
0.0
0.0
Co. Gr.
2380.0
0.0
482.5
249.1
137.1
94.4
1.9
0
0
11385
0
0.0
0.0
0.0
0.0
0.0
Gross
MBoe
MLt
MBbl
MBbl
MBbl
MBbl
MBbl
MMcf
MMcf
MMcf
MMcf
MBbl
MBbl
MBbl
MBbl
MBbl
Equiv. Oil
Sulphur
Total NGL
Pentane Plus
Butane
Propane
Ethane
Shale Gas
CBM
Non-Assoc
Assoc Gas
Solution Gas
Tight Oil
Synthetic
Bitumen
Heavy Oil
Lt Med Oil
M$
M$
M$
M$
M$
M$
%
M$
M$
M$
M$
M$
M$
M$
boe/d
Mcf/d
bbl/d
Cash Flow
Reclaim.
Capital
Expenses
Other Exp.
Opex
Royalty
Royalty
Non-Crown
Crown
Revenue
Revenue
Revenue
Revenue
Gross
Gross
Gross
Year
BTax
Aband. &
Total
Total
Total
Total
Total
Other
Gas
Oil
BOE
Comp.
Gas
Comp.
Oil
Comp.
-19525.0
0.0
25972.9
812.1
0.0
812.1
3.9
291.3
0.0
291.3
7551.3
3098.5
4452.8
0.0
1028.4
4919
0.0
2019
8957.7
0.0
887.7
1210.9
0.0
1210.9
4.0
457.1
0.0
457.1
11513.4
4392.1
7121.3
0.0
1041.7
4983
0.0
2020
5657.7
0.0
0.0
814.4
0.0
814.4
6.1
422.6
0.0
422.6
6894.8
2644.6
4250.2
0.0
597.4
2858
0.0
2021
4125.8
0.0
0.0
678.1
0.0
678.1
8.7
457.3
0.0
457.3
5261.3
1998.2
3263.1
0.0
440.3
2106
0.0
2022
3301.6
0.0
0.0
609.1
0.0
609.1
10.6
463.5
0.0
463.5
4374.2
1658.0
2716.2
0.0
356.9
1707
0.0
2023
2861.7
0.0
0.0
568.4
0.0
568.4
10.4
396.3
0.0
396.3
3826.3
1448.1
2378.2
0.0
303.7
1453
0.0
2024
2525.0
0.0
0.0
538.5
0.0
538.5
10.1
342.8
0.0
342.8
3406.3
1287.5
2118.8
0.0
264.6
1266
0.0
2025
2274.1
0.0
0.0
516.0
0.0
516.0
9.3
285.8
0.0
285.8
3075.9
1159.9
1916.0
0.0
233.0
1114
0.0
2026
2054.2
0.0
0.0
498.2
0.0
498.2
8.7
242.4
0.0
242.4
2794.8
1053.3
1741.5
0.0
206.8
989
0.0
2027
1871.1
0.0
0.0
484.6
0.0
484.6
8.2
211.1
0.0
211.1
2566.8
965.8
1601.1
0.0
184.8
884
0.0
2028
1693.7
0.0
0.0
473.0
0.0
473.0
7.8
184.2
0.0
184.2
2350.8
885.2
1465.6
0.0
166.2
795
0.0
2029
1545.3
0.0
0.0
464.4
0.0
464.4
7.6
164.2
0.0
164.2
2173.8
818.4
1355.4
0.0
150.3
719
0.0
2030
1411.0
0.0
0.0
457.8
0.0
457.8
7.3
147.9
0.0
147.9
2016.7
760.2
1256.5
0.0
136.6
654
0.0
2031
1297.4
0.0
0.0
453.3
0.0
453.3
7.2
135.7
0.0
135.7
1886.4
711.3
1175.1
0.0
124.8
597
0.0
2032
1187.5
0.0
0.0
449.4
0.0
449.4
7.1
124.7
0.0
124.7
1761.5
664.5
1097.0
0.0
114.4
547
0.0
2033
1092.0
0.0
0.0
447.1
0.0
447.1
7.0
116.2
0.0
116.2
1655.4
624.9
1030.5
0.0
105.3
504
0.0
2034
1005.6
0.0
0.0
445.9
0.0
445.9
7.0
109.0
0.0
109.0
1560.5
589.6
970.8
0.0
97.2
465
0.0
2035
931.5
0.0
0.0
445.9
0.0
445.9
7.0
103.5
0.0
103.5
1480.9
559.5
921.3
0.0
90.0
431
0.0
2036
855.5
0.0
0.0
446.2
0.0
446.2
7.0
98.0
0.0
98.0
1399.7
529.6
870.1
0.0
83.6
400
0.0
2037
790.2
0.0
0.0
447.5
0.0
447.5
7.0
93.8
0.0
93.8
1331.5
504.0
827.5
0.0
77.9
373
0.0
2038
25609.7
1035.0
26860.6
11710.2
0.0
11710.2
4937.6
0.0
4937.6
70153.0
26834.0
43319.0
0.0
Total
-303.7
1035.0
0.0
449.4
0.0
449.4
90.2
0.0
90.2
1270.9
480.9
790.0
0.0
6 Years
25913.4
0.0
26860.6
11260.8
0.0
11260.8
4847.4
0.0
4847.4
68882.2
26353.2
42529.0
0.0
Sub Total
13608.1
284.1
25064.5
7511.1
0.0
7511.1
3387.3
0.0
3387.3
49855.1
19138.0
30717.1
0.0
5%
Discount
6708.7
82.8
23469.9
5303.6
0.0
5303.6
2487.8
0.0
2487.8
38052.9
14654.2
23398.6
0.0
10%
Discount
4788.8
51.4
22881.5
4712.3
0.0
4712.3
2231.5
0.0
2231.5
34665.4
13365.3
21300.2
0.0
12%
Discount
2507.9
25.5
22046.3
4018.2
0.0
4018.2
1920.1
0.0
1920.1
30518.0
11785.3
18732.7
0.0
15%
Discount
762.3
12.9
21263.6
3488.6
0.0
3488.6
1673.9
0.0
1673.9
27201.3
10520.1
16681.2
0.0
18%
Discount
-177.5
8.3
20768.6
3201.4
0.0
3201.4
1537.2
0.0
1537.2
25338.0
9808.5
15529.5
0.0
20%
Discount
-1960.3
2.8
19616.6
2644.1
0.0
2644.1
1265.1
0.0
1265.1
21568.2
8366.7
13201.6
0.0
25%
Discount
$/BOE 2.91
3.9 years
6.3
1.8 years
20.8 years
First Year Co Gr. Operating Costs
Before Tax Payout
Reserve Life Index
Reserve Half Life
Reserve Life

– II-93 –

COMPETENT PERSON’S REPORT

APPENDIX II

			$/Lt MLt MLt MLt Price Co Net Co Grs Gross Sulphur - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - $/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Butane 44.69 15.5 16.3 16.3 46.85 20.9 22.0 27.3 49.32 11.4 12.6 15.2 50.52 8.0 9.3 11.0 51.75 6.1 7.5 8.8 53.00 5.2 6.4 7.5 54.27 4.6 5.6 6.5 55.57 4.1 4.9 5.7 56.90 3.7 4.3 5.0 58.26 3.3 3.9 4.5 59.64 3.0 3.5 4.0 61.05 2.7 3.2 3.6 62.48 2.5 2.9 3.3 63.95 2.3 2.6 3.0 65.44 2.1 2.4 2.7 66.97 1.9 2.2 2.5 68.52 1.8 2.0 2.3 70.11 1.7 1.9 2.2 71.73 1.5 1.8 2.0 73.38 1.4 1.6 1.9 105.0 118.4 137.1 1.3 1.5 1.7 103.7 116.8 135.4 $/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Pentane Plus 71.43 28.1 29.6 29.6 74.64 37.9 39.9 49.5 78.17 20.8 22.8 27.6 79.89 14.5 16.8 20.0 81.64 11.2 13.6 16.0 83.43 9.6 11.6 13.6 85.25 8.3 10.1 11.8 87.11 7.5 8.9 10.3 89.01 6.7 7.9 9.1 90.94 6.1 7.1 8.2 92.84 5.5 6.3 7.3 94.79 5.0 5.7 6.6 96.76 4.6 5.2 6.0 98.78 4.2 4.8 5.5 100.84 3.9 4.4 5.0 102.94 3.6 4.0 4.6 105.09 3.3 3.7 4.2 107.27 3.0 3.4 3.9 109.50 2.8 3.2 3.6 111.77 2.6 3.0 3.4 191.6 215.0 249.1 2.4 2.8 3.2 189.2 212.2 245.9 Year 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 Total 1 Years Sub Tot $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Heavy Oil - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Bitumen - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -	$/Lt MLt MLt MLt Price Co Net Co Grs Gross Sulphur - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - $/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Butane 44.69 15.5 16.3 16.3 46.85 20.9 22.0 27.3 49.32 11.4 12.6 15.2 50.52 8.0 9.3 11.0 51.75 6.1 7.5 8.8 53.00 5.2 6.4 7.5 54.27 4.6 5.6 6.5 55.57 4.1 4.9 5.7 56.90 3.7 4.3 5.0 58.26 3.3 3.9 4.5 59.64 3.0 3.5 4.0 61.05 2.7 3.2 3.6 62.48 2.5 2.9 3.3 63.95 2.3 2.6 3.0 65.44 2.1 2.4 2.7 66.97 1.9 2.2 2.5 68.52 1.8 2.0 2.3 70.11 1.7 1.9 2.2 71.73 1.5 1.8 2.0 73.38 1.4 1.6 1.9 105.0 118.4 137.1 1.3 1.5 1.7 103.7 116.8 135.4 $/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Pentane Plus 71.43 28.1 29.6 29.6 74.64 37.9 39.9 49.5 78.17 20.8 22.8 27.6 79.89 14.5 16.8 20.0 81.64 11.2 13.6 16.0 83.43 9.6 11.6 13.6 85.25 8.3 10.1 11.8 87.11 7.5 8.9 10.3 89.01 6.7 7.9 9.1 90.94 6.1 7.1 8.2 92.84 5.5 6.3 7.3 94.79 5.0 5.7 6.6 96.76 4.6 5.2 6.0 98.78 4.2 4.8 5.5 100.84 3.9 4.4 5.0 102.94 3.6 4.0 4.6 105.09 3.3 3.7 4.2 107.27 3.0 3.4 3.9 109.50 2.8 3.2 3.6 111.77 2.6 3.0 3.4 191.6 215.0 249.1 2.4 2.8 3.2 189.2 212.2 245.9 Year 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 Total 1 Years Sub Tot $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Heavy Oil - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Bitumen - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
$/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Propane	22.84 25.41 27.85 29.29 30.25 31.23 32.23 33.26 34.30 35.36 36.27 37.20 38.14 39.10 40.09 41.09 42.11 43.15 44.21 45.30		$/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Pentane Plus	71.43 28.1 29.6 29.6 74.64 37.9 39.9 49.5 78.17 20.8 22.8 27.6 79.89 14.5 16.8 20.0 81.64 11.2 13.6 16.0 83.43 9.6 11.6 13.6 85.25 8.3 10.1 11.8 87.11 7.5 8.9 10.3 89.01 6.7 7.9 9.1 90.94 6.1 7.1 8.2 92.84 5.5 6.3 7.3 94.79 5.0 5.7 6.6 96.76 4.6 5.2 6.0 98.78 4.2 4.8 5.5 100.84 3.9 4.4 5.0 102.94 3.6 4.0 4.6 105.09 3.3 3.7 4.2 107.27 3.0 3.4 3.9 109.50 2.8 3.2 3.6 111.77 2.6 3.0 3.4
	10.7 14.4 7.8 5.4 4.1 3.4 2.9 2.6 2.4 2.1 1.9 1.8 1.6 1.5 1.4 1.3 1.2 1.1 1.0 1.0	70.3 0.9 69.4
	11.2 15.1 8.6 6.4 5.2 4.4 3.8 3.4 3.0 2.7 2.4 2.2 2.0 1.8 1.7 1.5 1.4 1.3 1.2 1.1	81.4 1.1 80.4
	11.2 18.8 10.5 7.6 6.1 5.2 4.5 3.9 3.5 3.1 2.8 2.5 2.3 2.1 1.9 1.7 1.6 1.5 1.4 1.3	94.4 1.2 93.2
$/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Ethane	- 0.91 1.33 1.76 2.03 2.31 2.59 2.88 3.17 3.47 3.72 3.98 4.25 4.51 4.79 5.07 5.35 5.65 5.94 6.25		$/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Butane	44.69 15.5 16.3 16.3 46.85 20.9 22.0 27.3 49.32 11.4 12.6 15.2 50.52 8.0 9.3 11.0 51.75 6.1 7.5 8.8 53.00 5.2 6.4 7.5 54.27 4.6 5.6 6.5 55.57 4.1 4.9 5.7 56.90 3.7 4.3 5.0 58.26 3.3 3.9 4.5 59.64 3.0 3.5 4.0 61.05 2.7 3.2 3.6 62.48 2.5 2.9 3.3 63.95 2.3 2.6 3.0 65.44 2.1 2.4 2.7 66.97 1.9 2.2 2.5 68.52 1.8 2.0 2.3 70.11 1.7 1.9 2.2 71.73 1.5 1.8 2.0 73.38 1.4 1.6 1.9
	0.2 2 0.3 3 0.2 2 0.1 1 0.1 1 0.1 1 0.1 1 0.1 1 0.1 1 0.1 1 0.0 0 0.0 0 0.0 0 0.0 0 0.0 0 0.0 0 0.0 0 0.0 0 0.0 0 0.0 0	1.5 6 0.0 0 1.5 6
	0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0.	1. 0. 1.
	0.2 0.4 0.2 0.2 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0	1.9 0.0 1.9
$/Mcf MMcf MMcf MMcf Price Co Net Co Grs Gross Solution Gas	- - - - - - - - - - - - - - - - - - - -		$/Lt MLt MLt MLt Price Co Net Co Grs Gross Sulphur	- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
	- - - - - - - - - - - - - - - - - - - -
	- - - - - - - - - - - - - - - - - - - -
	- - - - - - - - - - - - - - - - - - - -
$/Mcf MMcf MMcf MMcf Mcf/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Gas	3.29 3.90 4.07 4.24 4.36 4.47 4.59 4.71 4.82 4.95 5.05 5.16 5.27 5.38 5.49 5.61 5.72 5.85 5.96 6.08		$/Bbl Price	- - - - - - - - - - - - - - - - - - - -
	1285 1733 979 710 572 491 430 381 339 305 274 248 226 207 189 174 161 149 138 129	9242 120 9122	MBbl Co Net	- - - - - - - - - - - - - - - - - - - -
	1353 1824 1043 769 623 532 462 407 361 324 290 262 239 218 200 184 170 158 146 136	9826 127 9699	MBbl MBbl Bbl/d Count Co Grs Gross Gr. Daily Gr. Well Bitumen	- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
	1353 2264 1262 914 734 622 538 472 418 373 334 302 274 250 228 210 193 179 166 155	11385 144 11241
	4919 6187 3459 2503 2010 1699 1474 1293 1145 1020 915 826 750 683 625 575 530 490 455 423
	5 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7
Year $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Light & Medium Oil	- - - - - - - - - - - - - - - - - - - -		Year $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Heavy Oil	2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
	- - - - - - - - - - - - - - - - - - - -
	- - - - - - - - - - - - - - - - - - - -
	- - - - - - - - - - - - - - - - - - - -
	2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -

– II-94 –

COMPETENT PERSON’S REPORT

APPENDIX II

Consolidated
Canlin Energy Corporation
As Of Date : 2017-12-31
Summary of Reserves and Net Present Values
Appendix C-D
Proved Undeveloped
Production Start : 2019-04-01
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
Income
Other Exp.
Opex
MinTax
Resource
Production
Crown Adj
Crown
Other
Royalty
Sulphur
NGL
Gas
Oil
Year
Operating
Royalties
Revenue
6447.9
0.0
812.1
0.0
0.0
0.0
104.0
395.3
0.0
0.0
0.0
3098.5
4452.8
0.0
2019
9845.3
0.0
1210.9
0.0
0.0
0.0
142.5
599.6
0.0
0.0
0.0
4392.1
7121.3
0.0
2020
5657.7
0.0
814.4
0.0
0.0
0.0
101.8
524.4
0.0
0.0
0.0
2644.6
4250.2
0.0
2021
4125.8
0.0
678.1
0.0
0.0
0.0
95.4
552.7
0.0
0.0
0.0
1998.2
3263.1
0.0
2022
3301.6
0.0
609.1
0.0
0.0
0.0
85.2
548.8
0.0
0.0
0.0
1658.0
2716.2
0.0
2023
2861.7
0.0
568.4
0.0
0.0
0.0
68.3
464.5
0.0
0.0
0.0
1448.1
2378.2
0.0
2024
2525.0
0.0
538.5
0.0
0.0
0.0
55.1
397.8
0.0
0.0
0.0
1287.5
2118.8
0.0
2025
2274.1
0.0
516.0
0.0
0.0
0.0
45.2
331.0
0.0
0.0
0.0
1159.9
1916.0
0.0
2026
2054.2
0.0
498.2
0.0
0.0
0.0
38.8
281.2
0.0
0.0
0.0
1053.3
1741.5
0.0
2027
1871.1
0.0
484.6
0.0
0.0
0.0
34.3
245.4
0.0
0.0
0.0
965.8
1601.1
0.0
2028
1693.7
0.0
473.0
0.0
0.0
0.0
30.4
214.6
0.0
0.0
0.0
885.2
1465.6
0.0
2029
1545.3
0.0
464.4
0.0
0.0
0.0
27.4
191.6
0.0
0.0
0.0
818.4
1355.4
0.0
2030
1411.0
0.0
457.8
0.0
0.0
0.0
24.9
172.9
0.0
0.0
0.0
760.2
1256.5
0.0
2031
1297.4
0.0
453.3
0.0
0.0
0.0
23.0
158.7
0.0
0.0
0.0
711.3
1175.1
0.0
2032
1187.5
0.0
449.4
0.0
0.0
0.0
21.2
145.9
0.0
0.0
0.0
664.5
1097.0
0.0
2033
1092.0
0.0
447.1
0.0
0.0
0.0
19.7
135.9
0.0
0.0
0.0
624.9
1030.5
0.0
2034
1005.6
0.0
445.9
0.0
0.0
0.0
18.5
127.5
0.0
0.0
0.0
589.6
970.8
0.0
2035
931.5
0.0
445.9
0.0
0.0
0.0
17.5
121.0
0.0
0.0
0.0
559.5
921.3
0.0
2036
855.5
0.0
446.2
0.0
0.0
0.0
16.5
114.6
0.0
0.0
0.0
529.6
870.1
0.0
2037
790.2
0.0
447.5
0.0
0.0
0.0
15.8
109.6
0.0
0.0
0.0
504.0
827.5
0.0
2038
53505.2
0.0
11710.2
0.0
0.0
0.0
1000.7
5938.4
0.0
0.0
0.0
26834.0
43319.0
0.0
Total
731.3
0.0
449.4
0.0
0.0
0.0
15.2
105.4
0.0
0.0
0.0
480.9
790.0
0.0
6 Years
52773.9
0.0
11260.8
0.0
0.0
0.0
985.5
5833.0
0.0
0.0
0.0
26353.2
42529.0
0.0
Sub Total
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
Cum.
Tax
Tax
Reclaim.
/Severance
Revenue
Revenue
Capital
COGPE
CDE
CEE
Capital
Year
BTax
Before
Sask.
Aband. &
AdValorem
Cum. Net
Net
Total
Other
-19525.0
-19525.0
0.0
0.0
0.0
-19525.0
-19525.0
25972.9
0.0
25972.9
0.0
0.0
2019
-10567.3
8957.7
0.0
0.0
0.0
-10567.3
8957.7
887.7
0.0
887.7
0.0
0.0
2020
-4909.6
5657.7
0.0
0.0
0.0
-4909.6
5657.7
0.0
0.0
0.0
0.0
0.0
2021
-783.9
4125.8
0.0
0.0
0.0
-783.9
4125.8
0.0
0.0
0.0
0.0
0.0
2022
2517.7
3301.6
0.0
0.0
0.0
2517.7
3301.6
0.0
0.0
0.0
0.0
0.0
2023
5379.4
2861.7
0.0
0.0
0.0
5379.4
2861.7
0.0
0.0
0.0
0.0
0.0
2024
7904.3
2525.0
0.0
0.0
0.0
7904.3
2525.0
0.0
0.0
0.0
0.0
0.0
2025
10178.4
2274.1
0.0
0.0
0.0
10178.4
2274.1
0.0
0.0
0.0
0.0
0.0
2026
12232.6
2054.2
0.0
0.0
0.0
12232.6
2054.2
0.0
0.0
0.0
0.0
0.0
2027
14103.7
1871.1
0.0
0.0
0.0
14103.7
1871.1
0.0
0.0
0.0
0.0
0.0
2028
15797.4
1693.7
0.0
0.0
0.0
15797.4
1693.7
0.0
0.0
0.0
0.0
0.0
2029
17342.7
1545.3
0.0
0.0
0.0
17342.7
1545.3
0.0
0.0
0.0
0.0
0.0
2030
18753.6
1411.0
0.0
0.0
0.0
18753.6
1411.0
0.0
0.0
0.0
0.0
0.0
2031
20051.1
1297.4
0.0
0.0
0.0
20051.1
1297.4
0.0
0.0
0.0
0.0
0.0
2032
21238.6
1187.5
0.0
0.0
0.0
21238.6
1187.5
0.0
0.0
0.0
0.0
0.0
2033
22330.6
1092.0
0.0
0.0
0.0
22330.6
1092.0
0.0
0.0
0.0
0.0
0.0
2034
23336.2
1005.6
0.0
0.0
0.0
23336.2
1005.6
0.0
0.0
0.0
0.0
0.0
2035
24267.6
931.5
0.0
0.0
0.0
24267.6
931.5
0.0
0.0
0.0
0.0
0.0
2036
25123.1
855.5
0.0
0.0
0.0
25123.1
855.5
0.0
0.0
0.0
0.0
0.0
2037
25913.4
790.2
0.0
0.0
0.0
25913.4
790.2
0.0
0.0
0.0
0.0
0.0
2038
25609.7
0.0
1035.0
0.0
26644.6
26860.6
0.0
26860.6
0.0
0.0
Total
-303.7
0.0
1035.0
0.0
731.3
0.0
0.0
0.0
0.0
0.0
6 Years
25913.4
0.0
0.0
0.0
25913.4
26860.6
0.0
26860.6
0.0
0.0
Sub Total

– II-95 –

COMPETENT PERSON’S REPORT

APPENDIX II

Consolidated
Canlin Energy Corporation
As Of Date : 2017-12-31
Summary of Reserves and Net Present Values
Appendix C-E
Total Probable
Production Start : 2018-01-01
3800.2
0.0
693.2
358.0
200.0
132.2
3.0
0
0
17689
345
0.0
0.0
0.0
0.0
101.3
Co. Net
4150.6
0.0
816.9
419.9
234.4
159.4
3.2
0
0
18935
385
0.0
0.0
0.0
0.0
113.7
Co. Gr.
4882.5
0.0
941.1
481.7
272.1
183.7
3.6
0
0
21494
834
0.0
0.0
0.0
0.0
220.1
Gross
MBoe
MLt
MBbl
MBbl
MBbl
MBbl
MBbl
MMcf
MMcf
MMcf
MMcf
MBbl
MBbl
MBbl
MBbl
MBbl
Equiv. Oil
Sulphur
Total NGL
Pentane Plus
Butane
Propane
Ethane
Shale Gas
CBM
Non-Assoc
Assoc Gas
Solution Gas
Tight Oil
Synthetic
Bitumen
Heavy Oil
Lt Med Oil
M$
M$
M$
M$
M$
M$
%
M$
M$
M$
M$
M$
M$
M$
boe/d
Mcf/d
bbl/d
Cash Flow
Reclaim.
Capital
Expenses
Other Exp.
Opex
Royalty
Royalty
Non-Crown
Crown
Revenue
Revenue
Revenue
Revenue
Gross
Gross
Gross
Year
BTax
Aband. &
Total
Total
Total
Total
Total
Other
Gas
Oil
BOE
Comp.
Gas
Comp.
Oil
Comp.
-15388.8
0.0
17054.4
285.8
0.0
285.8
7.7
161.7
10.2
151.6
2113.1
805.1
1224.8
83.2
237.7
1120
3.7
2018
8568.2
0.0
0.0
1187.5
0.0
1187.5
5.0
516.7
17.2
499.4
10272.4
4144.6
5965.0
162.8
1044.1
4966
6.4
2019
-5245.6
0.0
14796.9
1298.5
0.0
1298.5
6.3
726.1
24.0
702.1
11576.0
4325.1
7025.6
225.3
1035.9
4917
8.3
2020
8245.3
0.0
0.0
1292.1
0.0
1292.1
8.1
845.5
26.9
818.5
10382.8
3885.8
6248.8
248.2
887.0
4203
8.7
2021
6064.6
0.0
0.0
1038.8
0.0
1038.8
11.7
941.5
25.9
915.6
8044.9
2951.8
4819.6
273.4
659.7
3112
9.3
2022
5379.2
-154.9
0.0
964.1
0.0
964.1
12.3
865.0
28.7
836.4
7053.5
2553.9
4184.2
315.4
560.5
2632
10.6
2023
4648.7
-32.0
0.0
1002.4
0.0
1002.4
14.5
956.2
32.1
924.1
6575.3
2356.6
3873.0
345.7
506.1
2368
11.3
2024
4710.2
-380.9
0.0
1064.1
0.0
1064.1
13.5
841.9
36.5
805.4
6235.3
2219.3
3655.4
360.5
468.4
2187
11.6
2025
3797.9
275.7
0.0
1081.4
0.0
1081.4
13.0
773.1
40.3
732.8
5928.0
2103.9
3475.3
348.9
433.8
2024
11.0
2026
3937.7
58.8
0.0
1120.7
0.0
1120.7
9.7
551.5
42.0
509.5
5668.7
2000.1
3305.7
362.9
404.0
1880
11.2
2027
3953.1
-149.6
0.0
1124.5
0.0
1124.5
9.1
495.8
41.1
454.8
5423.9
1903.2
3146.3
374.3
374.7
1740
11.3
2028
3855.0
-247.0
0.0
1099.3
0.0
1099.3
8.7
446.9
40.1
406.8
5154.1
1809.1
2965.8
379.2
347.8
1611
11.2
2029
3576.0
-158.4
0.0
1232.9
0.0
1232.9
8.3
419.6
38.9
380.7
5070.1
1769.8
2901.6
398.7
333.6
1542
11.5
2030
3331.6
-108.6
0.0
1409.8
0.0
1409.8
8.1
406.8
42.1
364.6
5039.6
1734.9
2839.6
465.0
322.4
1480
13.2
2031
3073.0
-32.2
0.0
1549.9
0.0
1549.9
8.0
396.5
43.5
353.1
4987.3
1693.8
2771.2
522.3
309.1
1411
14.4
2032
2736.0
93.6
0.0
1681.0
0.0
1681.0
7.9
388.1
46.9
341.2
4898.6
1643.6
2700.7
554.3
297.2
1351
15.0
2033
3113.8
-493.3
0.0
1852.1
0.0
1852.1
7.9
386.0
50.5
335.4
4858.6
1606.9
2652.7
599.0
287.5
1300
15.9
2034
2455.3
117.7
0.0
2460.1
0.0
2460.1
8.3
454.8
86.5
368.3
5487.9
1689.3
2687.6
1110.9
299.2
1294
28.9
2035
4252.6
-908.2
0.0
3504.1
0.0
3504.1
7.6
562.0
89.0
473.0
7410.6
2543.9
3768.7
1098.0
397.3
1768
27.9
2036
3319.0
-335.8
0.0
3088.8
0.0
3088.8
7.7
508.1
76.3
431.8
6580.0
2279.9
3365.4
934.7
347.8
1553
23.3
2037
69508.3
2527.5
31851.3
45490.9
0.0
45490.9
14279.8
987.6
13292.1
163657.8
58944.5
93626.3
11086.9
Total
11125.3
4982.7
0.0
16153.3
0.0
16153.3
2635.9
148.8
2487.1
34897.2
12924.1
20049.2
1923.9
15 Years
58383.0
-2455.2
31851.3
29337.7
0.0
29337.7
11643.8
838.8
10805.0
128760.6
46020.4
73577.1
9163.1
Sub Total
36757.1
-411.5
29636.2
21948.4
0.0
21948.4
8541.2
526.1
8015.1
96471.5
35032.2
55730.8
5708.4
5%
Discount
20080.3
-569.9
27713.7
12477.3
0.0
12477.3
5778.7
314.0
5464.8
65480.1
24013.3
38168.2
3298.7
10%
Discount
15788.6
-505.5
27014.7
10361.3
0.0
10361.3
5068.5
262.8
4805.7
57727.5
21250.7
33747.6
2729.2
12%
Discount
10903.2
-398.3
26032.1
8130.2
0.0
8130.2
4249.9
206.8
4043.2
48917.1
18102.9
28700.5
2113.8
15%
Discount
7321.5
-306.0
25121.6
6619.4
0.0
6619.4
3635.9
167.5
3468.4
42392.3
15762.5
24941.1
1688.7
18%
Discount
5447.2
-256.2
24550.9
5871.1
0.0
5871.1
3306.7
147.6
3159.2
38919.7
14512.3
22931.1
1476.3
20%
Discount
1983.6
-167.2
23237.7
4559.1
0.0
4559.1
2675.7
112.1
2563.6
32288.9
12113.1
19072.3
1103.5
25%
Discount
$/BOE 3.29
3.9 years
318.6
7.3 years
30.0 years
First Year Co Gr. Operating Costs
Before Tax Payout
Reserve Life Index
Reserve Half Life
Reserve Life

– II-96 –

COMPETENT PERSON’S REPORT

APPENDIX II

			$/Lt MLt MLt MLt Price Co Net Co Grs Gross Sulphur - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - $/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Butane 37.90 4.4 4.9 5.3 44.68 20.3 21.8 23.1 46.83 19.7 21.7 24.3 49.29 16.1 18.5 20.4 50.48 10.9 13.7 15.4 51.69 9.1 11.6 13.3 52.93 7.7 10.5 12.1 54.17 7.3 9.7 11.3 55.46 6.8 9.0 10.6 56.78 7.0 8.3 10.0 58.13 6.6 7.7 9.6 59.50 6.1 7.2 9.2 60.91 5.9 6.8 8.7 62.32 5.7 6.6 8.1 63.75 5.5 6.3 7.8 65.22 5.3 6.0 7.3 66.73 5.1 5.8 6.8 68.11 5.1 5.9 6.9 69.83 7.0 7.9 9.7 71.46 6.1 7.0 8.5 200.0 234.4 272.1 32.4 37.3 43.3 167.6 197.0 228.7 $/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Pentane Plus 63.48 7.9 8.9 9.5 71.41 36.6 39.5 41.6 74.62 35.3 39.2 43.7 78.16 28.9 33.4 36.7 79.88 19.5 24.8 27.6 81.63 16.1 20.9 23.7 83.41 13.6 18.8 21.5 85.23 12.7 17.3 19.9 87.10 11.9 16.0 18.6 89.01 12.5 14.9 17.5 90.94 11.8 13.8 16.9 92.84 11.0 12.7 16.1 94.79 10.7 12.2 15.1 96.77 10.3 11.7 14.2 98.81 9.9 11.2 13.6 100.88 9.4 10.7 12.7 103.00 9.1 10.3 11.9 105.23 9.0 10.2 11.8 107.36 12.4 14.0 16.8 109.59 10.8 12.3 14.8 358.0 419.9 481.7 58.8 67.1 77.6 299.3 352.8 404.1 Year 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 Total 10 Years Sub Tot $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Heavy Oil - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Bitumen - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -	$/Lt MLt MLt MLt Price Co Net Co Grs Gross Sulphur - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - $/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Butane 37.90 4.4 4.9 5.3 44.68 20.3 21.8 23.1 46.83 19.7 21.7 24.3 49.29 16.1 18.5 20.4 50.48 10.9 13.7 15.4 51.69 9.1 11.6 13.3 52.93 7.7 10.5 12.1 54.17 7.3 9.7 11.3 55.46 6.8 9.0 10.6 56.78 7.0 8.3 10.0 58.13 6.6 7.7 9.6 59.50 6.1 7.2 9.2 60.91 5.9 6.8 8.7 62.32 5.7 6.6 8.1 63.75 5.5 6.3 7.8 65.22 5.3 6.0 7.3 66.73 5.1 5.8 6.8 68.11 5.1 5.9 6.9 69.83 7.0 7.9 9.7 71.46 6.1 7.0 8.5 200.0 234.4 272.1 32.4 37.3 43.3 167.6 197.0 228.7 $/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Pentane Plus 63.48 7.9 8.9 9.5 71.41 36.6 39.5 41.6 74.62 35.3 39.2 43.7 78.16 28.9 33.4 36.7 79.88 19.5 24.8 27.6 81.63 16.1 20.9 23.7 83.41 13.6 18.8 21.5 85.23 12.7 17.3 19.9 87.10 11.9 16.0 18.6 89.01 12.5 14.9 17.5 90.94 11.8 13.8 16.9 92.84 11.0 12.7 16.1 94.79 10.7 12.2 15.1 96.77 10.3 11.7 14.2 98.81 9.9 11.2 13.6 100.88 9.4 10.7 12.7 103.00 9.1 10.3 11.9 105.23 9.0 10.2 11.8 107.36 12.4 14.0 16.8 109.59 10.8 12.3 14.8 358.0 419.9 481.7 58.8 67.1 77.6 299.3 352.8 404.1 Year 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 Total 10 Years Sub Tot $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Heavy Oil - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Bitumen - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
$/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Propane	16.07 22.85 25.42 27.86 29.31 30.28 31.27 32.28 33.32 34.36 35.43 36.34 37.28 38.22 39.21 40.21 41.22 42.33 43.30 44.35		$/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Pentane Plus	63.48 7.9 8.9 9.5 71.41 36.6 39.5 41.6 74.62 35.3 39.2 43.7 78.16 28.9 33.4 36.7 79.88 19.5 24.8 27.6 81.63 16.1 20.9 23.7 83.41 13.6 18.8 21.5 85.23 12.7 17.3 19.9 87.10 11.9 16.0 18.6 89.01 12.5 14.9 17.5 90.94 11.8 13.8 16.9 92.84 11.0 12.7 16.1 94.79 10.7 12.2 15.1 96.77 10.3 11.7 14.2 98.81 9.9 11.2 13.6 100.88 9.4 10.7 12.7 103.00 9.1 10.3 11.9 105.23 9.0 10.2 11.8 107.36 12.4 14.0 16.8 109.59 10.8 12.3 14.8
	3.1 14.0 13.5 10.9 7.3 6.0 5.0 4.7 4.4 4.4 4.2 3.9 3.8 3.7 3.5 3.3 3.2 3.2 4.5 3.9	132.2 21.7 110.4
	3.4 15.0 14.9 12.7 9.4 7.9 7.2 6.6 6.1 5.7 5.2 4.8 4.6 4.4 4.2 4.0 3.9 3.8 5.3 4.6	159.4 25.4 134.0
	3.7 15.8 16.7 14.0 10.5 9.1 8.2 7.6 7.1 6.7 6.5 6.2 5.8 5.5 5.2 4.9 4.5 4.4 6.4 5.6	183.7 29.4 154.3
$/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Ethane	- - 0.91 1.33 1.76 2.03 2.31 2.59 2.88 3.17 3.47 3.72 3.98 4.25 4.51 4.79 5.07 5.35 5.65 5.94		$/Bbl MBbl MBbl MBbl Price Co Net Co Grs Gross Butane	37.90 4.4 4.9 5.3 44.68 20.3 21.8 23.1 46.83 19.7 21.7 24.3 49.29 16.1 18.5 20.4 50.48 10.9 13.7 15.4 51.69 9.1 11.6 13.3 52.93 7.7 10.5 12.1 54.17 7.3 9.7 11.3 55.46 6.8 9.0 10.6 56.78 7.0 8.3 10.0 58.13 6.6 7.7 9.6 59.50 6.1 7.2 9.2 60.91 5.9 6.8 8.7 62.32 5.7 6.6 8.1 63.75 5.5 6.3 7.8 65.22 5.3 6.0 7.3 66.73 5.1 5.8 6.8 68.11 5.1 5.9 6.9 69.83 7.0 7.9 9.7 71.46 6.1 7.0 8.5
	0.1 1 0.3 3 0.3 3 0.2 3 0.2 2 0.1 2 0.1 1 0.1 1 0.1 1 0.1 1 0.1 1 0.1 1 0.1 1 0.1 1 0.1 1 0.1 1 0.1 1 0.1 1 0.1 1 0.1 1	3.0 2 0.5 5 2.5 7
	0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0. 0.	3. 0. 2.
	0.1 0.3 0.3 0.3 0.2 0.2 0.2 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1	3.6 0.6 3.0
$/Mcf MMcf MMcf MMcf Price Co Net Co Grs Gross Solution Gas	2.96 3.24 3.83 3.94 4.06 4.18 4.30 4.41 4.50 4.60 4.70 4.80 4.89 4.95 5.03 5.11 5.18 5.22 5.34 5.44		$/Lt MLt MLt MLt Price Co Net Co Grs Gross Sulphur	- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
	7 11 16 12 11 13 15 16 15 14 13 14 14 16 17 17 16 24 23 19	345 37 307
	8 13 18 14 13 14 17 18 16 16 15 15 16 17 19 19 18 28 26 22	385 43 342
	16 26 42 32 30 35 39 41 37 36 37 39 40 43 46 44 36 48 47 39	834 80 754
$/Mcf MMcf MMcf MMcf Mcf/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Gas	3.00 3.29 3.90 4.07 4.24 4.36 4.47 4.58 4.71 4.82 4.95 5.05 5.16 5.27 5.38 5.49 5.61 5.72 5.85 5.96		$/Bbl Price	- - - - - - - - - - - - - - - - - - - -
	375 1704 1680 1422 1034 869 772 716 667 618 578 537 514 492 468 445 428 416 583 512	17689 2857 14832	MBbl Co Net	- - - - - - - - - - - - - - - - - - - -
	401 1799 1782 1520 1123 946 850 780 723 670 622 573 547 523 497 474 456 445 621 545	18935 3038 15897	MBbl MBbl Bbl/d Count Co Grs Gross Gr. Daily Gr. Well Bitumen	- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
	426 1888 1972 1657 1245 1063 958 887 831 781 750 715 669 622 591 551 516 503 733 647	21494 3489 18005
	1167 5172 5388 4541 3412 2913 2617 2431 2276 2140 2050 1959 1832 1703 1615 1510 1415 1377 2004 1771
	4 5 12 12 10 10 10 11 14 15 18 19 25 20 24 25 23 26 47 46
Year $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Light & Medium Oil	60.81 70.05 73.94 78.38 80.12 81.77 83.48 85.26 87.16 88.98 90.84 92.74 94.71 96.77 98.85 101.01 103.09 105.36 107.47 109.69		Year $/Bbl MBbl MBbl MBbl Bbl/d Count Price Co Net Co Grs Gross Gr. Daily Gr. Well Heavy Oil	2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
	1.2 2.0 2.7 2.7 3.0 3.4 3.7 3.8 3.6 3.7 3.8 3.7 3.8 4.3 4.8 4.9 5.2 9.4 9.1 7.5	101.3 14.9 86.4
	1.4 2.3 3.0 3.2 3.4 3.9 4.1 4.2 4.0 4.1 4.1 4.1 4.2 4.8 5.3 5.5 5.8 10.5 10.2 8.5	113.7 17.0 96.7
	2.7 4.6 6.3 6.7 7.3 8.3 8.6 8.7 8.1 8.2 8.5 8.4 8.9 10.0 10.9 10.8 10.8 17.8 17.8 14.9	220.1 31.9 188.2
	2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 7 1 13 2 17 2 18 2 20 - 23 1 24 3 24 3 22 2 23 2 23 1 23 3 24 3 27 5 30 8 30 10 30 9 49 21 49 20 41 18

– II-97 –

COMPETENT PERSON’S REPORT

APPENDIX II

Consolidated
Canlin Energy Corporation
As Of Date : 2017-12-31
Summary of Reserves and Net Present Values
Appendix C-E
Total Probable
Production Start : 2018-01-01
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
Income
Other Exp.
Opex
MinTax
Resource
Production
Crown Adj
Crown
Other
Royalty
Sulphur
NGL
Gas
Oil
Year
Operating
Royalties
Revenue
1665.6
0.0
285.8
0.0
10.2
0.0
17.9
169.4
0.0
1.1
0.0
804.0
1224.8
83.2
2018
8568.2
0.0
1187.5
0.0
17.2
0.0
148.7
648.1
0.0
2.5
0.0
4142.1
5965.0
162.8
2019
9551.3
0.0
1298.5
0.0
24.0
0.0
161.6
863.7
0.0
4.0
0.0
4321.1
7025.6
225.3
2020
8245.3
0.0
1292.1
0.0
26.9
0.0
159.7
978.3
0.0
5.0
0.0
3880.8
6248.8
248.2
2021
6064.6
0.0
1038.8
0.0
25.9
0.0
150.4
1066.0
0.0
5.8
0.0
2946.0
4819.6
273.4
2022
5224.3
0.0
964.1
0.0
28.7
0.0
132.7
969.1
0.0
6.4
0.0
2547.5
4184.2
315.4
2023
4616.7
0.0
1002.4
0.0
32.1
0.0
136.8
1060.9
0.0
6.9
0.0
2349.7
3873.0
345.7
2024
4329.3
0.0
1064.1
0.0
36.5
0.0
115.3
920.7
0.0
7.2
0.0
2212.1
3655.4
360.5
2025
4073.6
0.0
1081.4
0.0
40.3
0.0
101.4
834.2
0.0
7.4
0.0
2096.4
3475.3
348.9
2026
3996.5
0.0
1120.7
0.0
42.0
0.0
91.7
601.3
0.0
7.6
0.0
1992.5
3305.7
362.9
2027
3803.5
0.0
1124.5
0.0
41.1
0.0
81.0
535.7
0.0
11.0
0.0
1892.2
3146.3
374.3
2028
3607.9
0.0
1099.3
0.0
40.1
0.0
71.6
478.3
0.0
24.0
0.0
1785.0
2965.8
379.2
2029
3417.6
0.0
1232.9
0.0
38.9
0.0
67.4
448.0
0.0
23.8
0.0
1746.0
2901.6
398.7
2030
3223.1
0.0
1409.8
0.0
42.1
0.0
64.7
429.3
0.0
22.4
0.0
1712.5
2839.6
465.0
2031
3040.8
0.0
1549.9
0.0
43.5
0.0
62.2
415.2
0.0
21.2
0.0
1672.5
2771.2
522.3
2032
2829.6
0.0
1681.0
0.0
46.9
0.0
59.4
400.6
0.0
11.3
0.0
1632.4
2700.7
554.3
2033
2620.5
0.0
1852.1
0.0
50.5
0.0
57.6
393.1
0.0
0.0
0.0
1606.9
2652.7
599.0
2034
2573.0
0.0
2460.1
0.0
86.5
0.0
58.0
426.3
55.4
0.0
0.0
1633.9
2687.6
1110.9
2035
3344.4
0.0
3504.1
0.0
89.0
0.0
79.2
552.2
254.3
0.0
0.0
2289.6
3768.7
1098.0
2036
2983.2
0.0
3088.8
0.0
76.3
0.0
70.8
502.6
230.6
0.0
0.0
2049.3
3365.4
934.7
2037
103887.1
0.0
45490.9
0.0
987.6
0.0
2321.1
15613.2
1233.3
167.6
0.0
57543.6
93626.3
11086.9
Total
16108.1
0.0
16153.3
0.0
148.8
0.0
433.0
2920.0
692.9
0.0
0.0
12231.2
20049.2
1923.9
15 Years
87779.0
0.0
29337.7
0.0
838.8
0.0
1888.2
12693.2
540.4
167.6
0.0
45312.4
73577.1
9163.1
Sub Total
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
M$
Cum.
Tax
Tax
Reclaim.
/Severance
Revenue
Revenue
Capital
COGPE
CDE
CEE
Capital
Year
BTax
Before
Sask.
Aband. &
AdValorem
Cum. Net
Net
Total
Other
-15388.8
-15388.8
0.0
0.0
0.0
-15388.8
-15388.8
17054.4
0.0
17054.4
0.0
0.0
2018
-6820.6
8568.2
0.0
0.0
0.0
-6820.6
8568.2
0.0
0.0
0.0
0.0
0.0
2019
-12066.2
-5245.6
0.0
0.0
0.0
-12066.2
-5245.6
14796.9
0.0
13770.1
0.0
1026.8
2020
-3820.8
8245.3
0.0
0.0
0.0
-3820.8
8245.3
0.0
0.0
0.0
0.0
0.0
2021
2243.7
6064.6
0.0
0.0
0.0
2243.7
6064.6
0.0
0.0
0.0
0.0
0.0
2022
7623.0
5379.2
0.0
-154.9
0.0
7468.0
5224.3
0.0
0.0
0.0
0.0
0.0
2023
12271.7
4648.7
0.0
-32.0
0.0
12084.8
4616.7
0.0
0.0
0.0
0.0
0.0
2024
16981.9
4710.2
0.0
-380.9
0.0
16414.0
4329.3
0.0
0.0
0.0
0.0
0.0
2025
20779.8
3797.9
0.0
275.7
0.0
20487.6
4073.6
0.0
0.0
0.0
0.0
0.0
2026
24717.5
3937.7
0.0
58.8
0.0
24484.1
3996.5
0.0
0.0
0.0
0.0
0.0
2027
28670.6
3953.1
0.0
-149.6
0.0
28287.6
3803.5
0.0
0.0
0.0
0.0
0.0
2028
32525.5
3855.0
0.0
-247.0
0.0
31895.5
3607.9
0.0
0.0
0.0
0.0
0.0
2029
36101.5
3576.0
0.0
-158.4
0.0
35313.1
3417.6
0.0
0.0
0.0
0.0
0.0
2030
39433.2
3331.6
0.0
-108.6
0.0
38536.2
3223.1
0.0
0.0
0.0
0.0
0.0
2031
42506.2
3073.0
0.0
-32.2
0.0
41576.9
3040.8
0.0
0.0
0.0
0.0
0.0
2032
45242.2
2736.0
0.0
93.6
0.0
44406.6
2829.6
0.0
0.0
0.0
0.0
0.0
2033
48356.0
3113.8
0.0
-493.3
0.0
47027.1
2620.5
0.0
0.0
0.0
0.0
0.0
2034
50811.4
2455.3
0.0
117.7
0.0
49600.1
2573.0
0.0
0.0
0.0
0.0
0.0
2035
55064.0
4252.6
0.0
-908.2
0.0
52944.5
3344.4
0.0
0.0
0.0
0.0
0.0
2036
58383.0
3319.0
0.0
-335.8
0.0
55927.7
2983.2
0.0
0.0
0.0
0.0
0.0
2037
69508.3
0.0
2527.5
0.0
72035.8
31851.3
0.0
30824.5
0.0
1026.8
Total
11125.3
0.0
4982.7
0.0
16108.1
0.0
0.0
0.0
0.0
0.0
15 Years
58383.0
0.0
-2455.2
0.0
55927.7
31851.3
0.0
30824.5
0.0
1026.8
Sub Total

– II-98 –

COMPETENT PERSON’S REPORT

APPENDIX II

Appendix D — Page 1

Appendix D – Well List with Interests and Burdens

3390.22221.BRH.nmt

P:\Canlin Energy 22221\Report\Appendix D - Well List with Interests and Burdens.doc

==> picture [78 x 24] intentionally omitted <==

– II-99 –

COMPETENT PERSON’S REPORT

APPENDIX II

Canlin Energy Corporation
As Of Date : 2017-12-31
Interests and Burdens
Appendix D
%
%
%
%
Lessor/Incentive
%
%
%
yyyy mm
(PF/TF)
Value
Type
Formation
Status
Sliding Scale
NPI
NORR
GORR
FHI
Sliding Scale
NPI
NORR
GORR
Start
WI %
Payout
Type
Phase
Entity
Receivable
Payable
Interest
10.00
Current
P&NG
Gas
100/04-18-050-13W5/0
Crown / ARF to Modernized
RCKK
FLOWING GAS
75.00
Current
P&NG
Gas
100/06-35-050-14W5/0
Crown / ARF to Modernized
RCKK
FLOWING GAS
100.00
Current
P&NG
Gas
100/08-03-050-15W5/2
Crown / ARF to Modernized
MNVL
FLOWING GAS
100.00
Current
P&NG
Gas
101/02-04-050-15W5/HZ/NTKN
Crown / Modernized
NTKN
Location
100.00
Current
P&NG
Gas
100/13-22-050-15W5/3
Crown / ARF to Modernized - New Well Royalty Rate & Deep Gas
MNVL
PUMPING GAS
100.00
Current
P&NG
Gas
100/02-23-050-15W5/2
Crown / ARF to Modernized
MNVL
SUSPENDED GAS
100.00
Current
P&NG
Gas
100/05-23-050-15W5/0
Crown / ARF to Modernized - New Well Royalty Rate & Deep Gas
MNVL
FLOWING GAS
100.00
Current
P&NG
Gas
100/15-25-050-15W5/0
Crown / ARF to Modernized
RCKK
PUMPING GAS
100.00
Current
P&NG
Gas
101/05-26-050-15W5/HZ/NTKN
Crown / Modernized
NTKN
Location
1/150(5.0-7.5%)/7.5 %
100.00
Current
P&NG
Gas
100/10-26-050-15W5/0
Crown / ARF to Modernized
VKNS
PUMPING GAS
100.00
Current
P&NG
Gas
100/15-27-050-15W5/0
Crown / ARF to Modernized
RCKK
PUMPING GAS
100.00
Current
P&NG
Gas
100/09-35-050-15W5/0
Crown / ARF to Modernized
MNVL
PUMPING GAS
100.00
Current
P&NG
Gas
100/11-35-050-15W5/0
Crown / ARF to Modernized
GTNG
PUMPING GAS
100.00
Current
P&NG
Gas
100/07-36-050-15W5/0
Crown / ARF to Modernized
RCKK
PUMPING GAS
100.00
Current
P&NG
Gas
100/13-36-050-15W5/0
Crown / ARF to Modernized
RCKK
PUMPING GAS
1/150(3.6-10.8%)/15.0 %
2.00
1.00
69.70
Current
P&NG
Oil
100/04-06-051-11W5/0
Crown / ARF to Modernized - New Well Royalty Rate
CRDM
PUMPING OIL
1/150(3.6-10.8%)/15.0 %
2.00
1.00
69.70
Current
P&NG
Oil
100/05-06-051-11W5/0
Crown / ARF to Modernized - New Well Royalty Rate
CRDM
PUMPING OIL
1/150(3.6-10.8%)/15.0 %
2.00
1.00
69.70
Current
P&NG
Oil
100/12-06-051-11W5/0
Crown / ARF to Modernized - New Well Royalty Rate
CRDM
PUMPING OIL
‡ Uneconomic ** NRA

Version : 16.2.0.45
DB : Canlin22221.vndl
Canlin Energy Corporation
Run Time : 18/04/02 15:12
Run By : carolinh
Price : 2017-12-31 SAL Prices
Scenario : NI51-101
Project : 22221 - Report :
T4
Page : 1 of 9

– II-100 –

COMPETENT PERSON’S REPORT

APPENDIX II

Canlin Energy Corporation
As Of Date : 2017-12-31
Interests and Burdens
Appendix D
%
%
%
%
Lessor/Incentive
%
%
%
yyyy mm
(PF/TF)
Value
Type
Formation
Status
Sliding Scale
NPI
NORR
GORR
FHI
Sliding Scale
NPI
NORR
GORR
Start
WI %
Payout
Type
Phase
Entity
Receivable
Payable
Interest
1/150(3.6-10.8%)/15.0 %
2.00
1.00
69.70
Current
P&NG
Oil
100/13-06-051-11W5/0
Crown / ARF to Modernized - New Well Royalty Rate
CRDM
PUMPING OIL
2.04
34.15
Current
P&NG
Oil
100/01-07-051-11W5/0
Crown / ARF to Modernized - New Well Royalty Rate
CRDM
PUMPING OIL
2.04
34.15
Current
P&NG
Oil
102/01-07-051-11W5/0
Crown / ARF to Modernized - New Well Royalty Rate
CRDM
PUMPING OIL
2.04
34.15
Current
P&NG
Oil
100/02-07-051-11W5/0
Crown / ARF to Modernized - New Well Royalty Rate
CRDM
PUMPING OIL
2.04
34.15
Current
P&NG
Oil
100/03-07-051-11W5/0
Crown / ARF to Modernized - New Well Royalty Rate
CRDM
PUMPING OIL
2.04
34.15
Current
P&NG
Oil
100/04-07-051-11W5/0
Crown / ARF to Modernized - New Well Royalty Rate
CRDM
FLOWING OIL
5.04
68.31
Current
P&NG
Oil
100/13-18-051-11W5/0
Crown / ARF to Modernized - New Well Royalty Rate
CRDM
PUMPING OIL
5.04
68.31
Current
P&NG
Oil
100/14-18-051-11W5/0
Crown / ARF to Modernized - New Well Royalty Rate
CRDM
PUMPING OIL
5.04
68.31
Current
P&NG
Oil
100/15-18-051-11W5/0
Crown / ARF to Modernized
CRDM
PUMPING OIL
5.04
68.31
Current
P&NG
Oil
100/16-18-051-11W5/0
Crown / ARF to Modernized - New Well Royalty Rate
CRDM
PUMPING OIL
5.04
68.31
Current
P&NG
Oil
102/16-18-051-11W5/0
Crown / ARF to Modernized - New Well Royalty Rate
CRDM
PUMPING OIL
5.04
68.31
Current
P&NG
Oil
100/03-13-051-12W5/0
Crown / ARF to Modernized - New Well Royalty Rate
CRDM
PUMPING OIL
5.04
68.31
Current
P&NG
Oil
100/04-13-051-12W5/0
Crown / ARF to Modernized - New Well Royalty Rate
CRDM
PUMPING OIL
5.04
68.31
Current
P&NG
Oil
102/15-13-051-12W5/0
Crown / ARF to Modernized - New Well Royalty Rate
CRDM
FLOWING OIL
5.04
68.31
Current
P&NG
Oil
103/15-13-051-12W5/0
Crown / ARF to Modernized - New Well Royalty Rate
CRDM
FLOWING OIL
5.04
68.31
Current
P&NG
Oil
100/16-13-051-12W5/0
Crown / ARF to Modernized - New Well Royalty Rate
CRDM
PUMPING OIL
9.56
22.50
Current
P&NG
Gas
102/10-22-051-12W5/0
Crown / ARF to Modernized
RCKK
FLOWING GAS
16.50
Current
P&NG
Oil
102/04-02-051-13W5/0
Crown / ARF to Modernized
CRDM
PUMPING OIL
‡ Uneconomic ** NRA

– II-101 –

COMPETENT PERSON’S REPORT

APPENDIX II

Canlin Energy Corporation As Of Date : 2017-12-31 Interests and Burdens Appendix D % % % % Lessor/Incentive % % % yyyy mm (PF/TF) Value Type Formation Status Sliding Scale NPI NORR GORR FHI Sliding Scale NPI NORR GORR Start WI % Payout Type Phase Entity Receivable Payable Interest	% % % % Lessor/Incentive % % % Sliding Scale NPI NORR GORR FHI Sliding Scale NPI NORR GORR	0.00 M$ Current P&NG Oil 100/05-02-051-13W5/0 ‡ Crown / ARF to Modernized 10078.0 Payout CRDM PUMPING OIL 16.50 APO P&NG Oil Crown / ARF to Modernized	0.00 M$ Current P&NG Oil 100/12-02-051-13W5/0 ‡ Crown / ARF to Modernized 11420.0 Payout CRDM PUMPING OIL 16.50 APO P&NG Oil Crown / ARF to Modernized	0.00 M$ Current P&NG Oil 102/12-02-051-13W5/0 ‡ Crown / ARF to Modernized 9157.0 Payout CRDM PUMPING OIL 16.50 APO P&NG Oil Crown / ARF to Modernized	0.00 M$ Current P&NG Gas 100/07-06-051-13W5/2 ‡ Crown / ARF to Modernized 4796.0 Payout RCKK PUMPING GAS 25.00 APO P&NG Gas Crown / ARF to Modernized	20.00 Current P&NG Gas 100/12-28-051-13W5/0 ‡ Crown / ARF to Modernized RCKK FLOWING GAS	30.00 Current P&NG Oil 100/12-33-051-13W5/0 Crown / ARF to Modernized CRDM PUMPING OIL	40.00 Current P&NG Gas 100/08-09-051-14W5/2 Crown / ARF to Modernized GTNG FLOWING GAS	40.00 Current P&NG Gas 100/16-09-051-14W5/0 Crown / ARF to Modernized BLSK FLOWING GAS	40.00 Current P&NG Gas 102/01-16-051-14W5/2 Crown / ARF to Modernized VKNS FLOWING GAS	40.00 Current P&NG Gas 100/08-16-051-14W5/0 Crown / ARF to Modernized RCKK FLOWING GAS	40.00 Current P&NG Gas 100/15-16-051-14W5/2 Crown / ARF to Modernized VKNS FLOWING GAS	100.00 Current P&NG Gas 101/02-18-051-14W5/HZ/NTKN Crown / Modernized NTKN Location	100.00 Current P&NG Gas 100/03-19-051-14W5/0 Crown / ARF to Modernized RCKK FLOWING GAS	100.00 Current P&NG Gas 101/16-19-051-14W5/HZ/RCKK ‡ Crown / Modernized RCKK Location	100.00 Current P&NG Gas 102/03-20-051-14W5/0 Crown / ARF to Modernized RCKK PUMPING GAS	‡ Uneconomic NRA**
																		Version : 16.2.0.45 DB : Canlin22221.vndl Canlin Energy Corporation Run Time : 18/04/02 15:12 Run By : carolinh Price : 2017-12-31 SAL Prices Scenario : NI51-101 Project : 22221 - Report : T4 Page : 3 of 9

– II-102 –

COMPETENT PERSON’S REPORT

APPENDIX II

Canlin Energy Corporation
As Of Date : 2017-12-31
Interests and Burdens
Appendix D
%
%
%
%
Lessor/Incentive
%
%
%
yyyy mm
(PF/TF)
Value
Type
Formation
Status
Sliding Scale
NPI
NORR
GORR
FHI
Sliding Scale
NPI
NORR
GORR
Start
WI %
Payout
Type
Phase
Entity
Receivable
Payable
Interest
100.00
Current
P&NG
Gas
100/13-20-051-14W5/0
Crown / ARF to Modernized
VKNS
PUMPING GAS
100.00
Current
P&NG
Gas
101/15-20-051-14W5/HZ/RCKK ‡
Crown / Modernized
RCKK
Location
15.00
0.00
Current
P&NG
Gas
102/03-21-051-14W5/2
Crown / ARF to Modernized
VKNS
FLOWING GAS
15.00
0.00
Current
P&NG
Gas
100/12-21-051-14W5/2
Crown / ARF to Modernized
ELRL
FLOWING GAS
100.00
Current
P&NG
Gas
100/16-21-051-14W5/2
Crown / ARF to Modernized
VKNS
PUMPING GAS
40.00
Current
P&NG
Gas
100/10-25-051-14W5/2 ‡
Crown / ARF to Modernized
MNVL
FLOWING GAS
40.00
Current
P&NG
Gas
100/04-35-051-14W5/0 ‡
Crown / ARF to Modernized
ELRL
FLOWING GAS
100.00
Current
P&NG
Gas
100/01-14-051-15W5/0
Crown / ARF to Modernized - New Well Royalty Rate & Deep Gas
MNVL
FLOWING GAS
100.00
Current
P&NG
Gas
100/04-24-051-15W5/0
Crown / ARF to Modernized - New Well Royalty Rate & Deep Gas
MNVL
FLOWING GAS
100.00
Current
P&NG
Gas
100/06-24-051-15W5/2
Crown / ARF to Modernized
MNVL
FLOWING GAS
100.00
Current
P&NG
Gas
100/08-24-051-15W5/0
Crown / ARF to Modernized - New Well Royalty Rate & Deep Gas
RCKK
FLOWING GAS
100.00
Current
P&NG
Gas
100/13-24-051-15W5/2
Crown / ARF to Modernized
MNVL
FLOWING GAS
100.00
Current
P&NG
Gas
100/14-24-051-15W5/0
Crown / ARF to Modernized - New Well Royalty Rate & Deep Gas
NTKN
FLOWING GAS
100.00
Current
P&NG
Gas
100/01-13-051-16W5/0
Crown / ARF to Modernized
RCKK
FLOWING GAS
0.50
6.25
100.00
Current
P&NG
Gas
100/07-34-051-16W5/3
Crown / ARF to Modernized
RCKK
PUMPING GAS
25.00
Current
P&NG
Gas
100/12-04-052-13W5/0
Crown / ARF to Modernized
RCKK
FLOWING GAS
30.00
Current
P&NG
Gas
100/04-05-052-13W5/0
Crown / ARF to Modernized
GTNG
FLOWING GAS
30.00
Current
P&NG
Oil
100/16-05-052-13W5/0
Crown / ARF to Modernized
GTNG
FLOWING OIL
‡ Uneconomic ** NRA

– II-103 –

COMPETENT PERSON’S REPORT

APPENDIX II

Canlin Energy Corporation
As Of Date : 2017-12-31
Interests and Burdens
Appendix D
%
%
%
%
Lessor/Incentive
%
%
%
yyyy mm
(PF/TF)
Value
Type
Formation
Status
Sliding Scale
NPI
NORR
GORR
FHI
Sliding Scale
NPI
NORR
GORR
Start
WI %
Payout
Type
Phase
Entity
Receivable
Payable
Interest
25.00
Current
P&NG
Oil
100/10-09-052-13W5/0
Crown / ARF to Modernized
GTNG
FLOWING OIL
80.00
Current
P&NG
Gas
100/15-28-052-13W5/0
Crown / ARF to Modernized
RCKK
PUMPING GAS
50.00
Current
P&NG
Oil
100/11-30-052-13W5/3
Crown / ARF to Modernized
SSPK
PUMPING OIL
50.00
Current
P&NG
Oil
100/16-30-052-13W5/0
Crown / ARF to Modernized
CRDM
SUSPENDED OIL
22.50
Current
P&NG
Gas
100/13-32-052-13W5/3
Crown / ARF to Modernized
BLSK
FLOWING GAS
30.00
Current
P&NG
Gas
100/07-12-052-14W5/0 ‡
Crown / ARF to Modernized
RCKK
FLOWING GAS
24.00
Current
P&NG
Gas
100/09-14-052-14W5/0
Crown / ARF to Modernized
BLSK
FLOWING GAS
1/150(3.0-9.0%)/9.0 %
0.00
Current
P&NG
Gas
100/15-16-052-14W5/0
Crown / ARF to Modernized
RCKK
PUMPING GAS
1/375(2.0-6.0%)/6.0 %
100.00
Current
P&NG
Gas
100/08-26-052-14W5/0
Crown / ARF to Modernized - New Well Royalty Rate & Deep Gas
GTNG
FLOWING GAS
60.00
Current
P&NG
Gas
100/14-26-052-14W5/2
Crown / ARF to Modernized
MNVL
PUMPING GAS
100.00
Current
P&NG
Gas
100/08-33-052-14W5/0 ‡
Crown / ARF to Modernized
GTNG
PUMPING GAS
1/375(2.0-6.0%)/6.0 %
100.00
Current
P&NG
Gas
100/13-33-052-14W5/0
Crown / ARF to Modernized - New Well Royalty Rate & Deep Gas
GTNG
FLOWING GAS
6.00
100.00
Current
P&NG
Gas
100/15-33-052-14W5/0
Crown / ARF to Modernized - New Well Royalty Rate & Deep Gas
GTNG
FLOWING GAS
100.00
Current
P&NG
Gas
101/16-33-052-14W5/HZ/GTNG
Crown / Modernized
GTNG
Location
50.00
Current
P&NG
Gas
101/05-34-052-14W5/HZ/GTNG
Crown / Modernized
GTNG
Location
50.00
Current
P&NG
Gas
100/10-34-052-14W5/0
Crown / ARF to Modernized
GTNG
FLOWING GAS
100.00
M$ Current
P&NG
Gas
100/13-34-052-14W5/2
Crown / ARF to Modernized - New Well Royalty Rate
1335.0
Payout
MNVL
FLOWING GAS
50.00
APO
P&NG
Gas
Crown / ARF to Modernized - New Well Royalty Rate
‡ Uneconomic ** NRA

– II-104 –

COMPETENT PERSON’S REPORT

APPENDIX II

Canlin Energy Corporation
As Of Date : 2017-12-31
Interests and Burdens
Appendix D
%
%
%
%
Lessor/Incentive
%
%
%
yyyy mm
(PF/TF)
Value
Type
Formation
Status
Sliding Scale
NPI
NORR
GORR
FHI
Sliding Scale
NPI
NORR
GORR
Start
WI %
Payout
Type
Phase
Entity
Receivable
Payable
Interest
100.00
Current
P&NG
Gas
101/04-35-052-14W5/HZ/GTNG ‡
Crown / Modernized
GTNG
Location
50.00
Current
P&NG
Gas
100/08-35-052-14W5/0 ‡
Crown / ARF to Modernized
VKNS
PUMPING GAS
100.00
Current
P&NG
Gas
100/16-35-052-14W5/0
Crown / ARF to Modernized - New Well Royalty Rate & Deep Gas
GTNG
FLOWING GAS
60.00
Current
P&NG
Oil
100/01-36-052-14W5/0
Crown / ARF to Modernized
CRDM
FLOWING OIL
6.00
100.00
Current
P&NG
Gas
100/05-36-052-14W5/0 ‡
Crown / ARF to Modernized - New Well Royalty Rate & Deep Gas
MNVL
PUMPING GAS
60.00
Current
P&NG
Gas
102/10-36-052-14W5/2
Crown / ARF to Modernized
MNVL
PUMPING GAS
18.15
Current
P&NG
Gas
100/05-28-052-15W5/0
Crown / ARF to Modernized
BLRG
SUSPENDED GAS
62.50
Current
P&NG
Gas
100/02-08-053-13W5/0
Crown / ARF to Modernized
GTNG
PUMPING GAS
2.50
100.00
Current
P&NG
Gas
100/10-09-053-13W5/0
Crown / ARF to Modernized
GTNG
PUMPING GAS
2.50
100.00
Current
P&NG
Gas
100/06-10-053-13W5/0
Crown / ARF to Modernized
CRDM
PUMPING OIL
7.50
100.00
Current
P&NG
Gas
100/16-13-053-13W5/3
Crown / ARF to Modernized
MNVL
PUMPING GAS
2.50
100.00
Current
P&NG
Gas
100/10-16-053-13W5/2
Crown / ARF to Modernized
GTNG
FLOWING GAS
50.00
Current
P&NG
Gas
100/10-19-053-13W5/2
Crown / ARF to Modernized
RCKK
PUMPING GAS
100.00
Current
P&NG
Gas
101/04-20-053-13W5/HZ/GTNG
Crown / Modernized
GTNG
Location
2.50
100.00
Current
P&NG
Gas
100/10-20-053-13W5/0
Crown / ARF to Modernized
GTNG
FLOWING GAS
9.25
80.00
Current
P&NG
Gas
100/12-20-053-13W5/0 ‡
Crown / ARF to Modernized
CRDM
SUSPENDED OIL
2.50
87.50
Current
P&NG
Gas
100/06-21-053-13W5/0
Crown / ARF to Modernized
ELRL
PUMPING GAS
5.84
47.98
Current
P&NG
Gas
100/14-22-053-13W5/0
Crown / ARF to Modernized
GTNG
PUMPING GAS
‡ Uneconomic ** NRA

– II-105 –

COMPETENT PERSON’S REPORT

APPENDIX II

Canlin Energy Corporation
As Of Date : 2017-12-31
Interests and Burdens
Appendix D
%
%
%
%
Lessor/Incentive
%
%
%
yyyy mm
(PF/TF)
Value
Type
Formation
Status
Sliding Scale
NPI
NORR
GORR
FHI
Sliding Scale
NPI
NORR
GORR
Start
WI %
Payout
Type
Phase
Entity
Receivable
Payable
Interest
87.50
Current
P&NG
Gas
100/08-29-053-13W5/0
Crown / ARF to Modernized
GTNG
FLOWING GAS
87.50
Current
P&NG
Gas
100/13-29-053-13W5/0
Crown / ARF to Modernized
GTNG
PUMPING GAS
87.50
Current
P&NG
Gas
100/06-31-053-13W5/0
Crown / ARF to Modernized
GTNG
PUMPING GAS
87.50
Current
P&NG
Gas
100/14-31-053-13w5/0
Crown / ARF to Modernized
MNVL
PUMPING GAS
87.50
Current
P&NG
Gas
100/15-31-053-13W5/0
Crown / ARF to Modernized
BLSK
PUMPING GAS
87.50
Current
P&NG
Gas
100/16-31-053-13W5/0
Crown / ARF to Modernized - New Well Royalty Rate & Deep Gas
GTNG
FLOWING GAS
1.50
100.00
Current
P&NG
Gas
100/15-32-053-13W5/3
Crown / ARF to Modernized
VKNS
PUMPING GAS
100.00
Current
P&NG
Gas
100/11-34-053-13W5/3 ‡
Crown / ARF to Modernized
MNVL
PUMPING GAS
50.00
Current
P&NG
Gas
100/04-02-053-14W5/0
Crown / ARF to Modernized
MNVL
PUMPING GAS
60.00
Current
P&NG
Gas
100/02-03-053-14W5/2
Crown / ARF to Modernized
BLSK
PUMPING GAS
60.00
Current
P&NG
Gas
100/08-03-053-14W5/0
Crown / ARF to Modernized - New Well Royalty Rate & Deep Gas
MNVL
FLOWING GAS
60.00
Current
P&NG
Gas
100/15-03-053-14W5/0
Crown / ARF to Modernized
VKNS
PUMPING GAS
60.00
Current
P&NG
Gas
100/16-04-053-14W5/0
Crown / ARF to Modernized
VKNS
PUMPING GAS
15.00
16.67
Current
P&NG
Gas
100/12-07-053-14W5/0
Crown / ARF to Modernized
RCKK
PUMPING GAS
1/150(5.0-15.0%)/15.0 %
16.67
Current
P&NG
Gas
100/04-10-053-14W5/0
Crown / ARF to Modernized
MNVL
FLOWING GAS
1/150(5.0-15.0%)/15.0 %
16.67
Current
P&NG
Gas
100/14-10-053-14W5/0
Crown / ARF to Modernized
VKNS
FLOWING GAS
31.20
Current
P&NG
Oil
100/03-12-053-14W5/0
Crown / ARF to Modernized
CRDM
SUSPENDED OIL
15.00
45.00
Current
P&NG
Gas
100/06-13-053-14W5/2
Crown / ARF to Modernized
VKNS
PUMPING GAS
‡ Uneconomic ** NRA

– II-106 –

COMPETENT PERSON’S REPORT

APPENDIX II

Canlin Energy Corporation As Of Date : 2017-12-31 Interests and Burdens Appendix D % % % % Lessor/Incentive % % % yyyy mm (PF/TF) Value Type Formation Status Sliding Scale NPI NORR GORR FHI Sliding Scale NPI NORR GORR Start WI % Payout Type Phase Entity Receivable Payable Interest	% % % % Lessor/Incentive % % % Sliding Scale NPI NORR GORR FHI Sliding Scale NPI NORR GORR	12.00 Current P&NG Gas 100/04-16-053-14W5/0 Crown / ARF to Modernized RCKK PUMPING GAS	1/195(3.8-11.5%)/11.5 % 52.00 Current P&NG Gas 100/07-16-053-14W5/0 Crown / ARF to Modernized VKNS FLOWING GAS	0.00 100.00 M$ Current P&NG Gas 102/10-17-053-14W5/0 Crown / ARF to Modernized 1540.0 Payout PKCP PUMPING GAS 0.00 12.00 APO P&NG Gas Crown / ARF to Modernized	12.00 Current P&NG Gas 100/13-17-053-14W5/0 Crown / ARF to Modernized RCKK PUMPING GAS	78.11 Current P&NG Gas 100/04-22-053-14W5/0 Crown / ARF to Modernized VKNS PUMPING GAS	60.00 Current P&NG Gas 100/10-23-053-14W5/0 Crown / ARF to Modernized VKNS PUMPING GAS	40.00 Current P&NG Gas 101/15-24-053-14W5/HZ/GTNG Crown / Modernized GTNG Location	93.80 Current P&NG Gas 101/03-26-053-14W5/HZ/GTNG Crown / Modernized GTNG Location	93.80 Current P&NG Gas 101/04-26-053-14W5/HZ/GTNG Crown / Modernized GTNG Location	0.00 93.75 Current P&NG Gas 100/08-26-053-14W5/0 Crown / ARF to Modernized GTNG PUMPING GAS	15.00 100.00 Current P&NG Gas 100/04-32-053-14W5/0 Crown / ARF to Modernized VKNS PUMPING GAS	100.00 Current P&NG Gas 101/13-36-053-14W5/HZ/GTNG ‡ Crown / Modernized GTNG Location	100.00 Current P&NG Gas 101/14-36-053-14W5/HZ/GTNG ‡ Crown / Modernized GTNG Location	1/150(5.0-12.5%)/12.5 % 100.00 M$ Current P&NG Oil 100/16-36-053-14W5/0 Crown / ARF to Modernized 1775.0 Payout GTNG FLOWING GAS 60.00 APO P&NG Oil Crown / ARF to Modernized	15.00 100.00 Current P&NG Gas 100/15-10-054-14W5/0 ‡ Crown / ARF to Modernized MNVL FLOWING GAS	40.00 Current P&NG Oil 100/04-26-054-16W5/0 Crown / ARF to Modernized CRDM PUMPING OIL	40.00 Current P&NG Oil 100/05-26-054-16W5/0 Crown / ARF to Modernized CRDM PUMPING OIL	‡ Uneconomic NRA**
																				Version : 16.2.0.45 DB : Canlin22221.vndl Canlin Energy Corporation Run Time : 18/04/02 15:12 Run By : carolinh Price : 2017-12-31 SAL Prices Scenario : NI51-101 Project : 22221 - Report : T4 Page : 8 of 9

– II-107 –

COMPETENT PERSON’S REPORT

APPENDIX II

Canlin Energy Corporation As Of Date : 2017-12-31 Interests and Burdens Appendix D % % % % Lessor/Incentive % % % yyyy mm (PF/TF) Value Type Formation Status Sliding Scale NPI NORR GORR FHI Sliding Scale NPI NORR GORR Start WI % Payout Type Phase Entity Receivable Payable Interest	% % % % Lessor/Incentive % % % Sliding Scale NPI NORR GORR FHI Sliding Scale NPI NORR GORR	40.00 Current P&NG Oil 100/09-26-054-16W5/0 Crown / ARF to Modernized - New Well Royalty Rate CRDM PUMPING OIL	40.00 Current P&NG Oil 100/16-26-054-16W5/0 Crown / ARF to Modernized CRDM PUMPING OIL	12.00 Current P&NG Oil 100/04-35-054-16W5/0 Crown / ARF to Modernized CRDM PUMPING OIL	0.00 Current Facility Car.CK Field Costs ‡ Crown	0.00 Current Facility Car.CK Proc.Income Crown	0.00 Current Facility CP Field Costs ‡ Crown	0.00 Current Facility CP Proc. Income Crown

==> picture [14 x 47] intentionally omitted <==

– II-108 –

COMPETENT PERSON’S REPORT

APPENDIX II

Appendix E — Page 1

Appendix E – Representation Letter

The Representation Letter has been included as Appendix E; it was prepared by Officers of the Company and confirms the accuracy, completeness and availability of all data requested by Sproule and or otherwise furnished to Sproule during the course of our evaluation of the Company’s assets, herein reported on.

3390.22221.BRH.nmt

P:\Canlin Energy 22221\Report\Appendix E - Representation Letter.doc

==> picture [78 x 24] intentionally omitted <==

– II-109 –

COMPETENT PERSON’S REPORT

APPENDIX II

==> picture [490 x 634] intentionally omitted <==

– II-110 –

COMPETENT PERSON’S REPORT

APPENDIX II

==> picture [490 x 635] intentionally omitted <==

– II-111 –

COMPETENT PERSON’S REPORT

APPENDIX II

==> picture [490 x 633] intentionally omitted <==

– II-112 –

GENERAL INFORMATION

APPENDIX III

1. RESPONSIBILITY STATEMENT

This circular, for which the Directors collectively and individually accept full responsibility, includes particulars given in compliance with the Listing Rules for the purpose of giving information with regard to the Company. The Directors, having made all reasonable enquiries, confirm that, to the best of their knowledge and belie the information contained in this circular is accurate and complete in all material respects and not misleading or deceptive, and there are no other matters the mission of which would make any statement herein or this circular misleading.

2. DISCLOSURE OF INTERESTS

(a) Directors’ and Chief Executive’s Interests in Shares and Underlying Shares

As at the Latest Practicable Date, the interests or short positions of the Directors and chief executive of the Company in the Shares, underlying shares and debentures (if any) of the Company or any its associated corporations (within the meaning of Part XV of the SFO) as required to be notified to the Company and the Stock Exchange pursuant to Division 7 and 8 of Part XV of the SFO (including interests and short positions which they were taken or deemed to have under such provisions of the SFO), as recorded in the register maintained by the Company pursuant to section 352 of the SFO or otherwise notified to the Company and the Stock Exchange pursuant to the Model Code for Securities Transactions by Directors of Listed Issuers (the ‘‘Model Code’’) were as follows:

Interests and short positions in the shares, underlying shares and debentures of the Company or its associated corporations

			Number of
			shares (including
			options to be	Approximate
			exercised)/	percentage of
Name of	Name of	Capacity/nature	underlying	interest in the
Director	corporation	of interest	shares interested	corporation
Mr. Zhang Ruilin	the Company	Interest of controlled	1,522,095,234 (L)	51.80%
		corporation (Note 2)
		Interest of controlled	88,521,234 (S)	3.01%
		corporation (Note 3)
		Beneficial owner (Note 4)	7,987,000 (L)	0.27%

– III-1 –

GENERAL INFORMATION

APPENDIX III

			Number of
			shares (including
			options to be	Approximate
			exercised)/	percentage of
Name of	Name of	Capacity/nature	underlying	interest in the
Director	corporation	of interest	shares interested	corporation
Mr. Zhao Jiangwei	the Company	Interest of controlled	1,522,095,234 (L)	3.01%
		corporation (Note 2)
		Interest of controlled	88,521,234 (S)	51.80%
		corporation (Note 3)
		Beneficial owner (Note 4)	10,987,000 (L)	0.37%
Mr. Zhang Ruilin	Far East Energy	Interest of controlled	8,999	9.99%
	Limited	corporation (Note 2)
	(‘‘FEEL’’)
Mr. Zhao Jiangwei	FEEL	Interest of controlled	9,000	10%
		corporation (Note 2)
Mr. Jeffrey Willard	the Company	Beneficial owner	2,611,333 (L)	0.09%
Miller
Mr. Mei Jianping	the Company	Beneficial owner	2,067,933 (L)	0.07%
Mr. Guo Yanjun	the Company	Beneficial owner	800,000 (L)	0.03%
Ms. Xie Na	the Company	Beneficial owner	800,000 (L)	0.03%

Notes:

The letter ‘‘L’’ denotes long position in the Shares; and ‘‘S’’ denotes short position in the Shares.
FEEL is held by Ms. Zhao Jiangbo (‘‘Mrs. Zhang’’), Mr. Zhang Ruilin (‘‘Mr. Zhang’’) and Mr. Zhao Jiangwei (‘‘Mr. Zhao’’) as to 80%, 9.99% and 10%, respectively. On May 24, 2013, 72,000 shares in FEEL were issued to Mrs. Zhang, 399,070,000 shares in the Company were transferred from FEEL to Champion International Energy Limited (‘‘Champion’’), 399,070,000 shares in the Company were transferred from FEEL to Orient International Energy Limited (‘‘Orient’’), 475,000,000 shares in the Company were transferred from FEEL to New Sun International Energy Limited (‘‘New Sun’’) and 141,460,000 shares in the Company were transferred from FEEL to Power International Energy Limited (‘‘Power’’). Each of Champion, Orient, New Sun and Power is a wholly-owned subsidiary of Sunrise Glory Holdings Limited, which is itself a wholly-owned subsidiary of FEEL. Mrs. Zhang, Mr. Zhang and Mr. Zhao have entered into an Acting-in-Concert Agreement under which they agreed to act in concert in relation to all matters that require the decisions of the shareholders of FEEL. Pursuant to the Acting-in-Concert Agreement, if a unanimous opinion in relation to the matters that require action in concert is unable to be reached, Mr. Zhang shall be allowed to vote on his, Mrs. Zhang’s and Mr. Zhao’s shares. The long interests which FEEL, Mr. Zhang and Mr. Zhao have in the 1,522,095,234 shares in the Company

– III-2 –

GENERAL INFORMATION

APPENDIX III

include (i) the beneficial interests which FEEL has (and in the case of Mr. Zhang and Mr. Zhao, the indirect beneficial interests which they have (through their shareholdings in FEEL)) in the 1,414,600,000 shares in the Company held by FEEL through its subsidiaries, (ii) the 7,887,000 share options granted to Mr. Zhang, (iii) the 7,887,000 share options granted to Mr. Zhao, (iv) the call option which FEEL, Mr. Zhang and Mr. Zhao have been granted, pursuant to a put and call option agreement, over the 88,521,234 shares in the Company held by Mr. Ho Chi Sing through Celestial, as further described in note (3) below, (v) the 100,000 shares owned by Mr. Zhang himself and (vi) 3,100,000 shares owned by Mr. Zhao himself.

The Company was informed on November 8, 2014 that TPG Star Energy Ltd. and Celestial had entered into a sale and purchase agreement pursuant to which Celestial had acquired and TPG Star Energy Ltd. has sold 211,855,234 ordinary shares in the Company.

On November 8, 2014, FEEL, Mr. Zhang, Mr. Zhao, Mrs. Zhang and Celestial entered into a put and call option agreement in relation to certain of the shares, pursuant to which the parties to the put and call option agreement have agreed to grant each other certain rights in relation to their Shares, and section 317(1)(a) of the SFO applies. Mr. Ho Chi Sing is the sole shareholder of the Celestial.

In particular, Mr. Ho Chi Sing, through his holdings in Celestial, is beneficially interested in 211,855,234 shares in the Company. Pursuant to the abovementioned put and call option agreement, Mr. Ho Chi Sing and Celestial have been granted a put option to resell/put 211,855,234 shares to FEEL, Mr. Zhang and Mr. Zhao.

On January 6, 2017, FEEL, Mr. Zhang, Mr. Zhao, Mrs. Zhang and Celestial entered into the letter agreement in relation to the put and call option. The Board was also informed that Great Harmony International Ltd (‘‘Great Harmony’’) and Celestial have entered into a sale and purchase agreement pursuant to which Great Harmony has agreed to acquire (or procure its affiliate or other person or company designated by it to acquire) and Celestial has agreed to sell 211,855,234 ordinary shares in the Company.

On January 18, 2017, February 23, 2017 and March 7, 2017, Celestial had ceased to have 53,334,000 shares, 40,000,000 shares and 30,000,000 shares in long and short positions, respectively.

On May 17, 2017, FEEL, Mr. Zhang, Mr. Zhao, Mrs. Zhang and Celestial entered into the second letter agreement in relation to the put and call option agreement. For further details, please refer to the Company’s announcement dated May 17, 2017.

On November 30, 2017, FEEL, Mr. Zhang, Mr. Zhao, Mrs. Zhang and Celestial entered into the supplemental agreement to the second letter agreement in relation to the put and call option agreement. For further details, please refer to the Company’s announcement dated November 30, 2017.

These interests represent interests in outstanding stock options under the share option scheme and stock incentive compensation plan. Mr. Zhang’s interests includes the 100,000 shares held by himself and Mr. Zhao’s interests includes the 3,100,000 shares held by himself.

– III-3 –

GENERAL INFORMATION

APPENDIX III

(b) Persons who have interests or short positions which are discloseable under Divisions 2 and 3 of Part XV of the SFO

As at the Latest Practicable Date, the following persons, not being a Director or chief executive of the Company, had an interest in the shares and underlying shares of the Company as recorded in the register required to be kept under section 336 of the SFO or as required to be disclosed to the Company and the Stock Exchange under Divisions 2 and 3 of Part XV of the SFO, the details of which are set out below:

Interests and short positions in the shares and underlying shares of the Company

			Approximate
			percentage of
Name of		Number of	interest in the
shareholder	Nature of interest	Shares held	Company
Ms. Zhao Jiangbo	Interest of controlled	1,522,095,234 (L)	51.80%
	corporation (Note 2)	88,521,234 (S)	3.01%
FEEL	Interest of controlled	1,522,095,234 (L)	51.80%
	corporation (Note 2)	88,521,234 (S)	3.01%
Mr. Ho Chi Sing	Interest of controlled	1,522,095,234 (L)	51.80%
	corporation (Note 3)	88,521,234 (S)	3.01%
Celestial Energy	Interest of controlled	1,522,095,234 (L)	51.80%
Limited	corporation (Note 3)	88,521,234 (S)	3.01%
(‘‘Celestial’’)

Notes:

(1) The letter ‘‘L’’ denotes long position in the Shares; ‘‘S’’ denotes short position in the Shares.
(2) FEEL is held by Ms. Zhao Jiangbo (‘‘Mrs. Zhang’’), Mr. Zhang Ruilin (‘‘Mr. Zhang’’) and Mr. Zhao Jiangwei (‘‘Mr. Zhao’’) as to 80%, 9.99% and 10%, respectively. On May 24, 2013, 72,000 shares in FEEL were issued to Mrs. Zhang, 399,070,000 shares in the Company were transferred from FEEL to Champion International Energy Limited (‘‘Champion’’), 399,070,000 shares in the Company were transferred from FEEL to Orient International Energy Limited (‘‘Orient’’), 475,000,000 shares in the Company were transferred from FEEL to New Sun International Energy Limited (‘‘New Sun’’) and 141,460,000 shares in the Company were transferred from FEEL to Power International Energy Limited (‘‘Power’’). Each of Champion, Orient, New Sun and Power is a wholly-owned subsidiary of Sunrise Glory Holdings Limited, which is itself a wholly-owned subsidiary of FEEL. Mrs. Zhang, Mr. Zhang and Mr. Zhao have entered into an Acting-in-Concert Agreement under which they agreed to act in concert in relation to all matters that require the decisions of the shareholders of FEEL. Pursuant to the Acting-in-Concert Agreement, if a unanimous opinion in relation to the matters that require action in concert is unable to be reached, Mr. Zhang shall be allowed to vote on his, Mrs. Zhang’s and Mr. Zhao’s shares. The long interests which FEEL, Mr. Zhang and Mr. Zhao have in the 1,522,095,234 shares in the Company include (i) the beneficial interests which FEEL has (and in the case of Mr. Zhang and Mr. Zhao, the indirect beneficial interests which they have (through their shareholdings in FEEL)) in the 1,414,600,000 shares in the Company held by FEEL through its subsidiaries, (ii) the 7,887,000 share options granted to Mr. Zhang, (iii) the 7,887,000 share options granted to Mr. Zhao, (iv) the

– III-4 –

GENERAL INFORMATION

APPENDIX III

call option which FEEL, Mr. Zhang and Mr. Zhao have been granted, pursuant to a put and call option agreement, over the 88,521,234 shares in the Company held by Mr. Ho Chi Sing through Celestial, as further described in note (3) below, (v) the 100,000 shares owned by Mr. Zhang himself and (vi) 3,100,000 shares owned by Mr. Zhao himself.

(3) The Company was informed on November 8, 2014 that TPG Star Energy Ltd. and Celestial had entered into a sale and purchase agreement pursuant to which Celestial had acquired and TPG Star Energy Ltd. has sold 211,855,234 ordinary shares in the Company.

On January 18, 2017, February 23, 2017 and March 7, 2017, Celestial had ceased to have 53,334,000 shares, 40,000,000 shares and 30,000,000 shares in long and short positions, respectively.

On November 30, 2017, FEEL, Mr. Zhang, Mr. Zhao, Mrs. Zhang and Celestial entered into entered into the supplemental agreement to the second letter agreement in relation to the put and call option agreement. For further details, please refer to the Company’s announcement dated November 30, 2017.

Saved as disclosed above in this section, as at the Latest Practicable Date, the Company had not been notified of any other persons (other than the Directors or chief executive of the Company) who had any interest or short position in the shares and underlying shares of the Company as recorded in the register required to be kept under Section 336 of the SFO or as required to be disclosed to the Company and the Stock Exchange under Divisions 2 and 3 of Part XV of the SFO.

Saved as disclosed in this section, as at the Latest Practicable Date, none of the Directors or Proposed Directors was a director or employee of a company which had an interest in the Shares and underlying Shares which would fall to be disclosed under the provisions of Divisions 2 and 3 of Part XV of the SFO.

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GENERAL INFORMATION

APPENDIX III

3. COMPETING INTERESTS

As at the Latest Practicable Date, none of the Directors or their respective associates had any interest in a business, apart from the business of the Company, which competes or is like to compete with the business of the Company or has any other conflict of interest with the Company which would be required to be disclosed under Rule 8.10 of the Listing Rules.

4. INTEREST IN CONTRACT OR ARRANGEMENT

As at the Latest Practicable Date, none of the Directors has any direct or indirect interests in any assets which have been acquired or disposed of by or leased to, or which are proposed to be acquired or disposed of by or leased to, the Group since December 31, 2017, the date to which the latest published audited consolidated financial statements of the Group were made up.

As at the Latest Practicable Date, so far is known to the Directors, there is no contract or arrangement entered into by any member of the Group subsisting at the Latest Practicable Date in which any Director is materially interested and which is significant to the business of the Group.

5. DIRECTORS’ SERVICE CONTRACTS

On November 20, 2009, Mr. Zhang Ruilin and Mr. Zhao Jiangwei, each an executive Director, each entered into a service contract with the Company, which is renewable yearly unless terminated (i) with twelve months’ notice by either party, or (ii) by the Company upon certain events such as the Director having committed serious or persistent breaches of the service contract. Should the Company terminate the service contract, Zhang Ruilin and Zhao Jiangwei will be entitled to receive a severance payment equivalent to one year’s basic pay under the service contract, save for circumstances described in item (ii) above.

Save as disclosed above, as at the Latest Practicable Date, none of the Directors had any existing service contract or proposed service contract with the Group which is not determinable by the Group within one year without payment of compensation other than statutory compensation.

6. MATERIAL ADVERSE CHANGE

As at the Latest Practicable Date, the Directors were not aware of any material adverse change in the financial or trading position of the Group since December 31, 2017, the date to which the latest published audited accounts of the Company were made up.

– III-6 –

GENERAL INFORMATION

APPENDIX III

7. EXPERT AND CONSENT

The following is the qualification of the expert who has been named in this circular or have given opinion or advice contained in this circular:

Name Qualification

Sproule Associates Limited Competent Person

Sproule Associates Limited is referred to as the ‘‘Expert’’ hereinafter.

As at the Latest Practicable Date, the Expert had no shareholding in any member of the Group, nor had any right, whether legally enforceable or not, to subscribe for or to nominate persons to subscribe for securities in any member of the Group, nor had any direct or indirect interest in any assets which have been acquired or disposed of by, or leased to, any member of the Group or are proposed to be acquired or disposed of by, or leased to, any member of the Group since December 31, 2017, the date to which the latest published audited accounts of the Group was made up.

The Expert has given and has not withdrawn its written consent to the issue of this circular with the inclusion of its letter(s) or report(s) and reference to its name in the form and context in which it is included.

8. LITIGATION

As at the Latest Practicable Date, no members of the Group were engaged in any litigation, arbitration or claim of material importance and no litigation, arbitration or claim of material importance is known to the Directors to be pending or threatened against the Group.

9. MATERIAL CONTRACTS

The following contracts (not being contracts entered into in the ordinary course of business) have been entered into by the members of the Group within two years immediately preceding the issue of this circular and are material:

(a) a sale and purchase agreement dated April 26, 2016 between the Company and China New Energy Mining Limited relating to the disposal of the entire issued shares capital of Asia Gas & Energy Ltd. and the shareholder’s loan owed by Asia Gas & Energy Ltd. to China New Energy Mining Limited in consideration of US$ 220 million (approximately HK$1,720.8 million) (subject to adjustment);
(b) a purchase and sale agreement dated May 10, 2016 entered into between CQR Partnership and Tourmaline Oil Corp. for disposal of a portion of its interests in the Parkland area of British Columbia, Canada in consideration of C$7,500,000 (equivalent to approximately HK$45,627,000) (subject to adjustment);

– III-7 –

GENERAL INFORMATION

APPENDIX III

(c) a share purchase agreement dated September 15, 2016 entered between the MIE Maple Investments Limited (a wholly owned subsidiary of the Company) and InfraPSP Partners Inc., pursuant to which Infra-PSP Partners Inc. conditionally agreed to sell and MIE Maple Investments Limited conditionally agreed to purchase approximately 37.5% of the equity interests in Journey Energy Inc. for a cash consideration of C$33,846,602 (equivalent to approximately HK$205,909,188);
(d) a loan agreement dated December 16, 2016 entered between the Company, BostonPower, Inc. and G-O Scale Capital Management Co., LLC, pursuant to which the Company agreed to provide a loan in the amount of US$30 million (equivalent to approximately HK$234.7 million) with interest of 9% per annum to Boston-Power, Inc.;
(e) a purchase and sale agreement dated May 29, 2017 entered into between CQR Partnership and Leucrotta Exploration Inc. for disposal of its interests in the Pouce Coupe area of Alberta and British Columbia, Canada in consideration of C$5,000,000 (equivalent to approximately HK$30,418,000);
(f) the partnership interest purchase and sale agreement (the ‘‘PSA’’) dated May 31, 2017 entered into between Direct Energy Resources Partnership (‘‘Direct Energy’’) and an undisclosed body corporate (‘‘A Partner’’) in relation to the sale and purchase of 100% of the interests of partner in CQ Energy Canada Partnership;
(g) the subscription agreement dated May 31, 2017 entered into between Canlin Energy Corporation (‘‘Canlin’’), CCGRF Gastown Limited, Maple Marathon Investments Limited, Mercuria Energy Netherlands BV and the Company in relation to the subscription of convertible preferred shares issued by Canlin;
(h) an amending agreement dated June 8, 2017 entered into between Direct Energy and A Partner for the purpose of amending the date and time for escrow release under the PSA;
(i) a sale and purchase agreement dated December 1, 2017 entered into between the Company and Pacific Energy Development (Asia) Co. Corp. in relation to the disposal of the entire issued share capital of Riyadh Energy Limited;
(j) a sale and purchase agreement dated December 21, 2017 entered into between Global Oil Corporation and MIE International Resources Limited in relation to the acquisition of 10% participating interests in the foreign contractors’ entitlement and obligations under certain production sharing contracts for each of the Daan oilfield and the Moliqing oilfield;
(k) a share purchase agreement dated January 22, 2018 entered into between MIE Maple Investments Limited and Journey Energy Inc., (‘‘Journey’’) in relation to Journey’s acquisition of 12,700,000 issued and outstanding common shares in the capital of Journey; and
(l) the Agreement.

– III-8 –

GENERAL INFORMATION

APPENDIX III

10. MISCELLANEOUS

(a) The registered office of the Company is at P.O. Box 309, Ugland House, Grand Cayman KY1-1 104, Cayman Islands. The head office of the Company is at Suite 1501, Block C, Grand Place, 5 Hui Zhong Road, Chaoyang District, Beijing 100101, the People’s Republic of China and the principal place of business in Hong Kong is at Level 54, Hopewell Centre, 183 Queen’s Road East, Hong Kong.
(b) The branch share registrar and transfer office of the Company in Hong Kong is Tricor Investor Services Limited, at Level 22, Hopewell Centre, 183 Queen’s Road East, Hong Kong.
(c) The company secretary of the Company is Ms. Wong Sau Mei. Ms. Wong is an Associate of both The Hong Kong Institute of Chartered Secretaries and The Institute of Chartered Secretaries and Administrators.
(d) This circular is prepared in both English and Chinese. In the event of inconsistency, the English version shall prevail.

11. DOCUMENTS FOR INSPECTION

Copies of the following documents will be available for inspection at the Company’s principal place of business in Hong Kong at Level 54, Hopewell Centre, 183 Queen’s Road East, Hong Kong during normal business hours on any weekday (except public holidays) for a period of 14 days from the date of this circular:

(a) the memorandum and articles of association of the Company;
(b) the annual report of the Company for the financial year ended December 31, 2016 and the annual results announcement of the Company for the financial year ended December 31, 2017;
(c) the contracts referred to in the paragraph headed ‘‘Directors’ Service Contracts’’ in this Appendix;
(d) the contracts referred to in the paragraph headed ‘‘Material Contracts’’ in this Appendix;
(e) the Competent Person’s Report prepared by the Competent Person, the text of which are set out in Appendix II to this circular;
(f) the written consent from the Competent Person referred to in the paragraph headed ‘‘Expert and Consent’’ in this Appendix; and
(g) this circular.

– III-9 –

NOTICE OF EGM

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MIE HOLDINGS CORPORATION MI能源控股有限公司

(Incorporated in the Cayman Islands with limited liability)

(Stock Code: 1555)

NOTICE OF EXTRAORDINARY GENERAL MEETING

NOTICE IS HEREBY GIVEN THAT the extraordinary general meeting (the ‘‘EGM’’) of MIE Holdings Corporation (the ‘‘Company’’) will be held at Plaza 1–2, Novotel Century Hong Kong, 238 Jaffe Road, Wanchai, Hong Kong on Monday, May 7, 2018 at 10:00 a.m. for the purpose of considering and, if thought fit, passing with or without modification or amendment the following resolution:

ORDINARY RESOLUTION

‘‘THAT:

(a) the agreement of purchase and sale dated March 23, 2018 entered into between the Vendor and the Purchaser (as defined in the circular of the Company dated April 19, 2018) (a copy of which is produced to the EGM marked ‘‘A’’ and initialed by the chairman of the EGM for the purpose of identification), and the terms and conditions thereof and the transactions contemplated thereunder and the implementation thereof be and are hereby approved and confirmed; and
(b) the authorization to any one of the Directors, or any other person authorized by the Board from time to time, for and on behalf of the Company, among other matters, to sign, seal, execute, perfect, perform and deliver all such agreements, instruments, documents and deeds, and to do all such acts, matters and things and take all such steps as he or she or they may in his or her or their absolute discretion consider to be necessary, expedient, desirable or appropriate to give effect to and implement the Agreement and the transactions contemplated thereunder and all matters incidental to, ancillary to or in connection thereto, including agreeing and making any modifications, amendments, waivers, variations or extensions of the Agreement or the transactions contemplated thereunder be and are hereby approved, ratified and confirmed.’’

By order of the Board MIE Holdings Corporation Zhang Ruilin Chairman

Hong Kong, April 19, 2018

– EGM-1 –

NOTICE OF EGM

Notes:

(1) All resolutions at the meeting will be taken by poll pursuant to the Rules Governing the Listing of Securities on The Stock Exchange of Hong Kong Limited (the ‘‘Listing Rules’’) and the results of the poll will be published on the website of the Hong Kong Exchanges and Clearing Limited and the Company in accordance with the Listing Rules.
(2) Any shareholder of the Company entitled to attend and vote at the above meeting is entitled to appoint more than one proxy to attend and on a poll, vote instead of him. A proxy need not be a shareholder of the Company.
(3) In order to be valid, the form of proxy together with the power of attorney or other authority, if any, under which it is signed or a certified copy of that power of attorney or authority, must be deposited at the Company’s branch share registrar in Hong Kong, Tricor Investor Services Limited, at Level 22, Hopewell Centre, 183 Queen’s Road East, Hong Kong not less than 48 hours before the time appointed for the holding of the meeting or any adjourned meeting thereof (as the case may be). Delivery of the form of proxy shall not preclude a shareholder of the Company from attending and voting in person at the meeting and, in such event, the instrument appointing a proxy shall be deemed to be revoked.
(4) Where there are joint holders of any share of the Company, any one of such holders may vote at the meeting, either personally or by proxy, in respect of such share as if he was solely entitled thereto, but if more than one of such holders be present at the meeting personally or by proxy, that one of such holders so present whose name stands first on the register of members of the Company in respect of such share shall alone be entitled to vote in respect thereof.
(5) For determining the entitlement to attend and vote at the meeting, the register of members of the Company will be closed from Wednesday, May 2, 2018 to Monday, May 7, 2018, both days inclusive, during which period no transfer of shares will be registered. In order to be eligible to attend and vote at the meeting, all transfer documents accompanied by the relevant share certificates must be lodged with the Company’s branch share registrar in Hong Kong, Tricor Investor Services Limited, at Level 22, Hopewell Centre, 183 Queen’s Road East, Hong Kong, for registration not later than 4:30 p.m. on Monday, April 30. 2018.
As at the date of this notice, the Board comprises of (1) the executive Directors namely
Mr. Zhang Ruilin, Mr. Zhao Jiangwei; (2) the non-executive Directors namely Ms. Xie Na and Mr. Jiao Qisen; and (3) the independent non-executive Directors namely Mr. Mei Jianping, Mr. Jeffrey W. Miller and Mr. Guo Yanjun.

– EGM-2 –

AI assistant

MIE Holdings Corporation — Proxy Solicitation & Information Statement 2018

49998_rns_2018-04-18_8d38c193-ca6b-4086-bb0e-67bf5a19ea50.pdf

MIE HOLDINGS CORPORATION MI能 源控股 有限公司

(1) MAJOR TRANSACTION IN RELATION TO THE DISPOSAL OF ASSETS

AND

(2) NOTICE OF THE EXTRAORDINARY GENERAL MEETING

DEFINITIONS

MIE HOLDINGS CORPORATION MI能 源控股 有限公司

(Stock Code: 1555)

To the Shareholders

(1) MAJOR TRANSACTION IN RELATION TO THE DISPOSAL OF ASSETS AND

(2) NOTICE OF THE EXTRAORDINARY GENERAL MEETING

INTRODUCTION

LETTER FROM THE BOARD

THE AGREEMENT

Date

Parties

Subject matter of the Disposal

Consideration

Base Price and adjustments

LETTER FROM THE BOARD

Operating adjustments

Payment of Consideration

Conditions precedent

Purchaser’s conditions

Vendor’s conditions

Closing

KEY SUMMARY OF THE COMPETENT PERSON’S REPORT

INFORMATION ON THE PARTIES

The Group

The Purchaser

FINANCIAL INFORMATION ON THE ASSETS AND FINANCIAL EFFECTS OF THE DISPOSAL

USE OF PROCEEDS

REASONS FOR AND BENEFITS OF THE DISPOSAL

LETTER FROM THE BOARD

IMPLICATIONS UNDER THE LISTING RULES

EGM

CLOSURE OF REGISTER OF MEMBERS

RECOMMENDATION

ADDITIONAL INFORMATION

1. STATEMENT OF INDEBTEDNESS

Borrowings

Compound Instruments

Charges

Contingent liabilities

2. WORKING CAPITAL STATEMENT

3. FINANCIAL AND TRADING PROSPECTS OF THE GROUP

1. Table of Contents

Tables

Figures

Appendices

2. Executive Summary

Table 2.1

Canlin Energy Corporation Consolidated

Summary of the Evaluation of the P.& N.G. Reserves As Of Date : 2017-12-31

Table 2.1

3. Introduction

3.1 Scope and Terms of Reference

3.2 Statement of Competent Persons

Barrett R. (Barry) Hanson, P.Eng., SPEC

Alec Kovaltchouk, P.Geo.

Nora T. Stewart, P.Eng.

3.3 Credentials of Sproule

3.4 Field Operations

3.5 Nature and Source of Information

3.6 Reporting Standards

3.7 Effective and Preparation Dates

3.8 Evaluation Procedures

Introduction — Page 7

3.9 Evaluation Results

3.10 Reserve Definitions

3.11 Abbreviations

4. Summary of Assets

4.1 Location of Assets

4.2 Ownership and Acreage

4.3 Reserves and Net Present Value

4.4 Project Gross Field Production Profiles

5. Regional Geological Discussion

5.1 Regional Petroleum History

MIE Holdings Corporation Proxy Solicitation & Information Statement 2018

MIE HOLDINGS CORPORATION MI能源控股有限公司

MIE HOLDINGS CORPORATION MI能源控股有限公司