MIE Holdings Corporation - Proxy Solicitation & Information Statement 2017

THIS CIRCULAR IS IMPORTANT AND REQUIRES YOUR IMMEDIATE ATTENTION

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

If you have sold or transferred all your shares in MIE Holdings Corporation, you should at once hand this circular with the accompanying form of proxy to the purchaser or the transferee or to the bank, stockbroker 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)

(I) VERY SUBSTANTIAL ACQUISITION IN RELATION TO THE PROPOSED ACQUISITION OF ALL THE PARTNERSHIP INTERESTS OF CQ ENERGY CANADA PARTNERSHIP AND

(II) MAJOR DISPOSAL IN RELATION TO THE DEEMED DISPOSAL OF 36.4% EQUITY INTEREST IN A WHOLLY-OWNED SUBSIDIARY

Capitalised terms used on this cover shall have the same meanings as those defined in this circular.

A letter from the Board is set out on pages 12 to 39 of this circular.

A notice convening the EGM of MIE Holdings Corporation to be held at Plaza 3, Novotel Century Hong Kong, 238 Jaffe Road, Wanchai, Hong Kong on Friday, September 22, 2017 at 9:30 a.m. or any adjournment thereof is set out on pages EGM-1 to EGM-2 of this circular. A form of proxy for use at the EGM is also enclosed. Such form of proxy is also published on the websites of Hong Kong Exchanges and Clearing Limited (http://www.hkexnews.hk) and the Company (http://www.mienergy.com.cn).

Whether or not you are able to attend and vote at the EGM, please complete and sign the enclosed form of proxy in accordance with the instructions printed thereon and return it to 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 as soon as possible but in any event not less than 48 hours before the time appointed for the holding of the EGM or any adjournment thereof. Completion and return of the form of proxy as instructed will not preclude you from attending and voting in person at the EGM if you so wish.

September 7, 2017

CONTENTS

		Page
DEFINITIONS	. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	1
GLOSSARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .		11
LETTER FROM THE BOARD . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .		12
APPENDIX I	— FINANCIAL INFORMATION OF THE GROUP . . . . . . . . .	I-1
APPENDIX II	— ACCOUNTANT’S REPORT ON
	THE TARGET GROUP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	II-1
APPENDIX III	— UNAUDITED PRO FORMA FINANCIAL INFORMATION
	OF THE ENLARGED GROUP . . . . . . . . . . . . . . . . . . . . . . . . .	III-1
APPENDIX IV	— FURTHER INFORMATION ON
	THE TARGET GROUP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	IV-1
APPENDIX V	— COMPETENT PERSON’S REPORT AND
	VALUATION REPORT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	V-1
APPENDIX VI	— GENERAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	VI-1
NOTICE OF EGM . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .		EGM-1

– i –

DEFINITIONS

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

‘‘509760’’ 509760 Alberta Ltd. ‘‘8401268’’ 8401268 Canada Inc. ‘‘A Partner’’ an undisclosed body corporate holding as at the date hereof 40% of the Partnership Interests of the Target Company ‘‘Acquired Entities’’ or collectively, the Target Company, CQR Partnership and ‘‘Target Group’’ 8401268 ‘‘Acquisition’’ the proposed acquisition of the Partnership Interests by the Purchaser from the Vendors pursuant to the PSA ‘‘Applicable Law’’ means all applicable laws, statutes, rules, regulations, official directives and orders of Government Authorities (whether administrative, legislative, executive or otherwise), including judgments, orders and decrees of courts, commissions or bodies exercising similar functions ‘‘Board’’ the board of Directors ‘‘Business Day(s)’’ a day other than a Saturday, a Sunday or a statutory holiday in Calgary, Alberta or Hong Kong ‘‘C$’’, ‘‘CDN$’’ or ‘‘Canadian Canadian Dollars, the lawful currency of Canada Dollar’’ ‘‘CCGRF’’ Can-China Global Resource Fund L.P., a limited partnership existing under the laws of Cayman Islands, and solely managed by MEC Advisory Limited ‘‘Claim’’ any claim, including any demand, lawsuit, proceeding, arbitration or any proceeding or investigation by a Government Authority ‘‘Closing’’ the transfer of the Partnership Interests to the Purchaser, the payment of the Consideration and the delivery of all items required to be delivered including, but without limitation, an acknowledgment executed by DEML that DEML resigns as operator of the Target Company effective as of the Closing Date pursuant to the terms of the PSA

– 1 –

DEFINITIONS

‘‘Closing Date’’
means the date that is five (5) Business Days following the day on which the Investment Canada Act Clearance and Competition Act Approval have been obtained by the Parties in accordance with the terms of the PSA, or such other date as may be agreed on in writing by the Parties
‘‘Closing Time’’
10:00 a.m. on the Closing Date, or such other time as may be agreed upon in writing by the Vendors and Purchaser on the Closing Date.
‘‘Common Share(s)’’
the ordinary common share(s) in the share capital of the Purchaser
‘‘Company’’, ‘‘MIE’’ 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
‘‘Competition Act’’
Competition Act, R.S.C. 1985, c. C-34, as amended
‘‘Competition Act Approval’’
the Commissioner of Competition appointed under the Competition Act or his designee has issued an advance ruling certificate pursuant to section 102 of the Competition Act in respect of the Acquisition on terms and conditions satisfactory to the Vendors and Purchaser acting reasonably; or the Commissioner has advised the Vendors and Purchaser that he does not intend to apply to the Competition Tribunal for an order under section 92 of the Competition Act in respect of the Acquisition and (ii) the requirement of the Parties to notify the Commissioner under Part IX pursuant to paragraph 113(c) of the Competition Act has been waived or the waiting period under Part IX has expired or been terminated
‘‘Conditions Precedent’’
the conditions to Closing under the PSA, being the Purchaser’s conditions and the Vendors’ conditions
‘‘Connected Person(s)’’
has the meaning ascribed to it under the Listing Rules
‘‘Consideration’’
the purchase price payable by the Purchaser to the Vendors in relation to the Acquisition pursuant to the PSA
‘‘Conversion’’
when the Subscriber(s) exercise(s) the conversion right of the Convertible Preferred Shares
‘‘Conversion Ratio’’
each 0.83 Common Shares for every one Convertible Preferred Share

– 2 –

DEFINITIONS

‘‘Conversion Share(s)’’
‘‘Convertible Preferred Shares’’
‘‘CQR Partnership’’
‘‘Deemed Disposal’’
‘‘DEML’’
‘‘DEML Downstream Business’’
‘‘Deposit’’
‘‘DERP’’
‘‘Directors’’
the new Common Shares to be allotted and issued by the Purchaser upon exercise of the conversion rights attaching to the Convertible Preferred Shares
the Convertible Preferred Shares issued by the Purchaser to CCGRF and Mercuria pursuant to the Subscription Agreement
CQ Energy Canada Resources Partnership
the deemed disposal of the Company’s interest of 36.4% in the Purchaser as a result of the Conversion under Rule 14.29 of the Listing Rules
Direct Energy Marketing Limited
the downstream business and related businesses conducted by DEML and any of its Affiliates (excluding the Acquired Entities and 509760) consisting of: (i) natural gas and electricity sales/supply as well as energy management and services for commercial and industrial customers; (ii) natural gas and electricity sales/supply for residential customers; (iii) HVAC (heating, ventilation, air conditioning) installation and service, plumbing, water heaters, protection plans, building automation, facility maintenance, energy audits, energy management consulting, services for both residential and commercial/industrial customers; (iv) business management and operational counseling to independent home services contractors; (v) power generation and wind power purchase agreements; (vi) midstream gas storage (excluding Petroleum Substances for the account of CQR Partnership) and transportation (excluding Tangibles and any transportation service in the name of or for the account of CQR Partnership), commodity procurement (other than in the name of CQR Partnership) and proprietary trading, energy auctions and renewable energy credits; and (vii) all associated intellectual property related to any of the foregoing
means the deposit in an amount equal to C$70,000,000 (equivalent to approximately HK$404,908,000)
Direct Energy Resources Partnership, a partnership having an office and carrying on business in the City of Calgary, in the Province of Alberta

the director(s) of the Company

– 3 –

DEFINITIONS

‘‘Distribution’’

as applicable, a distribution of the Target Company’s cash or other property to DERP or A Partner (‘‘Partner’’), whether as a distribution of income or a return of capital to a Partner (but for certainty does not include payment to a Partner or an Affiliate for settlement of an intercompany account for goods or services or other cost reimbursement)

‘‘Document Escrow Release Time’’
5:30 p.m. on June 8, 2017 (Calgary time)
‘‘Effective Date’’
July 1, 2016
‘‘Effective Time’’ means 8:00 a.m. on the Effective Date
‘‘EGM’’
the extraordinary general meeting of the Company to be held at Plaza 3, Novotel Century Hong Kong, 238 Jaffe Road, Wanchai, Hong Kong on Friday, September 22, 2017 at 9:30 a.m. or any adjournment thereof to consider, and if thought fit, approve, among other things, the PSA, the Subscription Agreement and the transactions contemplated therein
‘‘Enlarged Group’’

the Group as enlarged by the Target Group upon Closing

‘‘Environment’’
means the atmosphere, the surface and sub-surface of the earth, groundwater and surface water and plants and animals; and ‘‘Environmental’’ means relating to or in respect of the Environment
‘‘Escrow Agent’’
Stikeman Elliott LLP
‘‘Escrow Agreement’’

the escrow agreement entered into between the Vendors, the Purchaser, Far East, the Company and the Escrow Agent on May 31, 2017 (Calgary time)

– 4 –

DEFINITIONS

‘‘Excluded Assets’’
the right, title, estate and interest of Vendors or their Affiliates, or any of their predecessors, held at any time in respect of the following: (i) all tax pools, other than those tax pools of the Acquired Entities; (ii) software owned or leased by Vendors or their Affiliates, other than software owned or leased by the Acquired Entities; (iii) Restricted DEML Seismic Data; (iv) amounts paid or received prior to Closing, or payable or receivable as of Closing, by the Target Company resulting from the net settlement of the Suncor FSOA and related Suncor arrangements from the 2013 acquisition of CQR Partnership; (v) physical and electronic files, including email data, to the extent they relate to Centrica plc or A Partner or their respective Affiliates, other than the Acquired Entities; and (vi) assets related to the DEML Downstream Business, which are primarily held by partners (or their affiliates) of the Acquired Entities and not by the Acquired Entities and such assets are not required to conduct the business of the Acquired Entities
‘‘Far East’’ or ‘‘FEEL’’
Far East Energy Limited, a limited liability company incorporated under the laws of Hong Kong and a substantial shareholder of the Company
‘‘Gastown’’
CCGRF Gastown Limited, a limited company existing under the laws of Hong Kong and a wholly-owned subsidiary of CCGRF
‘‘Government Authority’’
any government, regulatory or administrative authority, government department, agency, commission, board or tribunal or court having jurisdiction on behalf of any nation, province or state or subdivision thereof or any municipality, district or subdivision thereof
‘‘Group’’ the Company and its subsidiaries
‘‘HK$’’
Hong Kong dollars, the lawful currency of Hong Kong
‘‘Hong Kong’’
the Hong Kong Special Administrative Region of the People’s Republic of China
‘‘IFRS’’
International Financial Reporting Standards
‘‘Interim Period’’
the period from (and including) the date of the PSA to the Closing Time
‘‘Investment Canada Act’’
Investment Canada Act R.S.C., 1985 c.28 (1st Supp.), as amended

– 5 –

DEFINITIONS

‘‘Investment Canada Act Clearance’’
(a) Purchaser shall not have received notice from a Governmental Authority under either section 25.2(1) or section 25.3(2) of the Investment Canada Act within the periods prescribed under the Investment Canada Act or if Purchaser has received such a notice, the Purchaser shall have subsequently received one of the following notices, as applicable: (i) under section 25.2(4)(a) of the Investment Canada Act indicating that no order for the review of the transactions contemplated by the PSA will be made under section 25.3(1) of the Investment Canada Act, (ii) under section 25.3(6)(b) of the Investment Canada Act indicating that no further action will be taken in respect of the Transaction, or (iii) under section 25.4(1) of the Investment Canada Act indicating that the Governor in Council authorises the Closing of the Acquisition, in each case on terms and conditions satisfactory to Purchaser, in its reasonable discretion; and, if applicable, (b) the Minister (within the meaning of the Investment Canada Act) has sent a notice to Purchaser under the Investment Canada Act stating, the Minister (within the meaning of the Investment Canada Act) is satisfied or is deemed to be satisfied that the Acquisition is likely to be of net benefit to Canada
‘‘Latest Practicable Date’’
September 4, 2017, being the latest practicable date prior to the printing of this circular for ascertaining certain information contained herein
‘‘Listing Rules’’ the Rules Governing the Listing of Securities on the Stock Exchange
‘‘Maple Marathon’’ Maple Marathon Investments Limited, a corporation incorporated under the laws of Hong Kong and a whollyowned subsidiary of the Company
‘‘Mercuria’’
Mercuria Energy Group Ltd., a privately held Swiss-based international commodity trading company
‘‘Mercuria Energy Netherlands’’ Mercuria Energy Netherlands BV, a wholly-owned subsidiary of Mercuria
‘‘Model Code’’
Model Code for Securities Transactions by Directors of Listed Issuers as contained in Appendix 10 of the Listing Rules
‘‘OECD’’ The Organisation for Economic Co-operation and Development

– 6 –

DEFINITIONS

‘‘Outside Date’’
‘‘Partnership Interests’’
‘‘Person’’
‘‘Petroleum Substances’’
‘‘PSA’’
‘‘Purchaser’’ or ‘‘Canlin’’
‘‘Purchaser Default’’
‘‘Qualifying Misrepresentations’’
‘‘Restricted DEML Seismic Data’’
‘‘Scheduled Assets’’

September 30, 2017

100% of the interests of partner in the Target Company, being an undivided 60% interest in the Target Company held by DERP and an undivided 40% interest in the Target Company held by A Partner
any individual or entity, including any partnership, body corporate, trust, unincorporated organization, union, government or Government Authority and any heir, executor, administrator or other legal representative of an individual means petroleum, natural gas and all related hydrocarbons (including liquid hydrocarbons) and all other mineral substances, whether liquid, solid or gaseous and whether hydrocarbon or not (including sulphur and hydrogen sulfide) produced in association with petroleum, natural gas or related hydrocarbons
the Partnership Interest Purchase and Sale Agreement dated May 31, 2017 entered into between the Vendors, the Purchaser and the Company in relation to the proposed purchase of the Partnership Interests
Canlin Energy Corporation (formerly known as Maple Felix Energy Corporation), a company incorporated in British Columbia, Canada and a wholly-owned subsidiary of the Group
means a material breach of a representation or warranty made by the Purchaser in the PSA or a material breach by the Purchaser of a covenant or agreement in the PSA
the negative impact of an untrue representation and warranty on the aggregate value of the Partnership Interests exceeds 0.75% of the Base Purchase Price
means Seismic Data held by DEML that is subject to transfer restrictions that prohibit its transfer
(i) the Petroleum and Natural Gas Rights, (ii) the Wells; and (iii) Vendors’ and its Affiliates’ interests in the Major Facilities

– 7 –

DEFINITIONS

‘‘Senior Secured Revolving a senior secured revolving credit facility in an aggregate Credit Facility’’ commitment amount of C$240,000,000 (equivalent to approximately HK$1,388,256,000) to be provided by a syndicate of banks to the Purchaser
‘‘SFO’’
Securities and Futures Ordinance (Chapter 571 of the Laws of Hong Kong)
‘‘Shareholder(s)’’ holder(s) of the Shares
‘‘Stock Exchange’’ The Stock Exchange of Hong Kong Limited
‘‘Subscribers’’ collectively, Gastown, Maple Marathon and Mercuria Energy Netherlands
‘‘Subscription’’ the proposed subscription of the Convertible Preferred Shares pursuant to the terms and conditions of the Subscription Agreement
‘‘Subscription Agreement’’ the subscription agreement dated May 31, 2017 entered into between the Purchaser, the Subscribers and the Company in relation to the Subscription
‘‘Suncor FSOA’’
the final statement of adjustments under the Suncor Energy Resources Partnership’s (‘‘Suncor’’) partnership interest and share purchase and sale agreement dated April 15, 2013 between Suncor Energy Inc. and the Target Company (as assignee of DERP and A Partner)
‘‘Suncor FSOA Distribution’’
means the Distribution made by the Target Company to the Partners on or about January 12, 2017 in an approximate aggregate amount of C$5,800,000 (equivalent to approximately HK$33,549,520) (which amount does not exceed the net amount paid by Suncor Energy Inc. (or an affiliate) to the Target Company or CQR Partnership on its behalf in respect of the Suncor FSOA settlement)

– 8 –

DEFINITIONS

‘‘Tangibles’’

the entire right, title, estate and interest of CQR Partnership, its designated Affiliates and 509760 (whether absolute or contingent, legal or beneficial) in and to: the major facilities described in the PSA; and all tangible depreciable property and assets which are situate in, on or about the lands in the White Map Areas or appurtenant thereto and which are used or were used or are intended to be used by or on behalf of CQR Partnership, 509760 or the designated Affiliates in connection with: production, gathering, processing, measuring, making marketable, injection, removal, transmission, treatment or storage of Petroleum Substances or operations thereon or relative thereto; the Wells; or water or miscible fluids injection or removal operations including gas plants, camps, oil batteries, pipelines, buildings, structures, production equipment, fresh and produced water facilities, flowlines, gathering pipelines connections, gathering systems, meters, dehydrators, motors, compressors, treaters, scrubbers, separators, pumps, tanks, boilers and communication equipment (including SCADA equipment), roads, railspurs, railway sidings and generators

‘‘Target Company’’ or ‘‘Target’’ CQ Energy Canada Partnership
‘‘Third Parties’’
any Person other than the parties to the PSA or their respective Affiliates
‘‘Transactions’’ the transactions contemplated under the PSA
‘‘US$’’ US Dollars, the lawful currency of the United States of America
‘‘Vendor’’ each of DERP and A Partner, and ‘‘Vendors’’ means, collectively, DERP and A Partner
‘‘Wells’’ the wells identified in schedule C to the PSA and all other wells which are located in the White Map Area or which are, may be or were used in connection with the Petroleum and Natural Gas Rights, including, producing, shut-in, suspended, abandoned, water source, injection or disposal wells
‘‘White Map Areas’’ all lands outlined on the plat(s) in the schedule A to the PSA as the White Map Areas and includes, as the context requires, the surface of those lands and the Petroleum Substances within those lands

– 9 –

DEFINITIONS

‘‘%’’ per cent.

Translation of amounts in C$ into Hong Kong dollars is based on the rate of C$: HK$5.7844. This conversion rate is for the purpose of illustration only and does not constitute a representation that any amounts have been, could have been, or may be exchanged at the aforementioned or any other rates at all.

– 10 –

GLOSSARY

‘‘Bbl/d’’	barrels per day
‘‘boe/d’’	barrels of oil equivalent per day
‘‘EBITDA’’	refers to earnings before finance income, finance costs,
	income tax and depreciation, depletion and amortization
‘‘MMboe’’	millions of barrels of oil equivalent
‘‘MMcf’’	millions of cubic feet
‘‘MMcf/d ‘‘	millions of cubic feet per day
‘‘NPV’’	net present value of future net revenue

– 11 –

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 Director: Ms. Xie Na

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

Registered office: P.O. Box 309 Ugland House Grand Cayman KY1-1104 Cayman Islands

Principal Place of Business in Hong Kong: Level 22, 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 The People’s Republic of China

September 7, 2017

To the Shareholders

Dear Sir/Madam,

(I) VERY SUBSTANTIAL ACQUISITION

IN RELATION TO THE PROPOSED ACQUISITION OF ALL THE PARTNERSHIP INTERESTS OF CQ ENERGY CANADA PARTNERSHIP AND

(II) MAJOR DISPOSAL IN RELATION TO THE DEEMED DISPOSAL OF 36.4% EQUITY INTEREST IN A WHOLLY-OWNED SUBSIDIARY

– 12 –

LETTER FROM THE BOARD

INTRODUCTION

Reference is made to the announcement of the Company published on June 9, 2017 in relation to the signing of the PSA, pursuant to which the Vendors have conditionally agreed to sell, and the Purchaser agreed to purchase the Partnership Interests, representing all the partnership interests in the Target Company, at a Consideration of C$722,000,000 (equivalent to approximately HK$4,176,336,800) (subject to adjustments in accordance with the PSA).

On or prior to the Document Escrow Release Time, the Purchaser has paid a C$70,000,000 (equivalent to approximately HK$404,908,000) Deposit into an escrow account held by the Escrow Agent pursuant to the Escrow Agreement. The remaining balance of the Consideration calculated in accordance with the PSA will be paid upon Closing.

In order to facilitate the Acquisition, each of the Subscribers and the Purchaser entered into the Subscription Agreement on May 31, 2017 (Calgary time) in respect of the issue of: (i) an aggregate of 296,000,000 Common Shares to Maple Marathon, and (ii) the Convertible Preferred Shares in the aggregate principal amount of C$204,000,000 (equivalent to approximately HK$1,180,017,600), convertible into Common Shares on the basis of 0.83 Common Shares for every one Convertible Preferred Share, to Gastown and Mercuria Energy Netherlands.

Upon full conversion of the Convertible Preferred Shares at the Conversion Ratio, a total of 169,320,000 Conversion Shares will be issued, representing approximately 36.4% of the issued share capital of the Purchaser as enlarged by the issue of the Conversion Shares. Upon full conversion of the Convertible Preferred Shares, the Purchaser will remain to be a subsidiary of the Company, but the Company’s equity interest in the Purchaser will be reduced to approximately 63.6%.

For the purpose of amending the date and time for the escrow release under the PSA, the parties to the PSA entered into the amending agreement (the ‘‘Amending Agreement’’) on June 8, 2017 (Calgary time). The PSA was released from escrow and delivered to the parties on the Document Escrow Release Time.

The purpose of this circular is to give you, among other things, (i) further details of the PSA, the Subscription Agreement and the Transactions contemplated thereunder and the major transaction regarding the Deemed Disposal; (ii) the financial information of the Target Group; (iii) the pro forma financial information of the Enlarged Group; (iv) the Competent Person’s Report and the Valuation Report in respect of the oil and gas reserves of the Target Group; (v) other information as required under the Listing Rules; and (vi) the notice convening the EGM.

– 13 –

LETTER FROM THE BOARD

1. THE PSA

1.1. Date

May 31, 2017

1.2. Parties

(i) The Purchaser
(ii) The Vendors
(iii) The Company

To the best of the Directors’ knowledge, information and belief, having made all reasonable enquiries, the Vendors and their respective ultimate beneficial owners are third parties independent of the Company and its Connected Persons.

1.3. Subject Matter

The Purchaser has conditionally agreed to acquire and the Vendors have conditionally agreed to sell the Partnership Interests, representing all the partnership interests in the Target Company.

The parties commenced negotiation on the Acquisition in 2016. Pursuant to and subject to the terms and conditions of the PSA, if Closing occurs, the economic risks and benefits of the Acquired Entities as from the Effective Date (excluding, however, the Excluded Assets) will be for the account of the Purchaser. The economic risks, with certain limited exceptions, associated with employees and environmental matters will be borne by the Purchaser regardless of whether they arose before or after the Effective Date.

The Acquired Entities own a diverse base of producing, resource and infrastructure assets located throughout Alberta, Saskatchewan, Manitoba, Ontario and British Columbia in Canada. The portfolio includes midstream infrastructure assets in active areas including Ferrier (North business unit), Hanlan (Hanlan-Robb business unit), Carrot Creek (North business unit) and Wildcat Hills (Foothills business unit). Currently, the Target Company owns 11 major facilities in these areas including three sweet and eight sour plants.

A summary of the principal businesses and the assets of the Target Group is set out in the section headed ‘‘7. Information on the Target Group’’ of this circular.

1.4. Consideration

The total consideration for the Partnership Interests shall be the amount calculated as follows:

(a) C$722,000,000 (equivalent to approximately HK$4,176,336,800) (the ‘‘Base Purchase Price’’); plus

– 14 –

LETTER FROM THE BOARD

(b) the aggregate amount of any capital contributions made by the Vendors to the Target Company after the Effective Time, but prior to the Closing Date, which as of December 31, 2016 was C$0; minus
(c) the aggregate amount of any Distributions made to Vendors by the Target Company after the Effective Time but prior to the date of PSA (other than the pro forma cash distribution and the Suncor FSOA Distribution), which as of March 31, 2017 was C$36,640,000 (equivalent to approximately HK$211,940,416) in the aggregate, and any Distribution made in accordance with the PSA if applicable; plus
(d) C$14,000,000 (equivalent to approximately HK$80,981,600), which reflects certain adjustments for the taxable income of the Target Company and CQR Partnership in the 2016 fiscal year and other related items for tax purposes.

The capital contributions in item (b) above will only be made under special circumstances. Up to the Latest Practicable Date, the amount of capital contribution was nil. In addition, in accordance with the PSA, C$50,000,000 (equivalent to approximately HK$289,220,000) promissory notes issued by the Target Company in favour of the Vendors will be converted as capital of the Target Company prior to the closing of the Acquisition, without further adjustment to the Consideration.

The Consideration after adjustments in accordance with the PSA, i.e. C$699,360,000 (equivalent to approximately HK$4,045,377,984), will be funded through a combination of the Group’s internal resources, debt or equity financing and proceeds to be raised from the Convertible Preferred Shares issued by the Purchaser as follows:

(a) C$170,000,000 (equivalent to approximately HK$983,348,000) in Convertible Preferred Shares from Gastown;
(b) C$34,000,000 (equivalent to approximately HK$196,669,600) in Convertible Preferred Shares from Mercuria; and
(c) C$296,000,000 (equivalent to approximately HK$1,712,182,400) in Common Shares and C$10,000,000 (equivalent to approximately HK$57,844,000) in loan from the Group.

In addition, the Purchaser will draw up to C$190,000,000 (equivalent to approximately HK$1,099,036,000) from the Senior Secured Revolving Credit Facility to be provided by a syndicate of banks. The Senior Secured Revolving Credit Facility will rank senior to all securities of the Purchaser.

The Group will fund its subscription of Common Shares of the Purchaser and loan to the Purchaser through a combination of the Group’s internal resources, debt or equity financing. Apart from the financing facilities now available to the Group, the Group has also received a commitment from a subsidiary of China Huarong Asset Management Co., Ltd. to provide a US$100,000,000 committed term loan facility for the Acquisition.

– 15 –

LETTER FROM THE BOARD

1.5. Basis of Consideration

The Consideration was determined after arm’s length negotiations between the Purchaser and the Vendors after taking into consideration by the Company, among other things, the following factors, including without limitation, historical and future cash flows (EBITDA and netback) analysis, acreage (developed and undeveloped), proved developed producing reserves, proved reserves, proved plus probable reserves and the NPV of such reserves, value of the assets, production rate, the asset retirement obligations of the Acquired Entities and certain comparable transactions as set out in the table below. In view of the above, the Directors consider that the Consideration (including the applicable adjustments) is fair and reasonable and in the interests of the Company and the Shareholders as a whole.

Comparable Transactions

LTM Gas-Weighted Transactions (>C$10 MM)

Announcement Date 11-Jul-17 7-Jul-17 6-Jul-17 6-Jul-17 14-Jun-17 9-Jun-17 25-May-17 1-May-17 1-May-17 31-Mar-17 15-Mar-17 9-Mar-17 8-Feb-17 4-Jan-17 4-Jan-17 23-Dec-16 20-Oct-16 29-Sep-16 19-Aug-16 6-Jul-16 Average Median	Target Pengrowth Energy Questfire Energy Corp. Apache Corporation Trilogy Energy Corp. Bellatrix Exploration Ltd. Centrica Trilogy Energy Corp. Trilogy Energy Corp. Paramount Resources Undisclosed company(ies) UGR Blair Creek Ltd. Enerplus Undisclosed company(ies) Kelt Exploration Chinook Energy Undisclosed Shell Undisclosed company(ies) Marquee Energy Paramount Resources Ltd.	Acquiror Undisclosed company(ies) Manitok Energy Inc. Paramount Resources Ltd. Paramount Resources Ltd. Undisclosed company(ies) MIE Holdings Undisclosed company(ies) Undisclosed company(ies) Undisclosed company(ies) Clearview Resources Painted Pony Petroleum Undisclosed company(ies) Clearview Resources Undisclosed Undisclosed company(ies) Trident Exploration Tourmaline Oil Manitok Energy Inc. Alberta Oilsands Inc. Seven Generations Energy Ltd.	Transaction Value (C$MM) $300 $55 $495 $1,190 $35 $722 $60 $50 $150 $20 $277 $67 $11 $100 $11 $23 $1,369 $14 $130 $1,897	Deal Type Assets Corporate Corporate Corporate Asset Asset Asset Asset Asset Asset Asset Asset Asset Asset Asset Asset Asset Asset Corporate Asset	Gas Weighting (%) 55% 77% 74% 62% 70% 87% 68% 84% n.a. 67% 96% 66% 58% 50% 65% 96% 85% 66% 56% 51% 70% 67%	Transaction Metrics Production 2P Reserves (C$/boe/d) (C$/boe) $27,027 $0.73 $12,854 $1.92 $14,664 $2.15 $69,631 $10.60 $24,643 n.a. $12,945 $2.10 $93,750 n.a. $11,048 $11.36 $107,143 n.a. $17,946 $6.00 $32,541 $0.85 $9,219 n.a. $32,443 $10.55 $76,746 $7.87 $106,061 $47.06 $102,740 n.a. $55,091 $2.89 $7,714 $1.25 $37,946 $6.60 $63,233 $6.47 $42,430 $7.35 $27,027 $3.27	12-Month	Forward
						Production (C$/boe/d) $27,027 $12,854 $14,664 $69,631 $24,643 $12,945 $93,750 $11,048 $107,143 $17,946 $32,541 $9,219 $32,443 $76,746 $106,061 $102,740 $55,091 $7,714 $37,946 $63,233 $42,430 $27,027	NYMEX Gas (US$/ MMbtu) $3.05 $2.86 $2.89 $2.89 $2.93 $3.04 $3.28 $3.22 $3.22 $3.19 $2.98 $2.97 $3.13 $3.25 $3.25 $3.66 $3.14 $2.96 $2.58 $2.79 $3.01 $2.98	WTI (US$/bbl) $45.04 $44.23 $45.52 $45.52 $44.73 $45.83 $48.90 $48.84 $48.84 $50.60 $48.86 $49.28 $52.34 $53.26 $53.26 $53.02 $50.63 $47.83 $49.11 $47.43
								$48.61 $48.86

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LETTER FROM THE BOARD

1.6. Payment of the Deposit

On or prior to the Document Escrow Release Time, the Purchaser has paid a C$70,000,000 (equivalent to approximately HK$404,908,000) Deposit into an escrow account held by the Escrow Agent pursuant to the Escrow Agreement. The remaining balance of the Consideration, as adjusted in accordance with the PSA will be paid upon Closing.

If Closing does not occur due to: (i) the Purchaser Default; or (ii) the Shareholders’ Approvals (as defined below) or the Stock Exchange’s Approval (as defined below) required under the PSA not being obtained or maintained, in each case prior to the Closing Date, the PSA shall be terminated and the Deposit plus any interest earned thereon shall, subject to the final resolution of any dispute with respect to a purported Purchaser Default (if applicable), be paid by the Escrow Agent to Vendors in accordance with the terms of the Escrow Agreement and shall be retained by Vendors as liquidated damages, to compensate Vendors for expenses incurred in connection with the Acquisition and the delay or permanent impairment caused to Vendors’ efforts to sell the Partnership Interests. The forfeiture of the Deposit will be borne by the Group.

If the Investment Canada Act Clearance has not been obtained prior to the Outside Date or, if it has been obtained prior to the Outside Date, is not in force at the Closing Time and the PSA has been terminated by the Vendors or the Purchaser, as the case may be, pursuant to the PSA, and:

(i) if the Purchaser complied with its obligations under the PSA, then 50% of the Deposit plus any interest earned thereon shall be paid by the Escrow Agent to the Purchaser and the other 50% of the Deposit plus any interest earned thereon shall be paid by the Escrow Agent to the Vendors, in each case in accordance with the terms of the Escrow Agreement and such amount paid to the Vendors shall be retained by the Vendors as liquidated damages, to compensate the Vendors for expenses incurred in connection with the Acquisition and the delay or permanent impairment caused to the Vendors’ efforts to sell the Partnership Interests;
(ii) if the Purchaser failed to comply with its obligations under the PSA, then the Deposit plus any interest earned thereon shall be paid by the Escrow Agent to the Vendors in accordance with the terms of the Escrow Agreement and shall be retained by the Vendors as liquidated damages, to compensate the Vendors for expenses incurred in connection with the Acquisition and the delay or permanent impairment caused to the Vendors’ efforts to sell the Partnership Interests; or
(iii) if there is any amendment to the Investment Canada Act or its regulations which comes into effect during the Interim Period which prevents such Investment Canada Act Clearance from being granted to the Purchaser, then the Deposit plus any interest earned thereon shall be paid by the Escrow Agent to the Purchaser in accordance with the terms of the Escrow Agreement.

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LETTER FROM THE BOARD

Given that the Investment Canada Act Clearance hinges upon the Purchaser satisfying the Minister (within the meaning of the Investment Canada Act) that the Acquisition is likely to be of net benefit to Canada, the Purchaser considers that it is reasonable to compensate the Vendors for the expenses incurred in connection with the Acquisition and the delay or permanent impairment caused to the Vendors’ effort to sell the Partnership Interests if the Investment Canada Act Clearance can not be obtained in manner aforesaid.

If all of the Vendor’s Conditions as set out below are satisfied and Closing does not occur due to Vendors’ refusal to sell and transfer the Partnership Interests to the Purchaser and the PSA is terminated by Purchaser pursuant to the terms thereof, then the Vendors will pay (i) to the Purchaser a break fee of C$70,000,000.00 (equivalent to approximately HK$404,908,000) (the ‘‘Break Fee’’); and (ii) the Deposit plus any interest earned thereon shall be paid to Purchaser in accordance with the terms of the Escrow Agreement. The return of the Deposit and the payment of the Break Fee to Purchaser shall be considered as liquidated damages, to compensate Purchaser for expenses incurred in connection with the Acquisition and the delay or failure to complete the Acquisition.

If Closing does not occur for any reason other than due to the circumstances described above, and the PSA has been terminated pursuant to the terms thereof, the Deposit plus any interest earned thereon shall be paid to Purchaser in accordance with the terms of the Escrow Agreement and the Parties shall be released from all of their obligations under the PSA.

1.7. Conditions Precedent

Purchaser’s Conditions

The obligation of the Purchaser to purchase the Partnership Interests pursuant to the PSA is subject to the following conditions, which are for the exclusive benefit of the Purchaser and, save and except for the conditions (a) and (b) as set below, may be waived in whole or in part by the Purchaser by written notice to the Vendors:

(a) Competition Act Approval: The Competition Act Approval shall have been obtained, and as at the Closing Time is in force;
(b) Investment Canada Act Clearance: The Investment Canada Act Clearance shall have been obtained, and as at the Closing Time is in force;
(c) Representations and Warranties: the Vendors’ representations and warranties in the PSA shall be true in all material respects when made and as of the Closing Time (except for representations and warranties made as of a specified date, the accuracy of which shall be determined as of that specified date) provided, however, that the Purchaser shall not be entitled to terminate the PSA by reason of a Qualifying Misrepresentation being untrue (and this condition shall be deemed to be satisfied) unless the negative impact thereof, together with the negative impact of all other

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LETTER FROM THE BOARD

Qualifying Misrepresentations, on the aggregate value of the Partnership Interests and the Aggregate Tangible Repairs Cost (as defined below) exceeds, in aggregate, 5% of the Base Purchase Price;

(d) Compliance with Covenants: the Vendors shall have performed or complied in all material respects with all of their obligations, covenants and agreements contained in the PSA to be performed or complied with by the Vendors at or before Closing;
(e) Physical Damage to Tangibles: The cost to the Acquired Entities to repair any physical damage suffered by the Tangibles during the Interim Period, excluding ordinary course wear and tear and any physical damage that would be covered under a policy of insurance held by Vendors, the Acquired Entities or any of their Affiliates (the ‘‘Aggregate Tangibles Repair Cost’’), together with the negative impact of all Qualifying Misrepresentations on the aggregate value of the Partnership Interests, does not exceed 5% of the Base Purchase Price;
(f) No Action or Proceeding: At the Closing Time, no Claim shall be pending before any Government Authority (excluding Claims, if any, (i) involving a former co-investor or member of the Purchaser consortium or any of its Related Parties, (ii) involving the shareholders of Purchaser or the Company, or (iii) arising in connection with the Shareholders Approval of the Company, the Stock Exchange’s Listing Approvals or the Listing Rules) seeking to restrain or prohibit the Acquisition or to obtain material damages or other relief from Purchaser in connection with the consummation of the Acquisition; and
(g) MIE Shareholders’ Approval and Stock Exchange’s Approvals: the Company shall have received: (i) the approval of the Acquisition from the Shareholders at a general meeting of such Shareholders in accordance with the requirements of the Listing Rules (the ‘‘Shareholders’ Approval’’); and (ii) to the extent required, such consents, waivers, permissions and approvals in relation to the Acquisition from the Stock Exchange (the ‘‘Stock Exchange’s Approval’’); and as at the Closing Time the approvals stated in this sub-clause are in force.

The Purchaser and the Company acknowledge that the Shareholders’ Approval and the Stock Exchange’s Approval in the Purchaser’s condition (g) are not waivable. The Purchaser and the Company will comply with the requirements under the Listing Rules by obtaining the Shareholders’ Approval and the Stock Exchange’s Approval.

The Purchaser has submitted the applications for obtaining the Competition Act Approval and the Investment Canada Act Clearance. As at the Latest Practicable Date, the Purchaser has received the Competition Act Approval from the Government Authority. The Investment Canada Act Clearance is being processed and the Purchaser expects to receive such clearance in September 2017.

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LETTER FROM THE BOARD

Vendors’ Conditions

The obligation of Vendors to sell the Partnership Interests to Purchaser pursuant to the PSA is subject to the following conditions, which are for the exclusive benefit of Vendors and, save and except for the conditions (a) and (b) as set below, may be waived in whole or in part by Vendors by written notice to Purchaser:

(a) Competition Act Approval: The Competition Act Approval shall have been obtained, and as at the Closing Time is in force;
(b) Investment Canada Act Clearance: The Investment Canada Act Clearance shall have been obtained, and as at the Closing Time is in force;
(c) Representations and Warranties: The representations and warranties of Purchaser in the PSA shall be true in all material respects when made and as of the Closing Time;
(d) Compliance with Covenants: Purchaser shall have performed or complied in all material respects with all of its obligations, covenants and agreements contained in this Agreement to be performed or complied with by Purchaser at or before Closing; and
(e) No Action or Proceeding: At the Closing Time, no Claim shall be pending before any Government Authority seeking to restrain or prohibit the Acquisition or to obtain material damages or other relief from Vendors in connection with the consummation of the Acquisition.

As at the Latest Practicable Date, none of the conditions that require further action to be taken by the Purchaser and/or the Vendor has been fulfilled.

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LETTER FROM THE BOARD

1.8. Closing

Closing will take place at the Closing Time provided all the Conditions Precedent to the PSA have been satisfied (or, if applicable, waived by the parties to the PSA). As at the Latest Practicable Date, the Purchaser has received the Competition Act Approval from the Government Authority.

Upon Closing, the Target Group will be indirectly controlled by the Company and its financial information will be consolidated into the Group.

1.9. Termination

Either party may terminate the PSA by mutual written consent or if the Closing Date has not occurred by the Outside Date; provided that the right to terminate the PSA under the terms thereof shall not be available to a party whose failure to fulfill any obligation under the PSA has caused or resulted in the failure of the Closing Date to occur on or before the Outside Date.

If a condition in the Purchaser’s conditions or the Vendors’ conditions set out above has not been satisfied on or before the applicable date for satisfaction thereof and that condition has not been waived in writing, or deemed to be waived, by the party for whose benefit that condition has been included therein, that party may terminate the PSA by written notice to the other party, provided that, a party shall not be permitted to exercise or purport to exercise any right of termination if the event or circumstances giving rise to that right is due to a default by that party.

In the event of the termination of the PSA aforesaid, save for the defaults that occurred before the time at which that termination occurs where the defaulting party shall remain liable, the parties to the PSA shall be released from all of their further obligations under the PSA.

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LETTER FROM THE BOARD

2. THE SUBSCRIPTION AGREEMENT

2.1 Date

May 31, 2017

2.2 Parties

(i) the Purchaser
(ii) the Subscribers
(iii) the Company

To the best of the Directors’ knowledge, information and belief, having made all reasonable enquiries, each of Gastown and Mercuria Energy Netherlands and their respective ultimate beneficial owners are third parties independent of the Company and its Connected Persons.

2.3 Subject Matter

The Purchaser will issue (a) 170,000,000 Convertible Preferred Shares to Gastown at a price of C$1.00 per share for aggregate proceeds of C$170,000,000; (b) 34,000,000 Convertible Preferred Shares to Mercuria Energy Netherlands at a price of C$1.00 per share for aggregate proceeds of C$34,000,000; (c) 296,000,000 Common Shares to Maple Marathon at a price of C$1.00 per share for aggregate proceeds of C$296,000,000.

On the terms and subject to the conditions set out in the Subscription Agreement, the subscription of the relevant Convertible Preferred Shares by each of Gastown and Mercuria Energy Netherlands, and subscription of the Common Shares by Maple Marathon shall be irrevocable.

Closing of the subscription of the relevant Convertible Preferred Shares by each of Gastown and Mercuria Energy Netherlands will take place two Business Days prior to the Closing Date or such other date as the parties may agree. The subscription of the Common Shares by Maple Marathon will take place in two tranches, the first tranche, representing 70,000,000 Common Shares for an aggregate purchase price of C$70,000,000 shall be completed upon signing of the Subscription Agreement or as the parties may agree and the second tranche, representing 226,000,000 Common Shares for an aggregate purchase price of C$226,000,000 shall be completed on the Closing Date or as the parties may agree.

Maple Marathon shall fund its subscription under the Subscription Agreement through a combination of the Group’s internal resources, debt or equity financing.

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LETTER FROM THE BOARD

2.4 Conditions precedent to the Subscription

Closing of the Subscription shall be conditional upon:

(a) each sale of shares shall be exempt from the prospectus requirements of the Securities Act (Alberta) and the regulations, rules, policies and orders made thereunder and the securities legislation of any other jurisdiction applicable to the sale of the shares or upon the issuance of such rulings, orders, consents or approvals as may be required to permit the sale without the requirement of filing a prospectus;
(b) at or prior to the closing of the subscription by Gastown or Mercuria Energy Netherlands, (i) the articles of the Purchaser be amended to create the Convertible Preferred Shares in the capital of the Purchaser setting out the rights, privileges and restrictions as agreed between the parties and (ii) the shareholders agreement in the agreed form be entered into between the Purchaser, Gastown, Mercuria Energy Netherlands and Maple Marathon; and
(c) the PSA shall be in full force and effect and unamended (except for any amendments which have been consented to by Gastown, Mercuria Energy Netherlands and Maple Marathon).

Closing of the Acquisition and the Subscription is independent from and not conditional upon each other. The Purchaser shall use the proceeds from the Subscription to pay a portion of the Consideration pursuant to the PSA. Accordingly, if the Acquisition is not completed, the proceeds from the closing of the Subscription would need to be refunded to the Subscribers together with the payment of the Standby Fee (defined below) to Gastown. Both CCGRF and Mercuria have committed funding to satisfy their respective portion of subscription money during the period from the signing of the PSA to the Closing Date. As such, the Directors believe that it is not likely for CCGRF and Mercuria not to complete the Subscription according to the terms of the Subscription Agreement.

2.5 Special rights and restrictions attached to the Common Shares and Convertible Preferred Shares

The Common Shares shall have attached thereto the following special rights and restrictions:

(a) The holders of the Common Shares shall be entitled to one vote in respect of each Common Share held, at any annual or special general meeting of the shareholders of the Purchaser.
(b) The holders of the Common Shares shall, in the absolute discretion of the directors, be entitled to receive dividends, as and when declared by the directors, out of moneys of the Purchaser properly applicable to the payment of dividends in such amounts and payable in such manner as the board of directors of the Purchaser may from time to time determine.

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LETTER FROM THE BOARD

(c) In the event of the liquidation, dissolution or winding up of the Purchaser or other distribution of assets of the Purchaser among its shareholders for the purpose of winding up its affairs or upon a reduction of capital, after payment has been made to the holders of the Convertible Preferred Shares of the amount to which they are entitled, the holders of the Common Shares shall be entitled to share equally, share for share, in the remaining property and assets of the Purchaser.

The Convertible Preferred Shares shall confer on the holders thereof and shall be subject to the following rights, restrictions, privileges and conditions:

(a) The holders of the Convertible Preferred Shares shall be entitled to one vote in respect of each Convertible Preferred Share held, at any annual or special general meeting of the shareholders of the Purchaser.
(b) The holders of the Convertible Preferred Shares, in priority to the holders of the Common Shares and all other shares ranking junior to the Convertible Preferred Shares shall be entitled to receive and the Purchaser shall pay thereon, as and when declared by the board of directors of the Purchaser out of the assets of the Purchaser properly applicable to the payment of dividends, fixed preferential cumulative dividends of C$0.08 per share per annum. If on any dividend payment date the dividend payable on such date is not paid in full on all the Convertible Preferred Shares then issued and outstanding, the fixed preferential cumulative dividends payable on such Convertible Preferred Shares shall increase to C$0.16 per share per annum and such increased dividend, or the unpaid part thereof, shall be paid at a subsequent date or dates in priority to dividends on the Common shares and any other shares ranking junior to the Convertible Preferred Shares, and upon payment of such dividend the fixed preferential cumulative dividends payable on the Convertible Preferred shares shall again decrease to C$0.08 per share per annum.
(c) Except with the consent in writing of the holders of all the Convertible Preferred Shares outstanding, no dividend shall at any time be declared and paid on or set apart for payment on the Common Shares or on any other shares ranking junior to the Convertible Preferred Shares in any financial year unless and until the accrued preferential cumulative dividends on all the Convertible Preferred Shares outstanding have been declared and paid or set apart for payment.
(d) In the event that aggregate dividends are declared and paid on the Common Shares in an amount in excess of C$0.08 per Common Share per annum, the holders of the Convertible Preferred Shares shall be entitled to receive and the Purchaser shall pay thereon, as and when declared by the board of directors of the Purchaser out of the assets of the Purchaser properly applicable to the payment of dividends, a special dividend, in excess of the fixed preferential cumulative dividends hereinbefore provided, in an amount per Convertible Preferred share equal to the aggregate per share per annum dividends declared

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and paid to holders of Common Shares less the per share per annum fixed preferential cumulative dividends declared and paid to the holders of Convertible Preferred Shares hereinbefore provided.

(e) In the event of the liquidation, dissolution or winding up of the Purchaser or other distribution of assets of the Purchaser among its shareholders for the purpose of winding up its affairs, the holders of the Convertible Preferred Shares shall be entitled to receive for each such share held: (i) C$1.00 per share, plus (ii) all unpaid dividends which shall have accrued thereon, before any amount shall be paid or any property or assets of the Purchaser distributed to the holders of the Common Shares or shares ranking junior to the Convertible Preferred Shares and upon payment of the amount so payable to them, the Convertible Preferred Shares shall not be entitled to share in any further distribution of the property or assets of the Purchaser.
(f) Subject to the right of a holder to convert its Convertible Preferred Shares into Common Shares, from the first date of issue of the Convertible Preferred Shares to the date that is four years from the first date of issue of the Convertible Preferred Shares, the Purchaser may upon giving notice, redeem at any time the whole or from time to time any part of the then outstanding Convertible Preferred shares on payment of (i) C$1.00 for each Convertible Preferred Share to be redeemed, plus (ii) all unpaid dividends which shall have accrued thereon, plus (iii) an amount equal to the amount of dividends that would have accrued on such Convertible Preferred Share from the date on which redemption is to take place of such Convertible Preferred Share to the date that is five years from the first date of issue of such Convertible Preferred share at a rate of C$0.04 per share per annum (the whole constituting and being referred to herein as the ‘‘Redemption Amount’’).
(g) Irrespective of whether the event of closing of the Acquisition is completed or not completed, Gastown will be entitled to receive a one-time standby fee in the amount of 4.0% of its C$170,000,000 (equivalent to approximately HK$983,348,000), i.e. C$6,800,000 (equivalent to approximately HK$39,333,920) investment amount (‘‘Standby Fee’’). In the event that the closing of the Acquisition is completed, the Standby Fee will be paid to Gastown on October 1, 2018 together with the first dividend payment. In the event that the closing of the Acquisition is not completed, the Standby Fee will be paid to Gastown by no later than December 31, 2017.
(h) Each issued Convertible Preferred share may at any time prior to a Redemption Date be converted, at the option of the holder, into 0.83 Common Shares.
(i) All Common Shares resulting from any conversion of issued and fully paid Convertible Preferred Shares into Common Shares shall be deemed to be fully paid and non-assessable.

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LETTER FROM THE BOARD

(j) None of the Common Shares or the Convertible Preferred Shares shall be subdivided, consolidated, reclassified or otherwise changed unless contemporaneously therewith the other said class of shares is sub-divided, consolidated, reclassified or otherwise changed in the same proportion and in the same manner.
(k) In the event that the Purchaser sells or disposes (a ‘‘Disposition’’) of any of its assets or property, other than (i) sales or dispositions of inventory or worn out, obsolete or surplus equipment in the ordinary course of business, (ii) sales, dispositions, non-renewals and exchange of properties in the ordinary course of business, (iii) sales or dispositions between subsidiaries of the Purchaser or between the Purchaser and its subsidiaries, or (iv) sales or dispositions with the consent in writing of the holders of all Convertible Preferred Shares outstanding, it shall, as soon as practicable, by notice in writing (a ‘‘Disposition Notice’’), advise the holders of Convertible Preferred Shares of such Disposition and the amount of proceeds (the ‘‘Net Proceeds’’) in cash, cheques or other cash equivalent financial instruments received by the Purchaser from such Disposition, net of: (A) the direct costs relating to such Disposition, (B) sale, use or other transaction taxes paid or payable as a result thereof including income taxes, (C) amounts required to be applied to repay principal, interest and prepayment premiums and penalties on any indebtedness secured by an encumbrance on the property which is the subject of such Disposition, and (D) amounts required to be paid to the Purchaser’s lenders pursuant to its Senior Secured Revolving Credit Facility in respect of such Disposition. Following receipt of a Disposition Notice, a holder of Convertible Preferred Shares shall be entitled to require the Purchaser to redeem all or any of the Convertible Preferred Shares held by such holder from the Net Proceeds of the Disposition by tendering to the Purchaser at its registered office within 30 days following receipt of a Disposition Notice a share certificate or certificates representing the Convertible Preferred Shares which the holder desires to have the Purchaser redeem together with a request (a ‘‘Retraction Request’’) in writing specifying (i) that the holder desires to have the shares represented by such certificate or certificates redeemed by the Purchaser and, if part only of the shares represented by such certificate or certificates is to be redeemed, the number thereof so to be redeemed and (ii) the business day (herein referred to as the ‘‘Retraction Date’’) on which the holder desires to have the Purchaser redeem such Convertible Preferred Shares. The Retraction Date shall be not less than 30 days (or such shorter period to which the Purchaser may consent) after the day on which the request in writing is given to the Purchaser. Upon receipt of a share certificate or certificates representing the Convertible Preferred Shares which the holder desires to have the Purchaser redeem together with such a request the Purchaser shall on the Retraction Date redeem such Convertible Preferred Shares by paying to such holder (i) C$1.00 for each such Convertible Preferred Share being redeemed, plus (ii) all unpaid dividends which have accrued thereon (the whole constituting and being herein referred to as the ‘‘Retraction Amount’’). Notwithstanding the foregoing, in respect of a Retraction Request or Retraction Requests for a particular

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LETTER FROM THE BOARD

Disposition, in no event shall the Purchaser be required to pay an aggregate Retraction Amount to holders of Convertible Preferred shares in excess of the Net Proceeds of such Disposition.

The Standby Fee represents compensation to CCGRF for their committed funding under the terms of the Subscription Agreement during the period from the signing of the PSA to the Closing Date. As such, the Directors are of the view that the payment of the Standby Fee (irrespective of whether the Acquisition will be completed) is fair and reasonable and is in the interests to the Company and its shareholders as a whole.

3. INFORMATION ON THE GROUP

The Group is principally engaged in the exploration, development, production and sale of oil and other petroleum products in the People’s Republic of China (the ‘‘PRC’’) under production sharing contracts (‘‘PSC’’) and other similar arrangements. The Group currently has two producing oil PSCs in the PRC, an exploration contract and a working interest in the Niobrara shale oil and gas assets in the United States of America (the ‘‘USA’’). The Group also participates as associates in the exploration, development and production of petroleum assets located in the Republic of Kazakhstan (the ‘‘Kazakhstan’’), western Canada and the northern part of the South China Sea in the PRC.

4. INFORMATION OF THE VENDORS

The Vendors are:

(a) DERP, a partnership having an office and carrying on business in the City of Calgary, in the Province of Alberta. Its principal business is oil and gas exploration and development. DERP is an indirect subsidiary of Centrica plc. Centrica plc is an energy and service company and the shares of which are listed and traded on the London Stock Exchange. It is primarily engaged in the supply of gas and electricity to residential and business customers in the United Kingdom, the Republic of Ireland and North America; and
(b) A Partner, a body corporate incorporated under the laws of British Columbia. It is a government owned entity in the Middle East and the principal business of which is oil and gas exploration and development.

5. INFORMATION ON THE SUBSCRIBERS

The Subscribers are collectively:

(a) Gastown, a wholly-owned subsidiary of CCGRF established for the sole purpose to invest CCGRF’s capital into the Convertible Preferred Shares. Its principal business is investment holding;
(b) Maple Marathon, a corporation incorporated in Hong Kong and a wholly-owned subsidiary of the Company;

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(c) Mercuria Energy Netherlands, a wholly-owned subsidiary of Mercuria based in Utrecht, Netherland. It focuses on logistics, support of the Mercuria group, risk management and operations coordination.

CCGRF is a private equity fund focused on the natural resource sectors in North America. CCGRF is a limited partnership existing under the laws of the Cayman Islands. It is solely managed by MEC Advisory Limited.

Mercuria is a privately held Swiss-based international commodity trading company and is one of the world’s largest independent energy and commodity trading groups. Mercuria is primarily focused on energy, and its activities range from sourcing, supplying, trading, and financing to investment, logistics storage and blending.

6. INFORMATION ON THE PURCHASER

The Purchaser is a company incorporated in British Columbia, Canada and, as at the Latest Practicable Date, a wholly-owned subsidiary of the Group. Its principal business is investment holding.

6.1 Shareholding Structure of the Purchaser

Upon full Conversion of the Convertible Preferred Shares at the Conversion Ratio, a total of 169,320,000 Common Shares will be issued, representing approximately 36.4% of the issued share capital of the Common Shares of the Purchaser as enlarged by the issue of the Common Shares. Upon full Conversion, the Purchaser will remain to be a subsidiary of the Company, but Company’s interest in the issued share capital of the Common Shares of the Purchaser will be reduced to approximately 63.6%.

The following table sets out the shareholding structure of the Purchaser (i) as at the date of this circular; (ii) immediately upon the issue of the Convertible Preferred Shares; (iii) immediately upon the issue of the second tranche of Common Shares to Maple Marathon; and (iv) immediately upon full Conversion of the Convertible Preferred Shares, assuming that there is no other change in the issued shares of the Purchaser from the date of this circular (for illustration purposes only).

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LETTER FROM THE BOARD

Shareholders of the Purchaser Maple Marathon Gastown Mercuria Energy Netherlands Total Shareholders of the Purchaser Maple Marathon Gastown Mercuria Energy Netherlands Total Shareholders of the Purchaser Maple Marathon Gastown Mercuria Energy Netherlands Total	As at the Latest Practicable Date Number of Common Shares Number of Convertible Preferred Shares Approx. % of the total issued Common Shares 70,000,100 — 100 — — — — — — 70,000,100 — 100 Immediately after the issue of the second tranche of the Common Shares to Maple Marathon on Closing Date Number of Common Shares Number of Convertible Preferred Shares Approx. % of the total Issued Common Shares 296,000,100 — 100 — 170,000,000 — — 34,000,000 — 296,000,100 204,000,000 100 Immediately upon completion of full Conversion (convertible into Common Shares on the basis of 0.83 Common Shares for every one Convertible Preferred Share) Number of Common Shares Number of Convertible Preferred Shares Approx. % of the total Issued Common Shares 296,000,100 — 63.6 141,100,000 — 30.3 28,220,000 — 6.1 465,320,100 — 100	As at the Latest Practicable Date Number of Common Shares Number of Convertible Preferred Shares Approx. % of the total issued Common Shares 70,000,100 — 100 — — — — — — 70,000,100 — 100 Immediately after the issue of the second tranche of the Common Shares to Maple Marathon on Closing Date Number of Common Shares Number of Convertible Preferred Shares Approx. % of the total Issued Common Shares 296,000,100 — 100 — 170,000,000 — — 34,000,000 — 296,000,100 204,000,000 100 Immediately upon completion of full Conversion (convertible into Common Shares on the basis of 0.83 Common Shares for every one Convertible Preferred Share) Number of Common Shares Number of Convertible Preferred Shares Approx. % of the total Issued Common Shares 296,000,100 — 63.6 141,100,000 — 30.3 28,220,000 — 6.1 465,320,100 — 100
		100

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LETTER FROM THE BOARD

6.2 Board of Directors of the Purchaser

Immediately after Closing until the date Gastown completes the conversion of all of its Convertible Preferred Shares into Common Shares (the ‘‘Conversion Date’’) the board of directors of the Purchaser shall consist of up to five (5) directors, to be nominated in manner set out below. From the Conversion Date, the board of directors of the Purchaser shall consist of up to seven (7) directors, to be nominated in manner set out below.

For so long as the Company holds, or is deemed to hold, the requisite number of shares, the Company shall nominate directors of the Purchaser as follows:

(i) four (4) nominees designated by the Company will be directors immediately after Closing until the Conversion Date or five (5) nominees designated by the Company will be directors from the Conversion Date, if and only for so long as the Company holds at least 50% of the issued shares in the Purchaser;
(ii) three (3) nominees designated by the Company will be directors immediately after Closing until the Conversion Date or four (4) nominees designated by the Company will be directors from the Conversion Date, if and only for so long as the Company holds at least 40% and less than 50% of the issued shares in the Purchaser;
(iii) two (2) nominees designated by the Company will be directors immediately after Closing until the Conversion Date or two (2) nominees designated by the Company will be directors from the Conversion Date, if and only for so long as the Company holds at least 30% and less than 40% of the issued shares in the Purchaser;
(iv) one (1) nominee designated by the Company will be a director immediately after Closing until the Conversion Date or one (1) nominees designated by the Company will be directors from the Conversion Date, if and only for so long as the Company holds at least 20% and less than 30% of the issued shares in the Purchaser;

provided that, after Closing Date and for so long as the Company nominates more than one (1) director, the Company shall nominate the CEO to act as one of its nominee directors. In the event that the Company ceases to hold the requisite number of shares to nominate a director or directors, the Company’s excess nominee director(s) shall forthwith resign. No nominee designated by the Company will be a director, if and only for so long as the Company holds less than 20% of the issued shares in the Purchaser.

Immediately after Closing until the Conversion Date and for so long as Gastown holds at least 20% of the issued shares in the Purchaser, Gastown shall nominate one (1) director and shall be entitled to appoint one (1) non-voting observer to attend all meeting of the board of directors. From the Conversion Date and for so long as Gastown holds at least 20% of the issued shares in the Purchaser, Gastown shall nominate two (2) directors.

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LETTER FROM THE BOARD

In the event that Gastown ceases to hold the requisite number of shares, Gastown’s nominee director(s) shall forthwith resign.

7. INFORMATION ON THE TARGET GROUP

7.1 Target Company and its subsidiaries

The Target Company’s principal business is to explore and develop oil and natural gas resources and supply crude oil and natural gas to the North America markets. Its business model is to produce crude oil and natural gas at as low as possible cost, and supply North America markets efficiently (meaning lower transportation and marketing fees) and capture the margin between the market prices and their cost basis. The Target Company’s principal oil and natural gas producing properties are located in British Columbia, Alberta and Saskatchewan.

The shareholding structure of the Target Group immediately after Closing is set out below:

==> picture [299 x 378] intentionally omitted <==

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

The Company
100%
Maple Marathon
100% (Note 1)
Purchaser
100%
100%
Target Company [(Note 2)]
8401268 Canada Inc.
99.99%
43% 0.01%
CQ Energy Canada
Resources Partnership
509760 Alberta Inc.
----- End of picture text -----

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LETTER FROM THE BOARD

Notes:

(1) Upon full Conversion of the Convertible Preferred Shares into Common Shares, the Purchaser will be owned as to 63.6% thereof by Maple Marathon, as to 30.3% thereof by Gastown and as to the remaining 6.1% thereof by Mercuria energy Netherlands, respectively.
(2) It is expected that the partnership will collapse and the Target will be converted into a single entity immediately prior to Closing.

7.2 Information on the production and reserves of the Target Group

The Target Company’s key oil and gas asset are oil and gas bearing rocks (reservoirs) buried 300–5,000 meters below the surface. The reservoirs can be mapped using geophysical methods as well as drilling and logging of vertical wells. Most reservoir can be developed using horizontal drilling and completion technology. The assets can be divided into 5 geographical regions: Peace River Arch (‘‘PRA’’), North, Hanlan Robb, Foothills, South as well as Royalty and Fee Lands. In PRA, the key assets are (a) a gas charged reservoir called Montney which is a liquid rich gas assets situated in the Montney Formation which is capable of liquids rich gas production primarily in the Glacier and Parkland areas; (b) Spirit River area, which is characterized by light oil production from the Charlie Lake formation. In North, the key assets are light oil and liquid bearing zones such as Belly River, Cardium, Charlie Lake, Gething and Glauconite in Gilby, Carrot Creek and Ferrier. In Hanlan Robb, the company currently produces low decline sour gas from Turner Valley formation and sweet gas production from the Spirit River Group which consists of 3 stacked formations, the Notikewin, the Falher, and the Wilrich. In Foothills, the key asset is Wildcat Hills with sour gas production, also from Turner Valley formation. In South, the company is producing shallow gas.

Oil and gas assets are often owned by more than one company in energy business, the level of ownership is defined as working interest. High working interest means the level of interest in certain oil and gas assets is higher than 50%. As of June 6, 2017, the Target Company’s working interest in PRA, North, Hanlan Robb, Foothills, South are 70%, 72%, 52%, 67% and 77% respectively.

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LETTER FROM THE BOARD

The Target Company has ownership in 11 major facilities, including 3 sweet and 8 sour plants, which are more particularly set out in the table below:

										CQ WI%
									Licensed	Licensed
				Fluid	Op/Non-	Facility	Operational		gas	gas
CGU	Area	Facility name	Location	type	op	type	status	WI %	(MMscf/d)	(MMscf/d)
Foothills	Wildcat	Wildcat Hills	06–16–026–05W5	Sour	Op	gas plant	Active	100.0%	125.0	125.0
		Gas Plant
North	Carrot	Carrot Crk	10–16–053–13W5	Sweet	Op	gas plant	Active	100.0%	40.0	40.0
	Creek	10–16 Gas
		Plant
Hanlan	Hanlan	Hanlan Sour	15–02–049–20W5	Sour	Op	gas plant	Active	49.6%	371.2	184.1
		Gas Plant
Hanlan	Hanlan	Hanlan Sweet	15–02–049–20W5	Sweet	Op	gas plant	Active	39.1%	40.0	15.6
		Gas Plant
Hanlan	Hanlan	Husky Strachan	04–02–037–10W5	Sour	Non-op	gas plant	Active	5.1%	532.4	27.2
		(Ram) 4–2
North	Ferrier	Ferrier Gas	01–06–041–07W5	Sweet	Op	gas plant	Active	100.0%	119.9	119.9
		Plant
North	Gilby	Gilby Gas Plant	02–27–040–03W5	Sour	Op	gas plant	Active	100.0%	52.0	52.0
North	Wilson Ck	Keyera	10–05–046–06W5	Sour	Non-op	gas plant	Active	9.55%	159.5	15.2
		Minnehik-
		Buck Lk
PRA	Glacier	Progress 7–22	07–22–078–09W6	Sour	Non-op	gas plant	Active	38.0%	42.5	16.2
		Gas Plant
PRA	Boundary	Boundary Lake	14–24–084–15W6	Sour	Op	gas plant	Active	50.0%	60.0	30.0
		sour
PRA	Parkland	Parkland P2	06–29–081–15W6	Sour	Op	gas plant	Active	35.2%	12.0	4.2

These plants are gas processing plants. Their function is to clean raw natural gas produced by separating impurities and various non-methane hydrocarbons and fluids to produce what is known as pipeline quality dry natural gas. The Target Company’s gas plants process the raw natural gas produced in the nearby area by the company. These gas plants may also process raw natural gas produced by other producers in the area so as to generate third party processing revenue.

In addition to the facilities (plants), the midstream infrastructure referred to also include compressors and gathering pipeline. The function of the pipeline is mainly to gather the raw natural gas produced in an area and ship the gas to the processing plan for treatment. The function of the compressors is to pressurise processed quality dry natural gas so that it meet the pressure requirement of the main gas pipeline transportation.

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LETTER FROM THE BOARD

The following table set out the reserves by areas and average working interest calculation:

		Hanlan
	PRA	Robb	Foothills	North	South	Total
2P Reserve (bcfe)	574	408	478	339	279	2,078
AverageW.I.	70%	52%	67%	72%	77%	67%

The Company plans to acquire all the assets and facilities currently owned by the Target Company for the operation of its business under the Acquisition.

To the best knowledge of the Company after reviewing the documents provided by the Vendors, the Target Company has acquired all necessary rights, permits, licences, leases and contracts which are required for operation of its oil and gas reserves, which will remain valid so long as the land is being used for production of oil or gas with an active working programme.

Production by Region (average for 2016) Peace River Arch North South Hanlan Robb Foothills Total	Oil and natural gas liquids (Bbl/d) 1,047 3,705 191 398 373 5,714	Gas (MMcf/d) 48.04 50.63 57.88 61.77 83.82 302.14	Total (boe/d) 9,053 12,143 9,838 10,693 14,343
			56,070

For details of the production and reserves of the Target Group, please refer to the Competent Person’s Report set out in Appendix V to this circular. The Company confirmed that, to the best of its information and belief, as of the Latest Practicable Date, no material changes on the production and reserves of the Target Group have occurred since the effective date of the Competent Person’s Report.

The Competent Person’s Report set out in Appendix V to this circular also contained the valuation report prepared by DeGolyer and MacNaughton. It is the oil & gas industry’s common practice to engage an independent consulting firm to prepare/evaluate the oil & gas reserve/resources (including both of the reserves/resources amounts and accordingly the economic valuation of these reserves/resources). DeGolyer and MacNaughton is a world famous and tier one petroleum consulting company focused on oil & gas reserves/resources evaluation and DeGolyer and MacNaughton represents many Oil & Gas companies listed in the US, the United Kingdom and Hong Kong. Considering the credentials of DeGolyer and MacNaughton, the Directors of the Company believe that the reports presented an independent and fair valuation of the Target Group’s assets.

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LETTER FROM THE BOARD

7.3 Financial Information of the Target Group

Set out below is the financial information of the Target Group extracted from the Accountant’s Report (which is prepared on basis of IFRS as adjusted for the Purchaser’s accounting policies) set out in Appendix II to this circular for the year ended December 31, 2015 and the year ended December 31, 2016 and the first three months ended March 31, 2017 prepared in accordance with IFRS:

	For the first	For the	For the
	three months	year ended	year ended
	ended	December 31,	December 31,
	March 31, 2017	2016	2015
(C$’000)
Revenue	113,710	334,161	478,343
Royalties	(10,410)	(19,492)	(23,339)
Expenses	(230,909)	(337,836)	(1,160,593)
Net loss	(127,609)	(23,167)	(705,589)

The net loss amounting to C$705.6 million recorded by the Target Group for 2015 was mainly due to non-cash items. Due to the declining commodity price environment in 2015, the Target Group wrote off C$558.7 million in relation to impairment of property, plant and equipment and goodwill. Additionally, significant capital expenditure was invested by the Vendors, resulting in depreciation and amortisation of approximately C$228.1 million.

Balance Sheet

	As at	at December	at December
	March 31, 2017	31, 2016	31, 2015
(C$’000)
Current Assets	119,636	109,012	137,857
Non-current Assets	1,234,720	1,348,967	1,468,716
Total Assets	1,354,356	1,457,979	1,606,573
Current Liabilities	175,471	127,894	191,091
Non-current Liabilities	533,885	551,466	558,696
Partners’ Equity	645,000	778,619	856,786

As at March 31, 2017, the book value of the Target Group amounted to approximately C$645.0 million.

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LETTER FROM THE BOARD

Cash flow Statement

	For the first	For the	For the
	three months	year ended	year ended
	ended	December 31,	December 31,
	March 31, 2017	2016	2015
(C$’000)
Cash flow from operating activities	56,686	95,589	113,073
Cash flow used in investing
activities	(16,444)	(35,432)	(144,089)
Cash flow (used in)/from financing
activities	(20,816)	(74,000)	19,000
Change in cash and cash
equivalents	19,426	(13,843)	(12,016)

7.4 Litigation

As at the Latest Practicable Date, to the best knowledge of the Company, there are no legal claims or proceedings that may have an influence on the exploration or production rights of the Target Group.

8. REASONS FOR AND THE BENEFITS OF THE ACQUISITION

As part of its strategy of rebuilding its asset portfolio and creating value for its investors, the Group constantly evaluates investment opportunities globally and is particularly drawn by Canada’s vast oil and natural gas resources with an established energy sector in OECD jurisdiction.

The Group will not acquire the Excluded Assets or the DEML Downstream Business. Excluded Assets are owned by the Vendors or their Affiliates or any of their predecessors which are not required to conduct the business of the Target Group.

The Directors (including the independent non-executive Directors) believe that the Target Group possesses natural gas resources producing low decline, long life asset base products and infrastructure. It has vast acreage of undeveloped land and has potential for growth. Furthermore, the Target Group’s prolific assets have been able to generate positive EBITDA/ netback under current oil and gas prices and the Target Group has the ability to self-finance its future capital expenditure via its own cash flows and financing capabilities. The acquisition will also allow the Group to widen its global footprint and develop a more balanced oil and gas business portfolio, expand its operational capabilities and elevate its profile and image as an international energy company. Upon Closing and consolidation of the Target Group as a controlled company of the Group, it is believed that the Acquisition will enhance the Group’s financial performances and balance sheet.

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LETTER FROM THE BOARD

As the Target Group is able to generate positive operating cash flow for the past years, the Company does not expect to inject additional capital into the Target Group. Moreover, given the size of the reserve, production, revenue and operating cash flow of the Target Group, it may obtain funding from banks directly if additional working capital is needed.

Currently, DEML is the purchaser of nearly all of the Target Group’s production. DEML then sells these outputs into the open market in Canada at the western Canadian trading hubs of Aeco/Station 2. The Target Company is in discussions with Mercuria, one of the consortium members and an experienced Canadian oil and gas marketer, to assume the role of DEML to facilitate the sale of the outputs of the Target Group following completion of the Acquisition.

The exclusion of the Excluded Assets will not impact the current business model of the Target Group. The Consideration (subject to adjustment) was based on the ability of the Purchaser to acquire the production, resource and infrastructure portfolio located throughout the Western Canadian Sedimentary Basin and Williston basins in Alberta, Saskatchewan, Manitoba, Ontario and British Columbia in Canada. In addition, given that the Canadian oil and gas market is highly liquid, the assumption of the role previously undertaken by DEML by other oil and gas marketer will not materially affect the distribution of the output of the Target Group after completion of the Acquisition.

Based on the Base Purchase Price of approximately C$722,000,000 (equivalent to approximately HK$4,176,336,800), the Acquisition represents multiples of C$2.1/boe (EV/2P), being the Consideration divided by the total proved and probable reserves of the Target Company and C$12,944.9/boe/d (EV/Production), being the Consideration divided by the total daily production of the Target Group.

In view of the above and based on the fact that the Consideration has already excluded the Excluded Assets and the DEML Downstream Business, the Directors (including the independent non-executive Directors) are of the view that the terms of the PSA and the Transactions contemplated thereunder are fair and reasonable and are in the interest of the Company and the Shareholders as a whole.

9. FINANCIAL EFFECTS OF THE ACQUISITION

After Closing, the Target Group will be indirectly wholly controlled by the Company and its financial information will be consolidated into the Group. Upon completion of the Subscription but before conversion of the Convertible Preferred Shares, the Target Company is indirectly wholly controlled by the Company. Upon completion of the Subscription and after conversion of the Convertible Preferred Shares, the Company’s indirect interest in the issued share capital of the Common Shares of the Purchaser will be reduced to 63.6%. In both cases mentioned above, the results of the Target Group will be consolidated into the Company’s financial statements. The unaudited pro forma information of the Enlarged Group is set out in Appendix III to this circular.

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LETTER FROM THE BOARD

10. WAIVER FROM STRICT COMPLIANCE WITH RULE 4.03 OF THE LISTING RULES

Pursuant to Rule 4.03 of the Listing Rules, the accountant’s report of the Target Company which is required to be included in this circular must be prepared by certified public accountants who are qualified under the Professional Accountants Ordinance. Rule 4.03 of the Listing Rules also provides that, in the case of a circular issued by a listed issuer in connection with acquisition of an overseas company, the Stock Exchange may be prepared to permit the accountants’ report to be prepared by a firm of practicing accountants which is not so qualified but which is acceptable to the Stock Exchange. Such a firm must normally have an international name and reputation and be a member of a recognized body of accountants.

Given their geographical proximity and familiarity with the operating business of the Target, the Directors are of the view that it is more appropriate to appoint PricewaterhouseCoopers LLP, Canada (‘‘PwC Canada’’) instead of professional accountants who are qualified under the Professional Accountants Ordinance as reporting accountants for the purpose of issuing the accountants’ report of the Target Company to be included in this circular. It would be unduly burdensome to engage another certified public accountant who is qualified under the Hong Kong Professional Accountants Ordinance as reporting accountant as such a firm would require significant additional time to familiarise themselves with the business, financial reporting systems, and policies and procedures of the Target Group. Such appointment would likely result in an increase in cost and a delay to the timetable for preparation and despatch of the circular. Such appointment would therefore be unlikely to be in the best interests of the Company’s shareholders. PwC Canada is a member firm of PricewaterhouseCoopers International Limited and is a member of Chartered Professional Accountants Canada, which is a full member of the International Federation of Accountants. The Company has therefore applied to the Stock Exchange for a waiver from strict compliance with Rule 4.03 of the Listing Rules to allow PwC Canada to act as the reporting accountant for the accountants’ report of the Target Company for the inclusion in this circular. Such waiver was granted by the Stock Exchange on June 30, 2017 and the relevant accountant’s report is set in Appendix II of this circular.

The Company has requested PricewaterhouseCoopers Certified Public Accountants, Hong Kong (‘‘PwC Hong Kong’’) to assist PwC Canada in performing its duties as reporting accountant of the Target Group. PwC Hong Kong has been advising PwC Canada regarding the accounting-related requirements under the Listing Rules.

11. THE LISTING RULES IMPLICATIONS

As certain applicable percentage ratios (as defined in Rule 14.07 of the Listing Rules) in respect of the Acquisition contemplated under the PSA exceed 100%, the Acquisition constitutes a very substantial acquisition for the Company under Chapter 14 of the Listing Rules and therefore the Acquisition is subject to reporting, announcement and Shareholders’ approval requirements.

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LETTER FROM THE BOARD

The issue of Conversion Shares to the Subscribers upon Conversion will be deemed to be a disposal of interest in the Purchaser by the Company under the Listing Rules. As one or more of the applicable percentage ratios (as defined in Rule 14.07 of the Listing Rules) in respect of the Deemed Disposal exceed 25% but are less than 75%, the Subscription constitutes a major disposal for the Company under the Listing Rules and therefore the Company is subject to reporting, announcement and Shareholders’ approval requirements.

To the best knowledge, information and belief of the Directors, having made all reasonable enquiries, no Shareholder has a material interest in the PSA, the Subscription Agreement and the transactions contemplated thereunder and no Shareholder is required to abstain from voting to approve the PSA, the Subscription Agreement and the transactions contemplated thereunder at the EGM.

To the best of the Directors’ knowledge, information and belief and having made all reasonable enquiries, there is (i) no voting trust or other agreement or arrangement or understanding entered into by or binding upon Shareholders; and (ii) no obligation or entitlement of any Shareholder as at the Latest Practicable Date, whereby they have or may have temporarily or permanently passed control over the exercise of the voting right in respect of their shares in the Company to a third party, either generally or on a case-by-case basis.

12. RECOMMENDATIONS

The Directors (including the independent non-executive Directors) are of the view that the terms of the PSA and the Subscription Agreement are fair and reasonable and the proposed transactions therein are in the interests of the Company and the Shareholders as a whole. Accordingly, the Directors (including the independent non-executive Directors) recommend the Shareholders vote in favour of the ordinary resolution proposed at the EGM to approve the terms of the PSA, the Subscription Agreement and the transactions contemplated therein.

13. ADDITIONAL INFORMATION

As Closing is subject to the fulfilment of a number of conditions precedent which are detailed in this circular, the Acquisition may or may not be completed. Shareholders and potential investors should exercise caution when dealing in the Shares.

Your attention is drawn to the additional information set out in appendices to this circular.

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

– 39 –

FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

A. FINANCIAL INFORMATION OF THE GROUP FOR THE THREE YEARS ENDED DECEMBER 31, 2014, 2015 AND 2016

The financial statements of the Group for each of the years ended December 31, 2014, 2015 and 2016 can be referred to in the following documents which have been published on both the website of the Stock Exchange (http://www.hkexnews.hk) and the website of the Company (http://www.mienergy.com.cn/en/):

(a) annual report of the Company for the year ended December 31, 2014 (pages 88 to 236);
(b) annual report of the Company for the year ended December 31, 2015 (pages 90 to 236);
(c) annual report of the Company for the year ended December 31, 2016 (pages 116 to 272); and
(d) interim report of the Company for the six months ended June 30, 2017 (pages 56 to 108).

B. MANAGEMENT DISCUSSION AND ANALYSIS ON THE GROUP

Set out below are the ‘‘Management discussion and analysis’’ sections and other relevant sections extracted from the Company’s annual reports for each of the years ended December 31, 2014, 2015 and 2016 and interim report for the six months ended June 30, 2017.

(i) FOR THE YEAR ENDED DECEMBER 31, 2014

BUSINESS REVIEW AND PROSPECTS

Overview

The year 2014 can be viewed as having two distinctly different parts, with the first half of the year having benefited from high crude oil prices (average realized price US$96.02/barrel) and the second half of the year characterized by drastic global oil prices decline, which negatively disrupted the entire upstream oil and gas industry. Overall, the Group’s average realized price was US$86.15/barrel, a decrease of US$10.03/barrel, compared with 2013.

Despite the oil price slump since 2H2014 and material scale back of the Group’s capital expenditure (‘‘Capex’’), the Group delivered solid execution of the work programs set out at the beginning of 2014 and successfully achieved production targets by increasing both oil and gas gross (operated) production and net production, compared with 2013. In particular, it is worth underscoring that the average daily oil production of EmirOil, LLC (‘‘Emir-Oil’’) in Kazakhstan for 2014 was 5,201 barrels per day (‘‘BOPD’’), which represents an increase of 20.4% compared to 2013. Also notable is that the Group Sino Gas & Energy Limited (‘‘SGE’’) project in Shanxi Province China reached a

– I-1 –

FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

significant milestone in November 2014, when the Qiaojiashan Gas Processing Station (‘‘QJS Station’’) in the Sanjiaobei Block was put into service, pilot production gas sales into pipeline was officially started.

In 2014, the Group divested two non-core assets in China: (1) Pan-China Resources Ltd. (‘‘PCR’’), which operates the Kongnan Production Sharing Contract (‘‘PSC’’) in Hebei Province; and (2) Miao Three which operates the Miao 3 PSC in Jilin Province. The final adjusted consideration of the PCR and Miao Three divestments was approximately US$83.1 million and US$21.2 million, respectively. The Group realized a total gain of about US$42.0 million. We believe that these two transactions demonstrate the tremendous intrinsic value of the Group’s remaining assets (e.g. the PCR sale price represents a valuation of approximately US$16.3 per 2P Reserve Barrel), and more importantly, the sale proceeds from these divestments provide good support for the Group’s liquidity and operations under current low oil price environment.

Based on the 2014 yearend oil and gas reserves and resources estimates prepared by independent consultants, the Group’s reserves value continues to enhance significantly, with NPV10 of the Group’s 2P oil and gas reserves estimated to be approximately US$4.0 billion, or a 14.3% increase from 2013, which is largely based on the gas reserves increases achieved in the SGE project.

The Group drilled 193 wells in 2014 (including 36 wells in SGE), which is fewer than our 2014 guidance, as we strategically scaled down drilling activities after oil price dropped in second half of 2014. As of December 31, 2014, the Group operated a total of 2,753 wells, of which, 2,703 are located in China, 45 in Kazakhstan, and 5 in the USA.

REVIEW ON OPERATIONS BY SEGMENT

. China Operations

(1) Oil Projects (Jilin Province: Daan, Moliqing, Miao 3; Hebei Province: Kongnan)

As part of the Group’s strategy to continuously upgrade our core assets portfolio, two definitive agreements were signed during 3Q2014 to divest PCR and Miao Three. Both transactions were completed in 4Q2014, with the final adjusted consideration being approximately US$83.1 million and US$21.2 million respectively and realized a total gain of about US$42.2 million. The PCR sale price represents a valuation of approximately US$16.3 per 2P Reserve Barrel, and the Miao Three sale price represents a valuation of approximately US$36.8 per 2P Reserve Barrel. We believe that these sales valuation metrics confirm and validate the high value of the Group’s remaining oil producing assets. The sale proceeds from these divestments will also serve as a strong buffer for the Group’s operation under the current low oil price environment.

In terms of total average daily operated oil production, the three Northeast China projects (i.e. Daan, Moliqing and Miao 3) in Jilin Province recorded a decrease of 3.9% yoy to 19,349 BOPD, whilst net production decreased 1.6% yoy to

– I-2 –

FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

9,088 BOPD. In particular, the average daily operated and net oil production for Daan and Moliqing for FY2014 were 18,854 BOPD and 8,863 BOPD, respectively (FY2013: 19,469 BOPD and 8,931 BOPD, respectively). Meanwhile, average daily net oil production for our two divested projects Kongnan and Miao 3 was approximately 945 BOPD and 225 BOPD, respectively during the same period. Due primarily to the sharp drop in global crude oil prices since 2H2014, the realized Daqing oil price (in respect of our Jilin oilfields) averaged approximately US$97.31/ bbl for FY2014, representing a decrease of 6.7% yoy, compared to US$104.25/bbl for FY2013. The average realized CINTA oil price (in respect of Kongnan oilfield) was US$103.59/bbl, for the period January 2014 to the end of November 2014 (i.e. the completion of the divestment).

A total of 151 gross wells were drilled and completed in our China oil fields during FY2014 and the total net Capex incurred was US$109 million. Compared to our Revised Capex Guidance provided in August 2014 (US$122 million), the actual Capex for 2014 in our China oilfields was reduced mainly due to our strategic cancellation of some drilling and downhole completions work, in view of declining oil prices. As we have no contractual obligation to commit a minimum amount of Capex or production level in any given period, we have the flexibility to cut back capital spending or production output whenever oil prices come down.

Direct Lifting costs in our Northeast China projects (i.e. Daan, Moliqing and Miao 3) increased by US$0.56/ barrel, or 5.4%, from US$10.39/barrel for 2013 to US$10.95/barrel for 2014 as a result of higher staff costs, power, fuel and downhole operation costs. Including the Kongnan project, the direct lifting costs of our four China oil projects for 2014 was US$11.83/ barrel. Direct Lifting costs for Daan and Moliqing increased by US$0.69/barrel, or 6.9%, from US$9.93/ barrel for 2013 to US$10.62/barrel for 2014.

The cash netback (Cash Netback is defined as Oil Price realized minus costs of Direct Lifting, Distribution Costs, and Taxes or Duties Other than Income Tax) for our Northeast China projects decreased by US$4.8/barrel, or 6.4%, from US$75.0/ barrel for 2013 to US$70.2/barrel for 2014. The decrease in cash netback was primarily due to (1) the decrease of the average realized oil price, although that is partially offset by the decrease of special oil levy for the northeast China projects and (2) the increase of direct lifting cost. After including Kongnan project, the cash netback of our four China oil projects for 2014 was US$69.6/barrel. The cash netback of Daan and Moliqing for 2014 was US$70.4/barrel.

(2) Gas Projects (Shanxi Province: Linxing, Sanjiaobei)

We are pleased with the progress made by SGE on testing, pilot production and gas sales, as well as on preparation of China Reserve Reports (CRRs) and Overall Development Plans (ODPs) in 2014.

Overall, SGE’s well testing program in 2014 has been successful, with average flow rate significantly increased (by at least 1.5 times) in comparison to the 2013 testing program. In the Linxing Block, 28 flow tests were performed (excluding the

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horizontal well TB-1H), resulting in an average absolute open flow (AOF), potential rate of 925 MSCF per day (approximately 26,205 cubic meters per day, AOF). In the Sanjiaobei Block, where 10 flow tests were carried out, similar improvement was recorded with an average AOF potential rate of 380 MSCF per day (approximately 10,780 cubic meters per day, AOF). The first horizontal well TB-1H and the new vertical well TB-23 in Linxing Block have achieved particularly encouraging test results. For TB-1H, flow testing resulted in a gas flow rate of 4.93 million cubic feet (‘‘MMSCF’’) (approximately 140,000 cubic meters per day) per day with stable tubing head pressure of 2,008 psi (or 14MPa) during 80 hours of testing in two stages. Positive results were also attained at the vertical well TB-23, where a gas flow rate of 2.0 MMSCF per day (approximately 56,600 cubic meters per day) was achieved. SGE’s second horizontal well, TB-2H also had encouraging preliminary flow rates, with the test achieving a sustained flow rate of 3.7 MMSCF per day (approximately 106,000 cubic meters/day) at the relatively stable flowing tubing head pressure of 1,494 psi (or 10Mpa). This is a particularly significant result because the TB-2H well is located 25 km north of the TB-1H well, and thereby demonstrates the great potential of the extensive north central part of the Linxing West Block. In short, the significantly improved test results achieved in 2014 underscore the tremendous potential of both the Linxing and Sanjiaobei PSCs. The test improvements also highlight SGE’s strong and rapidly expanding technological and operational know-how in gas well fracking and completion operations for both horizontal and vertical wells.

In November 2014, SGE’s Qiaojiashan Gas Processing Station (‘‘QJS Station’’) was officially put into pipeline pilot production. A total of 16 vertical wells, including 14 wells in the Linxing West block and 2 wells in the Sanjiaobei block have been connected to the QJS Station. Currently, 7 wells are producing, with a combined total pilot production rate of about 4 MMSCF per day (or approximately 113 thousand cubic meters per day). With respect to the QJS station’s capacity of 7 MMSCF per day (or 200,000 cubic meters per day), this provides substantial room for the rapid production ramp up expected early in FY2015, as more positive flow rates are recorded and more wells are brought onto production. SGE has recently signed two new gas sales agreements: the first agreement was signed in November 2014, based on a sales price for the pilot production of US$9.50/MSCF (RMB2.04/ cubic meter); and the second agreement was signed in February 2015, based on a sales price for the pilot production of US$9.60/mscf (RMB2.13/cubic meters). With SGE’s next gas processing station in the Linxing West block (with capacity of 7 million cubic feet per day) expected to be put into pilot production in 2H2015, the total production from both blocks is expected to increase significantly by late 2015 when the project enters into a new phase of pilot production development.

In FY2014, a total of 36 new wells were drilled by SGE, bringing the total number of new wells drilled since the Group’s acquisition of its 51% stake in SGE in July 2012 to 79 wells. For FY2014, the incurred Capex attributed to the Group was about US$42 million. Our Revised Capex Guidance provided in August 2014 was US$48 million, and from this amount, approximately US$6 million of Capex (or 12.5%) has been deferred into FY2015.

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The CRR for Linxing East has received official approval from the China authorities. Whilst the CRRs for Linxing West and Sanjiaobei have been submitted to the relevant China partners in 2H2014, the internal preparation and compilation work for the Linxing East and Sanjiaobei ODPs are also underway, as another priority.

SGE’s successful drilling and testing programs have led to very significant increases in the project’s reserves. According our independent consultant’s review of yearend 2014 reserves and resources for the Linxing and Sanjiaobei projects, the net 1P Reserves, attributed to the Group increased by 171% to 364.1 BCF (or 10.3BCM, and 2P Reserves increased by 54% to 466.7BCF(13.2BCM). Furthermore, the yearend 2014 reserves assessment indicates that, based on 2P Gas Reserves, the Group’s net share NPV 10 is estimated at about US$1.6 billion. In the current global low oil price scenario, the price and demand for natural gas in China has remained strong, and SGE currently sells gas at US$9.50 to US$9.60 per MSCF. With huge net contingent and prospective resources attributed to the Group totaling more than 1,350 BCF (38.3BCM, Best Estimate Prospective Resources + 2C Contingent Resources) in an extensive area of about 3,000 square kilometers, SGE still has significant growth potential. We are very positive that our SGE project will experience strong growth and profitability in the foreseeable future.

. Kazakhstan Operations (Emir-Oil)

Average daily oil production for Emir-Oil increased by 20.4% yoy from 4,320 BOPD in FY2013 to 5,201 BOPD in FY2014. However, the average realized oil price for EmirOil was US$62.82/barrel for FY2014, representing a drop of 21.1% yoy, compared to US$79.64/barrel for FY2013. The average realized export oil price (after deducting export sales discount of US$20.98/barrel) and domestic oil price were US$69.72/ barrel and US$40.15/barrel respectively, compared to US$87.80/barrel (export) and US$41.57/barrel (domestic) realized for FY2013. The drop in average realized oil price was mainly due to: 1) lower export oil price particularly since 2H2014; and 2) decrease in export:domestic sales mix from 82:18 for FY2013 to 76:24 during FY2014.

As of December 31, 2014, Emir-Oil operated a total of 45 wells, of which 22 wells were producing and 16 wells were shut-in. During FY2014, 6 new wells were drilled by Emir-Oil, including 4 development wells and 2 exploration wells. Also, 1 side-track of an existing well was completed. As of yearend FY2014, 3 new wells and 1 side-track well had been spudded and were on schedule to complete in FY2015.

Although the groundbreaking for construction of the new CPF took place in November 2014, the Group has recently decided to postpone the target date of completion for the CPF from 1H2015 (original target date) to 2016, in light of current global oil price volatility. Total Capex for Emir-Oil incurred in FY2014 amounted to about US$54 million. With respect to the Revised Capex Guidance provided in August 2014 of US$125 million, the reduction of Emir’s actual Capex was mainly related to our strategic deferral of construction work on the CPF and deferral of completion of 3 wells into FY2015.

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In January 2015, Emir-Oil and the Kazakhstan Ministry of Energy (formerly known as Ministry of Oil and Gas) executed an agreement to extend the expiration period of the Aksaz- Dolinnoe-Emir-Kariman (‘‘ADEK’’) Exploration Contract by 2 years to January 9, 2017. Based on incremental reserves and resources attributable to prior exploration work within the ADEK area, the Group is excited about the upside potential provided by this exploration contract extension.

In order to enhance profit margins, particularly in light of the current low oil price environment, Emir-Oil executed a new sales agreement with our Kazakhstan export oil marketing company, Euro-Asian Oil SA (formerly known as ‘‘Titan Oil’’) in February 2015 to change the transportation route for our export oil, in order to reduce the transport cost. The new export route goes from Emir-Oil’s oilfield to Aktau Port (Kazakhstan), across the Caspian Sea via vessel to Makhachkala Port (Russia), and then further via onshore oil pipeline reaches Novorossiysk Port (Russia), which is the final destination. The new transportation route will increase the cash netback for the export oil by approximately US$2 to US$3/barrel, after taking account for the differential between Brent and the new sales price which is based on the benchmark Urals (RCMB) Oil Price.

The direct lifting cost for Emir-Oil decreased by US$0.33/ barrel, or 6.3%, from US$5.18/barrel for 2013 to US$4.85/ barrel for 2014. The decrease in lifting cost was primarily due to the ramp up of production.

The cash netback for the domestic sales oil of Emir-Oil was about flat at US$31.81/ barrel comparing with 2013. The cash netback for the export sales oil of Emir-Oil decreased by US$14.89/barrel, or 34.3%, from US$43.42/barrel for 2013 to US$28.52/ barrel for 2014. The decrease in cash netback for export sales oil was primarily due to the decrease of the average export realized oil price, alongside with the global oil price decline in 2H2014.

Due the above factors, the weighted average cash netback for Emir-Oil decreased by US$12.23/barrel, or 29.6%, from US$41.37/barrel for 2013 to US$29.14/barrel for 2014.

. USA Operations (Condor)

There were no drilling activities during 2014 in our US business. The Group’s subsidiary, Condor Energy Technology LLC, operates 5 horizontal wells in the Niobrara project. For 2014, the average daily operated oil and gas production was 129 BOPD and 277 MSCF/day, net oil and gas production was 92 BOPD and 209MSCF/day, respectively. Average realized oil and gas price was US$83.11/barrel and US$6.44/MSCF, respectively.

. Other Segment

In November 2014, the Group participated in a co-investment opportunity with CCGRF for a minority interest in CIOC. Total consideration paid by the Group for this investment is approximately US$7.0 million. CIOC is a Calgary (Canada) headquartered private oil and gas producer. With approximately 250,000 net acres, CIOC’s core asset is located in the Alberta Deep Basin where it is developing unconventional multi-zone, oil and liquids-rich gas plays. CCGRF is a private equity fund focused in the natural

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resources sector wi th more than US$1 bil l ion of commitments under management. The Group’s strategic alliance with CCGRF and co-investment in CIOC has broadened our connection with global top-tier oil and gas specialized operators and investors and set the stage to pursue our future global expansion strategies.

FY2015 Guidance

Following is our preliminary guidance for 2015:

	Numbers	Net
	of Wells	Investments	Net Production	Comments
	(Gross)	(millions of
		US$)
Group in Total	32	103	Total: 11,400–12,800 BOED	Represents a 22–31% yoy
			Oil: 9,800–11,100 BOPD	decrease (without PCR &
			Gas: 9,600–10,100	Miao 3 in 2014) of oil
			MCFD (270–280MCMD)	production, 53–61% yoy
				increase of gas production
China Oil Projects	—	13	Oil: 6,700–7,000 BOPD	No wells will be drilled under
(Daan, Moliqing)				current low oil price outlook;
				minimal Capex for converting
				development wells to injection
				wells and other surface
				engineering
China Gas Projects	29	51	Gas: 4,500–5,000	Based on 51% of US$99 mm
(SGE: Linxing,			MCFD (130–140 MCMD)	SGE budget approved by the
Sanjiaobei)				Board in Jan 2015, including
				8 exploration wells, 21
				development wells and
				US$9.2 mm seismic expenses
				not capitalized by the Group.
				Significant ramp up of pilot
				production with Linxing
				Central Gas Station
				operational in 2H2015
Kazakhstan	3	39	Oil: 3,000–4,000 BOPD	Including completion work for 1
(Emir-Oil)			Gas: 5,000	exploration well, 2
			MCFD (142MCMD)	development wells, all
				spudded in 2014; Capex for
				CPF is US$19 mm
USA (Condor)	—	—	Oil:100 BOPD
			Gas:100
			MCFD (3MCMD)

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FINANCIAL RESULTS

Revenue

The Group’s revenue is generated from sales of oil and gas products and rendering of services.

The Group’s revenue from sales of oil and gas decreased by RMB283.1 million, or 8.7%, from RMB3,253.1 million for 2013 to RMB2,970.0 million for 2014. This decrease was primarily due to the decrease of average realized oil price, from US$97.06/barrel of year 2013 to US$86.15/barrel in 2014. Our total net sales volume of crude oil was 5.58 million barrels for 2014, compared to 5.38 million barrels for 2013.

The Group’s revenue from rendering of services is RMB12.9 million for 2014.

. China

Our China oil fields realized revenue from oil sales of RMB2,204.1 million in 2014, decreased from RMB2,440.9 million for 2013. The decrease was mainly due to decrease in realized oil price and sales volumes. Our China total net sales volume was 3.66 million barrels for 2014, compared to 3.77 million barrels for 2013, the average realized oil price was US$97.89/barrel for 2014, compared to US$104.35/barrel for 2013.

. Kazakhstan

In 2014, Emir-Oil realized revenue of RMB746.3 million. In 2013, revenue contributed by Emir-Oil was RMB782.6 million.

(a) Crude oil sales

In 2014, Emir-Oil realized revenue from crude oil sales of RMB732.7 million. Emir-Oil exported 76.4% of its sales volume of oil and realized Brent prices (before transportation and sales commission) for such export sales. The average realized oil price comprising export and domestic sales was US$63.34/barrel for 2014. The average realized oil price for 2014 was US$70.63/barrel from export sales (after transportation and marketing commissions of US$20.98/barrel) and US$39.68/barrel from domestic sales. Emir-Oil’s total oil sales volume was 1,882,351 barrels, comprising 1,438,962 barrels from export sales and 443,389 barrels from domestic sales. Revenue from export sales of oil accounted for 85.2% of Emir-Oil’s total oil revenue.

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During 2013, Emir-Oil realized revenue from oil sales of RMB768.9 million. Emir-Oil exported 82.3% of its sales volume of oil and realized Brent prices for these sales. The average realized oil price (before transportation and marketing commissions) comprising export and domestic sales was US$79.64/barrel. The average realized oil price was US$87.80/barrel from export sales (after transportation and marketing commissions of US$20.76/barrel) and US$41.57/barrel from domestic sales. Emir-Oil’s oil sales volume was 1,559,808 barrels for 2013, comprising of 1,284,287 barrels from export sales and 275,520 barrels from domestic sales. Revenue from export sales of oil accounted for 90.8% of Emir- Oil’s total oil revenue.

(b) Gas sales

In 2014, Emir-Oil realized revenue from gas sales of RMB13.6 million with average realized gas price of US$1.14 per Mscf and total gas sales volume of 1,954,375 Mscf, whilst revenue realized from gas sales in 2013 was RMB13.8 million with average realized gas price of US$1.34 per Mscf and total gas sales volume 1,661,583 Mscf.

Operating expenses

The Group’s operating expenses decreased by RMB177.5 million, or 7.4%, from RMB2,386.9 million for 2013 to RMB2,209.4 million for 2014, primarily due to the inclusion RMB259.4 million ‘‘Other Gains’’ from disposal of subsidiaries, partially offset by assets impairment loss, and increase in general and administrative expense.

. Depreciation, depletion and amortization. The Group’s depreciation, depletion and amortization increased by RMB23.4 million, or 2.6%, from RMB905.0 million for 2013 to RMB928.4 million for 2014. The increase in depreciation, depletion and amortization was mainly due to slightly higher unit of production from of China oil and gas properties.
. Taxes other than income taxes. The Group’s taxes other than income taxes decreased by RMB45.5 million, or 6.1%, from RMB740.6 million for 2013 to RMB695.1 million for 2014.

The decrease in taxes other than income taxes for our China operations was mainly due to lower crude oil production and sales volume and decrease in average realized oil price, which resulted in lower unit special oil levy (‘‘Special Oil Levy’’). The Special Oil Levy is calculated according to five progressive levels and valorem rates on the excess amounts of the realized crude oil price; it is calculated on a monthly basis and paid on a quarterly basis. The Ministry of Finance of the People’s Republic of China (‘‘MOF’’) recently issued a notice regarding the uplift of the threshold of the special oil levy (Cai

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Shui [2014] No.115) (‘‘Notice’’) from US$55 to US$65 per barrel, with effect from January 1, 2015. Details are as follows:

Crude oil prices
(US$/barrel)	Level of levy
65–70 (inclusive)	20%
70–75 (inclusive)	25%
75–80 (inclusive)	30%
80–85 (inclusive)	35%
Over 85	40%

The decrease in Special Oil Levy in China operation was partially offset by the increases in Export Duty of our Kazakhstan operation, which were mainly caused by export duty increased from US$60 per metric ton to US$80 per metric ton, with effect from March 2014.

Set out below are the various taxes that our Kazakhstan operation being subject to:

Rent export tax

Rent export tax is payable on export oil and is calculated based on world prices for crude oil. Rent Export Tax rate depends on export price for crude oil and can be 0% if export price is less than US$40/ barrel or up to 32% if export price is higher than US$190/barrel.

Mineral extraction tax (‘‘MET’’)

MET is payable at a rate of 5% for export oil and 2.5% for domestic oil. MET for export oil is calculated at 5% based on barrels of oil produced, less barrels of domestic oil and barrels of internally consumed oil, multiplied by average world oil price/barrel. MET for domestic oil is calculated at 2.5% based on barrels of domestic oil multiplied by production cost/barrel multiplied by 120%.

Export duty

Before April 14, 2013, export duty is payable on export oil and calculated as US$40 per metric ton or US$5.35/barrel multiplied by volume of export oil sales. From April 14, 2013, this duty increased to US$60 per metric ton. From March 12, 2014, this duty was increased to US$80 per metric ton.

Property tax

Property tax is payable on oil and gas assets which have been granted a production license at a rate of 1.5% based on average balance of oil and gas properties.

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Corporate

Withholding Tax

Withholding tax represents accrual of withholding tax on interest charged on intercompany loans.

Employee compensation costs.

The Group’s employee compensation costs decreased by RMB12.2million, or 5.4%, from RMB227.8 million for 2013 to RMB215.6 million for 2014. The drop in employee compensation costs was primarily due to decrease in performance bonus.

Purchases, services and other expenses.

Our purchases, services and other expenses decreased by RMB32.9 million, or 8.9%, from RMB370.2 million for 2013 to RMB337.3million for 2014. The decrease in purchase, service and other expenses was primarily due to (i) less work over and fracturing of wells for Emir-Oil ; (ii) less amount was paid or settled with suppliers in Kazakhstan upon Tenge’s devaluation in early 2014; (iii) only ten months of Miao Three’s purchases, services and other expenses being included before the completion of its disposal.

Geological and geophysical expenses.

The Group adopts ‘‘successful method’’ accounting and under this method, exploration costs including geological and geophysical expenses (other than direct exploration wells drilling costs) are charged to profit and loss account in the period of incurrence. During 2014, the Group incurred geological and geophysical expenses in of about RMB20.0 million, compared to RMB4.7 million of 2013.

Distribution expenses.

The Group’s distribution expenses increased by RMB5.3 million, or 16.9%, from RMB31.3 million for 2013 to RMB36.6 million for 2014. The increase in such pipeline expenses was due to the increase in sales volume of our Kazakhstan operation in 2014.

General and administrative expenses.

The Group’s general and administrative expenses increased by RMB21.2 million, or 20.7% from RMB102.5 million for 2013 to RMB 123.7 million for 2014. The increase was primarily due to: (i) Emir- Oil incurred more education services, training, and donation expenses; and (ii) more business travel expenses incurred at corporate level.

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Impairment charges.

Thre Group recognized an impairment charge amounting to RMB29.3 million and RMB125.3 million on the long-live assets (including mineral extractions rights) relating to a block in the PRC and the working interest in the USA, respectively, to reduce their carrying value to the respective estimated recoverable amount calculated based on valuein-use.

Other (losses)/income.

The Group incurred ‘‘other income’’ of RMB302.0 million for 2014, compared to other loss of RMB4.6 million for 2013. Other income for the current year includes mainly (i) RMB52.2 million gains from disposal of Miao Three and RMB207.2 million from disposal of PCR; (ii) realized gain of RMB19.6 million from oil hedge contracts for our 2014 production; (iii) royalty income received by PCR for its interest in the Zhou 13 Bock in Daqing of RMB8.1 million; and (iv) non-cash revaluation gain of RMB3.6 million for this interest. Other losses for 2013 represented (i) a non-cash, unrealized loss of RMB7.63 million from changes in fair value of oil hedge options for our 2014 production; (ii) an indemnity provision for Emir-oil’s traffic accident of RMB23.1 million, which is offset by (iii) royalty income received by PCR for its interest in the Zhou 13 Bock in Daqing of RMB5.5 million and (iv) consulting fee income of RMB14.1 million.

Profit from operations

The Group’s profit from operations decreased by RMB95.7 million, or 11.0%, from RMB869.2 million for 2013 to RMB773.5 million for 2014. This decrease was primarily due to the decrease in realized oil price and impairment loss for Condor and Moliqing oil & gas properties, which is partially offset by the increase in sales volume and gains from disposal of Miao Three and PCR.

Finance income/(costs), net

The Group’s finance income increased by RMB12.1 million, or 189.1%, from RMB6.4 million for 2013 to RMB18.5 million for 2014. This increase was primarily due to our cash and cash equivalent balance as at 2014 increased significantly.

Finance cost increased by RMB147.8 million, or 42.0%, from RMB352.0 million for 2013 to RMB499.8 million for 2014. This increase was primarily due to: (i) RMB120.2 million call premium for the early redemption of the 2016 Notes; (ii) RMB34.7 million unamortized expenses of the 2016 Notes charged to finance cost as a result of redemption.

Share of loss of joint ventures

The Group holds a 51% interest in SGE. This investment was accounted for as joint ventures by the Group and our share of loss of SGE decreased from RMB68.8 million in 2013 to RMB55.4 million in 2014. This is mainly due to the decrease in loss of our investment in SGE, as a result of decreases in geological, geophysical and other

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APPENDIX I

exploration expenses (mainly seismic expenditures). These expenses are accounted for under IFRS ‘‘successful method’’ by the Group and being charged to profit and loss account in the period of incurrence (note that SGE adopts IFRS ‘‘full cost method’’, under which similar exploration expenses are capitalized as exploration and evaluation assets and will be transferred to oil and gas properties, and will ultimately depreciated on the unit-of-production basis driving the production phase of the project in future).

Profit before income tax

The Group’s profit before income tax decreased by RMB218.2 million, or 48.0%, from RMB454.9 million for 2013 to RMB236.7 million for 2014. This decrease was primarily due to the cumulative effects of the above factors.

Income tax expense

The Group’s income tax expense for 2014 was RMB214.2 million, increasing RMB39.1 million compared to the income tax expense of RMB175.1 million for 2013. The increase of income tax expense was mainly due to certain expenses were not deductible for tax purposes and no deferred income tax asset was recognized for certain tax losses and temporary differences. In addition, less income tax expense in 2013 was due to deferred tax in Kazakhstan has been re-measured in 2013 to reflect the changes in excess profit tax rate of Kazakhstan will be applied in the future, which is mainly caused by changes in management forecast of future capital expenditures and other tax rates. There is no such remeasurement occurring in 2014. The weighted average effective tax rate for 2014 is 90%, compared to 38% in 2013. The increase in effective tax rate is mainly due to non-deductible one-off finance expense related to the 2016 Notes, share of loss of SGE, impairment loss of Condor, and other expenses incurred by non-operating group companies of the Group.

Net profit for the year

As a result of the foregoing, our net profit for the year decreased by RMB257.2 million, or 91.9%, from RMB279.8 million for 2013 to RMB22.6 million for 2014.

LIQUIDITY AND CAPITAL RESOURCES

Overview

The Group’s primary sources of cash during 2014 were cash flow from operating activities and cash flow from financing activities.

In 2014, we had net cash generated from operating activities of RMB1,180.4 million, net cash used in investing activities of RMB1,311.1 million, net cash generated from financing activities of RMB541.9 million, an exchange losses on cash and cash equivalent of RMB3.4 million, and a net increase in cash and cash equivalent of RMB414.3 million.

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Cash generated from operating activities

Net cash generated from operating activities was RMB1,180.4 million in the year ended December 31, 2014. In the year ended December 31, 2014, our net cash generated in operating activities included profit before income tax of RMB236.7 million adjusted for, depreciation, depletion and amortization of RMB928.4 million, net interest expenses of RMB514.1 million, employee share option of RMB12.3 million, share of loss from investments in joint ventures of RMB55.4 million, offset by gains on disposal of subsidiaries of RMB259.4 million, exchange gain of RMB32.8 million, and gains on changes of fair value of derivative financial instruments of RMB11.3 million, gains on oil hedge options of RMB19.6 million. The cash movements from changes in working capital which included decrease in trade and other payables of RMB140.5 million, an decrease in trade and other receivables of RMB226.2 million and an decrease in inventories of RMB2.5 million, and interest paid of RMB326.0 million and income tax paid of RMB155.3 million.

Net cash generated from operating activities was RMB1,209.1 million in the year ended December 31, 2013. In the year ended December 31, 2013, our net cash generated in operating activities included profit before income tax of RMB454.9 million adjusted for, depreciation, depletion and amortization of RMB905.0 million, net interest expenses of RMB394.8 million, employee share option of RMB26.5 million, share of loss from investments in joint ventures of RMB68.8 million, offset by exchange gain of RMB50.3 million. The cash movements from changes in working capital which included decrease in trade and other payables of RMB150.2 million, an decrease in trade and other receivables of RMB258.8 million and an decrease in inventories of RMB2.7 million, and interest paid of RMB295.9 million and income tax paid of RMB267.6 million.

Cash used in investing activities

Net cash used in investing activities in the year ended December 31, 2014 amounted to RMB1,311.1 million, as a result of purchases of property, plant and equipment of RMB1,314.0 million, capital contribution to investments accounted for using the equity method of RMB269.4 million, loans to investments accounted for using equity method of RMB163.9 million, increase in restricted cash of RMB103.4 million, purchase of available-for-sale financial assets of RMB72.0 million, offset by proceeds from disposal of interest in subsidiaries net of disposal expenses, cash and cash equivalent balance as at disposal date of RMB532.5 million, deposit received in relation to disposal of subsidiary of RMB46.4 million, proceeds from contingent consideration receivable of RMB8.1 million and interest received of RMB14.4 million.

Net cash used in investing activities in the year ended December 31, 2013 amounted to RMB1,585.0 million, as a result of purchases of property, plant and equipment of RMB1,408.9 million, capital contribution to and acquisition of investments accounted for using the equity method of RMB180.8 million, offset by a decrease in restricted cash of RMB1.8 million, and interest received of RMB2.9 million.

– I-14 –

FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

Cash generated from financing activities

Net cash generated from financing activities in the year ended December 31, 2014 amounted to RMB541.9 million primarily due to: (i) proceeds from the issue of the 2019 Notes of RMB2,986.2 million in April 2014, (ii) proceeds from bank borrowings of RMB411.5 million, comprising one RMB55 million and two RMB5 million short-term working capital loan from China Construction Bank (‘‘CCB’’), US$35 million from Deutsche Bank (‘‘DB’’), and US$20 million from Bank of Communication (‘‘BCM’’), and (iii) dividends on repurchased shares held in trust of RMB1.0 million, offset by: (i) 2013 final cash dividend of RMB61.0 million paid in June 2014, (ii) RMB2,465.6 million used for repayment of the 2016 Notes in May 2014 and the repayment of RMB125 million short-term and RMB1.5 million long-term working capital loan from CCB, (iii) RMB120.2 million used for the payment of premium related to the repayments of the 2016 Notes, (iv) RMB10.4 million used for the payment for settlement of share options, (v) RMB15.0 million used for the payment of loan arrangement fees and other fees, (vi) settlement of options to consultants for investments in subsidiaries of RMB44.6 million and (vii) RMB13.6 million payment for buyback of shares and cancellation.

Net cash generated from financing activities in the year ended December 31, 2013 amounted to RMB215.1 million primarily due to: (i) proceeds from bank borrowings of RMB120.0 million comprising two RMB60 million short-term working capital loan from CCB, (ii) proceeds from issue of senior note payable, net of issuance costs of RMB1,229.2 million, (iii) dividends on repurchased shares held in trust of RMB2.0 million, (iv) proceeds from disposal of a joint venture of RMB16.7 million, proceeds from partial disposal of interest in subsidiary of RMB44.5 million, offset by: (i) 2012 final dividend paid of RMB124.4 million, (ii) repayments of RMB998.6 million comprising repayment a US$80 million loan and US$60 million loan from Minsheng and two RMB60 million short-term working capital loan from CCB, (iii) RMB25.3 million used for the payment of loan arrangement fees and (iv) payment for share purchased under Share Award Scheme of RMB50.2 million.

Our gearing ratio, which is defined as total borrowings less cash and cash equivalents (‘‘Net Borrowings’’) divided by the sum of Net Borrowings and total equity, increased slightly from 47.7% as at December 31, 2013 to 51.8% as at December 31, 2014, principally due to the newly issued 2019 Notes.

Our Total Borrowings to EBITDA ratio, which is defined as total borrowings divided by EBITDA increased from 2.14 as at December 31, 2013 to 2.74 as at December 31, 2014.

Our Total Borrowings to Adjusted EBITDA ratio, which is defined as total borrowings divided by Adjusted EBITDA increased from 2.02 as at December 31, 2013 to 2.83 as at December 31, 2014.

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

Borrowings

The carrying amount of borrowing are denominated in the following currencies: (i) RMB8.5 million worth of borrowing in RMB; and (ii) RMB4,505.8 million worth of borrowing in US Dollars.

The Group has the following undrawn banking facilities: (i) RMB290.0 million at floating rate and expiring within one year; and (ii) RMB220.0 million at fixed rate and expiring within one year.

Market Risks

Our market risk exposures primarily consist of fluctuations in oil prices and exchange rates.

Oil price risk

Our realized oil prices are determined by reference to oil prices in the international market, changes in international oil prices will have a significant impact on us. Unstable and high volatility of international oil prices may have a significant impact on our revenue and profit.

Currency risk

The majority of the Group’s China operation sales are in US dollars, while production and other expenses in China are incurred in RMB. The RMB is not a freely convertible currency and is regulated by the PRC government. Limitations on foreign exchange transactions imposed by the PRC government could cause future exchange rates to vary significantly from current or historical exchange rates.

The functional currency of the Kazakhstan subsidiary is in US dollars and all export sales are in US dollars. The transactions of the Kazakhstan subsidiary which are denominated in the Kazakhstan Tenge are exposed to fluctuations in the US dollars and Kazakhstan Tenge exchange rate. Management is not in a position to anticipate changes in the PRC foreign exchange regulations or the fluctuations between the US dollar and Kazakhstan Tenge exchange rates, and as such is unable to reasonably anticipate the impacts on the Group’s results of operations or financial position arising from future changes in exchange rates.

CHARGES ON GROUP ASSETS

The secured bank loans totalling RMB122.4 million is secured by the Group’s bank deposits of approximately RMB132.3 million.

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

EMPLOYEES

As at December 31, 2014, the Group had 2,131 employees, with 1,783 based in China (Mainland and Hong Kong), 344 based in Kazakhstan and 4 based in USA.

The Group have adopted a market-oriented employment system and a competitive remuneration scheme. The remuneration scheme and employment system are periodically reviewed. Apart from pension funds and in-house training programs, performance bonuses and share options may be awarded to employees according to assessment of individual contribution.

The stock incentive compensation plan was adopted on November 20, 2009 with the purpose of providing additional incentive to employees, directors and consultants to attract and retain the best available personnel for positions of substantial responsibility. The Company originally reserved 6,072,870 ordinary shares for issuance under the Plan. The Company has undertaken that no further options shall be granted under the Plan upon its initial public offering. Any options granted prior to the initial public offering remain subject to the ordinary vesting and exercise provisions set out in the award agreement. A total of 4,422,000 shares originally reserved for the Plan were cancelled upon the initial public offering.

As approved by shareholders of the Company at a meeting held on November 27, 2010, the Company adopted a new share option scheme (‘‘Scheme’’) in accordance with Chapter 17 of the Listing Rules.

The purpose of the Scheme is to enable the Company to grant options to selected participants as incentives or rewards for their contributions to the Group.

The Company’s directors may, at their absolute discretion, invite any person belonging to any of the following classes of participants, to take up options to subscribe for the shares: (i) any employee (full time) of the Company or any of the subsidiaries, including any executive Director; and (ii) any non-executive Director (including independent non-executive Director) of the Company or any of the subsidiaries.

CONTINGENCIES

On August 28, 2000, MIE entered into a PSC with Sinopec for exploration and development of Luojiayi 64 block at Shengli oilfield in Shandong Province, which was suspended since the end of 2004. In April 2005, MIE requested an extension from Sinopec to restart the project. On September 27, 2006, MIE received a letter from Sinopec denying the request to restart the project and seeking to terminate the PSC on the grounds that the extension period of the trial-development phase had expired and MIE had not met its investment commitment under the PSC. The Company believes its investment in the project at Shengli oilfield had met the required commitment amount under the PSC. The PSC with Sinopec has not been formally terminated and the dispute has not entered any judicial proceedings. As advised by the external legal counsel of the Company, the probability of claim from Sinopec for unfulfilled investment commitment, if any, in relation to the pilotdevelopment phase is remote as the statute of limitations has run out.

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

SHARE OPTION SCHEME

Cancellation of Vested Options

On September 20, 2011, the Company granted, pursuant to the share option scheme adopted by the Company on November 27, 2010 (the ‘‘Scheme’’), share options to certain employees of the Company, entitling the option holders to subscribe for an aggregate of 112,048,000 ordinary shares of the Company of US$0.001 each at the exercise price of HK$2.254 per share (‘‘2011 Grant’’). The share options for an aggregate of 5,987,200 shares subsequently lapsed pursuant to the terms of the Scheme and the relevant option agreements as at December 31, 2014.

Since February 2013, the exercise price of the vested options has been higher than the prevailing market price of the shares. As a result, the options could no longer serve as an effective incentive. In view of this, the Company offered these option holders a cash consideration of HK$0.20 per share to cancel vested options under the 2011 Grant, subject to the option holders consenting to such cancellation. As a result, options in respect of 65,358,066 shares were cancelled on March 21, 2014.

Grant of New Options

On March 21, 2014, the Company granted share options pursuant to the Scheme to 151 eligible participants comprising certain directors, substantial shareholders and employees of the Company to subscribe for an aggregate of 97,280,000 shares. These options have an exercise price of HK$1.40 per share and a term of 10 years from the grant date, and will vest over the next three or four years. The share options for an aggregate of 4,008,379 shares subsequently lapsed pursuant to the terms of the Scheme and the relevant option agreements as at December 31, 2014.

FUTURE PLANS FOR MATERIAL INVESTMENTS OR CAPITAL ASSETS AND THEIR EXPECTED SOURCES OF FUNDING IN THE COMING YEARS

The sharp slump of international crude oil prices since 2H2014 undoubtedly affects oil producers around the world. A vast number of oil companies ranging from independents to international majors have already announced substantial cuts to work plans and budgets for 2015. In view of current conditions, and given the global crude oil market outlook remains to be volatile and challenging, management of the Group is committed to exercise further due care when pursuing our business plans, particularly when that is related to any capital expenditures and/or investments.

– I-18 –

FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

(ii) FOR THE YEAR ENDED DECEMBER 31, 2015

BUSINESS REVIEW AND PROSPECTS

Overview

A race to pump by OPEC crude producers, US shale and Non-OPEC suppliers created an unprecedented global glut that drove oil prices to a second year of steep declines since 2014. The dramatic drop and volatility in crude prices reverberated around the world, prompting changes in both government spending and private sector investment.

Despite the challenging environment, the Group made achievement in managing and lowering our costs and the adaptability exhibited in executing our FY2015 work program. In particular, lifting costs in our China oil projects dropped by 10.6% to US$9.49/barrel, while those of Emir-Oil in Kazakhstan decreased by 24.6% to US$3.66/barrel. In our SGE project in Shanxi Province, China, vertical well drilling costs were also down approximately 10%. In terms of overall overhead, the total headcount of the Group was reduced from about 2,100 as of year-end FY2014 to about 1,700 as of year-end FY2015.

Based on the year-end FY2015 oil and gas reserves and resources estimates prepared by independent technical consultants, the Group’s reserves were enhanced, despite the low oil price environment, with the Group’s 2P oil and gas reserves at 232.2 million BOE, representing a 6% increase from year-end FY2014. The increase in total 2P oil and gas reserves is largely attributable to the gas reserves increases achieved in the SGE project, where a successful FY2015 drilling and well-testing program increased 2P gas reserves by 23% to 574 BCF (16.3 BCM).

Successful exploration drilling in SGE and Emir-Oil provided significant reserves additions. At SGE, new gas reserves were discovered by three exploration wells within the Linxing East block, expanding the discovered resource area of the Linxing PSC by 40 square kilometers (7% increase) to 613 square kilometers, and adding approximately 33 BCF to the Group’s net 2P gas reserves share of the SGE project. On a BOE-basis, the Group’s net 2P gas reserves share of 574 BCF for the SGE project represents 95.7 million BOE, which is approximately equivalent to the 2P oil reserves of Emir-Oil (96.2 million barrels), and about four times the combined 2P oil reserves of Daan plus Moliqing (24.4 million barrels). Furthermore, important exploration success was also achieved in Kazakhstan where Emir-Oil tested the North Kariman-1 well at an initial production rate of 1,520 barrels of oil per day (‘‘BOPD’’). As a result, 2P reserves for the North Kariman discovery were increased by approximately 55%, helping to keep Emir-Oil’s total 2P oil reserves essentially flat versus year-end 2014.

The Group drilled a total of 23 new wells in FY2015 (including 20 wells in SGE), less than our original guidance, as we strategically scaled down drilling activities and deferred a portion of SGE’s work program. As of year-end FY2015, the Group operated a total of 2,772 wells, of which, 2,719 are located in China, 48 in Kazakhstan, and 5 in the USA.

– I-19 –

FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

Review of Operations by Segment

. China Operations

(1) Oil Projects (Jilin Province: Daan, Moliqing)

During FY2015, total gross operated production for our two China oil projects, Daan and Moliqing, decreased by 15.4% to 15,942 BOPD, as compared to FY2014 (excluding the production of Pan-China Resources Ltd. (‘‘PCR’’) and Miao Three Energy Limited (‘‘Miao Three’’)). Total net production allocated to the Group decreased by 24.5% to 6,687 BOPD (excluding the production of PCR and Miao Three), mainly due to the scale back of Capex. In line with the decline in global crude oil prices, the average realized Daqing oil price averaged approximately US$46.65/barrel for FY2015, representing a decrease of 52.1% year-on-year, compared to US$97.31 for FY2014.

No new wells were drilled for the China oil projects in FY2015. Total net Capex relating to converting development wells to injection wells and other surface engineering incurred was US$5 million.

Direct lifting costs for Daan and Moliqing decreased by US$1.13/barrel, or 10.6%, from US$10.62/barrel for FY2014 to US$9.49/barrel for FY2015 as a result of lower fuel, electricity, transportation and downhole operating costs, as well as enhanced operational efficiency and maintenance scheduling adjustments.

EBITDA per barrel for our China oil projects decreased by US$34.04/barrel, or 51.8%, from US$65.70/barrel for FY2014 to US$31.66/barrel for FY2015. The decline in EBITDA per barrel was primarily due to the drop in average realized oil price, which was partially offset by the decrease of special oil levy for the China oil projects and the decrease in direct lifting cost.

(2) Gas Projects (Shanxi Province: Linxing, Sanjiaobei)

In FY2015, SGE made significant progress on testing, pilot production, gas sales, as well as preparation of China reserve reports (‘‘CRR’’) and overall development plans (‘‘ODP’’).

SGE well testing program continued to be successful in FY2015. The most notable test results was at the Linxing West vertical well TB-27, located in the northeast part of the block, where a flow rate of 1.8 MMSCF/day (or 50,940 cubic meters/day) at a pressure of 630 psi (or 4.2Mpa) was recorded from an un-fracked reservoir zone. This represents the second highest flow rate ever achieved from an un-stimulated reservoir zone in the SGE project area. The significantly improved test results underscore the tremendous potential of both the Linxing and Sanjiaobei PSCs. The test improvements also highlight SGE’s strong and rapidly expanding technological and operational knowhow in gas well fracking and completion operations for both horizontal and vertical wells.

– I-20 –

FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

In FY2015, a total of 20 new wells were drilled by SGE, including 17 wells in Linxing block (including 2 horizontal wells, TB-3H and TB-4H) and 3 wells in Sanjiaobei block, bringing the total number of new wells drilled since the Group’s acquisition of its 51% stake in SGE in July 2012 to 99 wells. SGE’s net incurred Capex attributed to the Group was about US$22 million. Particularly notable were results achieved in SGE’s new horizontal wells. The horizontal well TB-3H has lateral section of 1,051 meters and logs have indicated excellent development potential, while TB-4H has lateral section of 1,184 meters and is adjacent to TB-3H. Furthermore, efficiencies and improved rig rates drove an approximate 10% decrease in average well costs in FY2015 compared to FY2014. As a result, average costs for both exploration wells and vertical development wells were approximately US$100,000 lower in FY2015, at about US$900,000 and US$1.1 million, respectively.

In terms of pilot production and sales, SGE’s Linxing CGS was officially put into pipeline pilot production in October 2015, providing the project substantial room for rapid production ramp up. As of year-end FY2015, a total of 14 wells have been connected to the Linxing CGS. 10 wells were producing, with a combined total pilot production rate of about 7 MMSCF per day (or approximately 200,000 cubic meters per day). In addition, SGE has recently signed attractive terms for two new gas sales agreements for FY2016, amid the recent NDRC announcements on the reduction in city-gate prices. For Sanjiaobei gas production, a revised wellhead gas sales price of RMB1.63 per cubic meter (approximately US$7.10/MSCF) has been signed with a new local gas buyer, Shanxi Guoxin Energy, under the Shanxi provincial government. For Linxing gas production, a revised wellhead gas sales price of RMB1.615 per cubic meter (approximately US$7.04/MSCF) has been signed with Shanxi Guohua Energy Limited Company.

Sanjiaobei CRR has been submitted to PetroChina Coalbed Methane Company Limited (‘‘PCCBM’’) and is currently progressing through technical review with approval expected in the middle of 2016, while approval for Linxing West CRR is anticipated by the end of FY2016. During the FY2015, SGE also completed the geology and gas reservoir engineering section of the Sanjiaobei ODP.

As mentioned above, SGE’s successful drilling and testing programs have led to further significant increases in the project’s reserves. According to the independent technical consultant’s review of year-end FY2015 reserves and resources for the Linxing and Sanjiaobei blocks, the net 1P reserves, attributed to the Group increased by 3% to 376 BCF (or 10.6BCM) and 2P reserves increased by 23% to 574 BCF (16.3 BCM). Furthermore, the year-end FY2015 reserves assessment indicates that, based on 2P gas reserves, the Group’s net share NPV 10 is estimated at about US$1.3 billion. In the current global low oil price scenario, the price and demand for natural gas in China has remained strong, and SGE currently sells gas at between RMB1.615 to RMB1.63/cubic meter (US$7.04 to US$7.10 per MSCF). With huge net contingent and prospective resources attributed to the Group totaling more than

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

1,521 BCF (43.1BCM, Best Estimate Prospective Resources + 2C Contingent Resources) in an extensive area of about 3,000 square kilometers, SGE still has further enormous growth potential.

Furthermore, SGE has recently confirmed the receipt of pilot gas sales revenue for the Linxing PSC since December 2014, which accordingly shall be applied to finance a significant portion of the project’s Capex for FY2016 and beyond. Meanwhile, the discussion with PCCBM in respect of a similar pilot gas sales allocation for the Sanjiaobei block is progressing well. As such, we remain excited that the SGE project will contribute significant profitability and shareholders’ value to the Group in the foreseeable future.

. Kazakhstan Operations (Emir-Oil)

Due to the strategic shut-in of low efficiency wells during this period of low global oil prices, the average daily oil production for Emir-Oil decreased by 34.4% from 5,201 BOPD in FY2014 to 3,412 BOPD in FY2015. The average realized oil price for Emir-Oil was US$43.95/barrel for FY2015, representing a drop of 30.6% year-on-year, compared to US$63.34/barrel for FY2014. The average realized export oil price (after deducting export sales and transportation commission (the ‘‘Commission’’) of US$5.56/barrel) and domestic oil price were US$48.41/barrel and US$12.02/barrel respectively during FY2015, compared to US$70.63/barrel (export) and US$39.68/barrel (domestic) realized for FY2014. The drop in average realized oil price was mainly due to lower export and domestic realized oil prices which were partially offset by an increase in export:domestic sales mix from 76:24 for FY2014 to 88:12 during FY2015.

As of year-end FY2015, Emir-Oil operated a total of 48 wells, of which 16 wells were producing. In FY2015, Emir-Oil completed 2 development wells and 1 exploration well that were spudded in FY2014. Total Capex for Emir-Oil incurred in FY2015 amounted to about US$56 million, which was mainly related to the construction of central processing facility (‘‘CPF’’). As of year-end FY2015, the Group has incurred a total of approximately US$46 million for the CPF. Amid the continued challenging operating environment, whilst ancillary oil and gas pipeline as well as external ground work amounting to approximately US$33 million shall be further deferred beyond 2016, it is anticipated that Emir-Oil’s CPF construction will be completed by fourth quarter of 2016.

On the exploration front, North Kariman-1, the second exploration well drilled in the North Kariman block commenced testing at the end of September 2015, and produced about 830 cubic meters of oil during the first 82 hours (approximately 1,520 BOPD), representing another high production well for the Group, following the success of North Kariman-2 well. The success at North Kariman-1 and North Kariman-2 further enhances the reserve base for Emir-Oil, and more importantly, it also makes the integration of the North Kariman block into the Kariman production license more realistic and likely, leading to the potential for further reserves upgrades, based on the possibility of one continuous accumulation in the overall Kariman — North Kariman area.

– I-22 –

FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

In order to enhance operating profit margins, particularly in light of the current low oil price environment, Emir-Oil executed a new sales agreement with our Kazakhstan export oil marketing company, Euro-Asian Oil SA (formerly Titan Oil), effective January 2016. Under the previous agreement, the benchmark price was Urals (RCMB) and the Commission payable by Emir-Oil was around US$5/barrel. Under the new export sales agreement, the benchmark price is Brent (ICE) and the Commission is about US$8/barrel. The increase in Commission is offset by the expected decrease in distribution expenses. As such, an overall net gain of approximately US$2–3/barrel is expected to be enjoyed from this new sales agreement with Euro-Asian Oil in FY2016, as compared to the previous export sales agreement.

The direct lifting cost for Emir-Oil decreased by US$1.19/barrel, or 24.6%, from US$4.85/barrel for FY2014 to US$3.66/barrel for FY2015. The decrease in lifting cost was primarily due to the operation of higher efficiency wells, reduction in administrative expenses, change in sales route, depreciation of Tenge and higher operation efficiencies.

EBITDA per barrel for the export sales oil of Emir-Oil decreased by US$14.41/ barrel, or 87.8%, from US$16.41/barrel for FY2014 to US$2.00/barrel for FY2015. The EBITDA per barrel for the domestic sales oil of Emir-Oil decreased by US$24.32/barrel, or 127.8%, from US$19.04/barrel for FY2014 to US$(5.29)/barrel for FY2015. Weighted average EBITDA per barrel for Emir-Oil decreased by US$16.49/barrel, or 96.8%, from US$17.03/barrel for FY2014 to US$0.54/barrel for FY2015. The decrease in EBITDA per barrel was primarily due to the decrease of the average realized oil price.

. USA Operations (Condor)

There were no drilling activities during FY2015 in our US business. The Group’s subsidiary, Condor Energy Technology LLC, operates 5 horizontal wells in the Niobrara project. For FY2015, the average daily operated oil and gas production was 71 BOPD and 136 MSCF/day, net oil and gas production was 54 BOPD and 109 MSCF/day, respectively. Average realized oil and gas price was US$40.68/barrel and US$2.61/ MSCF, respectively.

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

FY2016 Guidance

The following is our preliminary guidance for FY2016:

	Numbers	Net
	of Wells	Investments	Net Production	Comments
	(Gross)	(millions of
		US$)
China Oil Projects	—	$5	5,600–6,300 BOPD	Represents certain producer-
(Daan, Moliqing)				injector well conversions,
				reservoir re-fracturing, new
				equipment, surface
				engineering
China Gas Projects	21	$20	5,000 MCFD(1)	Based on the gross 2016 Capex
(Cash Call from SGE)				Budget of US$45mm
				approved by the SGE Board
Kazakhstan (Emir-Oil)	2	$30	3,600–4,200 BOPD	Comprises of the final c.
			6,000–7,000 MCFD	US$14m investment in CPF
				and 2 exploration wells
USA (Condor)	—	—	40 BOPD 100 MCFD
Group in Total	23	$55	9,240–10,540 BOPD
			11,100–12,100 MCFD

Note 1: Net production guidance only reflects Linxing’s figures

– I-24 –

FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

FINANCIAL RESULTS

Revenue

The Group’s revenue is generated from sales of oil and gas products and rendering of services.

The Group’s revenue from sales of oil and gas decreased by RMB1,946.0 million, or 65.5%, from RMB2,970.0 million for FY2014 to RMB1,024.0 million for FY2015.

This decrease was mainly due to the significant drop in crude oil prices over 2015 as well as the decrease of the Group’s overall sales volumes. In addition, the Group’s FY2015 results do not include PCR and Miao Three, two subsidiaries that were divested in 2H2014. PCR and Miao Three’s revenue totaled RMB266.5 million in FY2014. Average realized oil price was US$45.79 per barrel for FY2015, compared to US$86.15 per barrel for FY2014. The Group’s total crude oil sales volume was 3.55 million barrels for FY2015, compared to 5.58 million barrels for FY2014.

The Group’s revenue from rendering of services is RMB8.7 million for FY2015.

. China

In FY2015, our China oil fields realized revenue of RMB707.1 million. The average realized oil price was US$46.65 per barrel for FY2015, compared to US$97.89 per barrel for FY2014. Our sales volume was 2.44 million barrels for FY2015, compared to 3.66 million barrels for FY2014.

. Kazakhstan

In FY2015, Emir-Oil realized revenue from oil and gas sales of RMB310.5 million, compared to RMB746.3 million for FY2014. The decrease in revenue was primarily due to the drop in realized oil price and a decrease in sales volumes.

(a) Crude oil sales

The sales volumes decreased from 1,883,235 barrels for FY2014 (comprising 1,439,846 barrels from export sales and 443,389 barrels from domestic sales) to 1,089,285 barrels for FY2015 (comprising 955,750 barrels from export sales and 133,535 barrels from domestic sales).

The average realized oil price for FY2015 was US$48.41 per barrel from export sales (after Commission of US$5.56 per barrel) and US$12.02 per barrel from domestic sales. The average realized oil price for FY2014 was US$70.63 per barrel from export sales (after Commission of US$20.98 per barrel) and US$39.68 per barrel from domestic sales. As a result of the new export sales agreement effective February 2015, the new export transportation and marketing commissions payable to

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

Euro-Asian Oil SA decreased from US$20.98 per barrel in FY2014 to US$5.56 per barrel in FY2015, which was partially offset by an additional distribution expense averaging US$7.8 per barrel under the new agreement.

(b) Gas sales

In FY2015, Emir-Oil realized revenue from gas sales of RMB11.8 million, with a realized gas price of US$0.95 per MSCF and total gas sales volume of 2,001,150 MSCF. In FY2014, Emir-Oil realized revenue from gas sales of RMB13.6 million, with a realized gas price of US$1.14 per MSCF and total gas sales volume of 1,954,375 MSCF.

. USA

In FY2015, our USA oil fields realized revenue from crude oil sales of RMB5.1 million. The average realized oil price was US$40.68 per barrel, with sales volume of 20,085 barrels. In FY2014, our USA oil fields realized revenue from crude oil sales of RMB17.0 million. For FY2014, the average realized oil price was US$83.11 per barrel, with sales volume of 33,272 barrels.

Our USA operations realized revenue from gas sales of RMB0.3 million, with a realized gas price of US$2.61 per MSCF and total gas sales volume of 20,124 MSCF for FY2015. In FY2014, revenue from gas sales of RMB2.4 million was recorded from realized gas price of US$6.44 per MSCF and total gas sales volume of 59,961 MSCF.

Depreciation, depletion and amortization

The Group’s depreciation, depletion and amortization decreased by RMB331.5 million, or 35.7%, from RMB928.4 million for FY2014 to RMB596.9 million for FY2015. The decrease in depreciation, depletion and amortization was mainly due to: (i) the decrease in sales and production volumes in FY2015; (ii) our exclusion two subsidiaries, PCR and Miao Three in FY2015, which were divested 2H2014 and whose depreciation, depletion and amortization amounted to RMB64.8 million in FY2014; and (iii) no depreciation, depletion and amortization expenses recorded for Riyadh’s property, plant and equipment and intangible assets after Riyadh’s assets and liabilities were reclassified to ‘‘held for sale’’ on June 30, 2015.

Taxes other than income taxes

The Group’s taxes other than income taxes decreased by RMB541.1 million, or 77.8%, from RMB695.1 million for FY2014 to RMB154.0 million for FY2015.

. China

The Ministry of Finance of the People’s Republic of China (‘‘MOF’’) announced that the threshold of the special oil income levy was revised from US$55 to US$65 per barrel, effective from January 1, 2015. As no sales were realized at or above US$65 per barrel during FY2015, no special oil levy was incurred for our China oilfields.

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

. Kazakhstan

In 2015, Emir-Oil’s taxes other than income taxes amounted to RMB130.6 million, which is a decrease of RMB201.4 million, or 60.7% compared to RMB332.0 million for 2014. This decrease in taxes other than income taxes for our Kazakhstan operation was primarily due to: (i) the drop in realized oil price and sales volumes leading to the substantial decrease in both rent export tax as well as mineral extraction tax; and (ii) rent export duty expenditure was lowered from US$80 per metric ton to US$60 per metric ton with effect from April 2015.

Set out below are the various taxes that our Kazakhstan operation is subject to:

Rent Export Tax

Rent Export Tax is payable on export oil and is calculated based on realized prices for crude oil. Rent Export Tax rate ranges from 0% (if export price is less than US$40 per barrel) to 32% (if export price is higher than US$190 per barrel).

Mineral Extraction Tax (‘‘MET’’)

For production of less than 250,000 tons per annum, MET is payable at a rate of 5% for export oil and 2.5% on domestic oil. MET for export oil is based on barrels of oil produced less barrels of domestic oil and barrels of internally consumed oil, multiplied by average realized price per barrel. MET for domestic oil is calculated based on barrels of domestic oil multiplied by production cost per barrel multiplied by 120%.

Rent Export Duty Expenditure

From April 14, 2013, Rent Export Duty expenditure payable on export oil was US$60 per metric ton multiplied by volume of export oil sales. From March 12, 2014, this duty was increased to US$80 per metric ton. Subsequently, from April 2015, this duty was revised down to US$60 per metric ton.

Property Tax

Property tax is payable on oil and gas assets which have been granted a production license at a rate of 1.5% based on average balance of oil and gas properties.

. Corporate

Withholding Tax

Withholding tax represents accrual of withholding tax on interest charged on intercompany loans.

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

Employee compensation costs

The Group’s employee compensation costs decreased by RMB41.2 million, or 19.1%, from RMB215.6 million for FY2014 to RMB174.4 million for FY2015. The decrease in employee compensation costs was primarily due to (i) a reduction of headcount during FY2015; and (ii) the exclusion of two subsidiaries (PCR and Miao Three) in FY2015, which accounted for a total of RMB20.8 million employee compensation costs for FY2014.

Purchases, services and other expenses

Our purchases, services and other expenses decreased by RMB167.6 million, or 49.7%, from RMB337.3 million for FY2014 to RMB169.7 million for FY2015. The decrease in purchase, services and other expenses was primarily due to (i) the decrease of production and sales during FY2015; and (ii) the disposal of two subsidiaries (PCR and Miao Three) during 2H2014, which accounted for a total of RMB48.7 million in purchases, services and other expenses for FY2014. The Group’s results excluded these two companies during FY2015.

Distribution expenses

The Group’s distribution expenses increased by RMB52.8 million, or 144.3%, from RMB36.6 million in FY2014 to RMB89.4 million in FY2015, primarily due to the new export sales route for our Kazakhstan operation which resulted in the recording of an average of US$7.80/barrel of distribution expense. The increase of distribution expenses incurred by our Kazakhstan operation was partially offset by the decrease of distribution expenses incurred by our China oilfields due to lower sales volume for FY2015.

General and administrative expenses

The Group’s general and administrative expenses decreased by RMB8.2 million, or 6.6%, from RMB123.7 million for FY2014 to RMB115.5 million for FY2015. The decrease in administrative expenses was primarily due to: (i) the stringent cost control measures implemented by the Group; and (ii) the exclusion of two subsidiaries (PCR and Miao Three) in FY2015, which accounted for about RMB13.9 million in general and administrative expenses for FY2014. The above decreases were partially offset by transaction expenses of RMB21.9 million incurred for the proposed acquisition of Long Run Exploration Ltd. in FY2015.

Impairment charges

Due to significant lower global oil prices in FY2015, the Group recognized an impairment charge amounting to RMB473.4 million, RMB233.9 million and RMB16.7 million on the long-live assets (including mineral extractions rights) relating to assets in the PRC, Kazakhstan and the working interest in the USA, respectively, to reflect their carrying value to the respective estimated recoverable amount calculated based on valuein-use.

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

Other (losses)/income

The Group incurred ‘‘other loss’’ of RMB378.7 million for FY2015, compared to other income of RMB302.0 million for FY2014. Other losses for FY2015 arose primarily from (i) provision for bad debts of RMB86.7 million; and (ii) loss on re-measurement of disposal group classified as held for sale of RMB328.5 million, regarding assets and liabilities related to Riyadh being presented as held for sale at June 30, 2015 following the approval of the Company to dispose Riyadh. At December 31, 2015, the assets and liabilities of Riyadh were remeasured at the lower of adjusted carrying amount and fair value less cost to sell at FY2015 following initial classification as held for sale. Other income for FY2014 includes mainly (i) RMB52.2 million gains from disposal of Miao Three and RMB207.2 million from disposal of PCR; (ii) realized gain of RMB19.6 million from oil hedge contracts for our FY2014 production; (iii) royalty income received by PCR for its interest in the Zhou 13 Bock in Daqing of RMB8.1 million; and (iv) noncash revaluation gain of RMB3.6 million for this interest.

Finance income/(costs), net

The Group’s finance income increased by RMB2.0 million, or 10.8%, from RMB18.5 million for FY2014 to RMB20.5 million for FY2015.

Finance cost decreased by RMB171.2 million, or 34.3%, from RMB499.8 million for FY2014 to RMB328.6 million for FY2015. This decrease was primarily due to certain one-off finance costs incurred during FY2014 including: (i) RMB120.2 million call premium for the early redemption of the US$400 million 9.75% senior notes due 2016 (‘‘2016 Notes’’); and (ii) RMB35.2 million unamortized expenses of the 2016 Notes charged to finance cost as a result of the redemption. For FY2015, a net exchange gain of RMB85 million (2014: RMB32 million) was recorded as net result of the devaluation of the Tenge, which was offset by the devaluation of the Renminbi.

Share of loss of joint ventures

The Group holds a 51% interest in SGE. This investment was accounted for as joint ventures by the Group and our share of loss of SGE decreased from RMB55.4 million in FY2014 to RMB26.6 million in FY2015. This is mainly due to lower loss incurred by SGE as SGE realized pilot gas sales in FY2015.

Loss before income tax

The Group’s loss before income tax was RMB1,704.5 million for FY2015, compared to the profit before income tax RMB236.7 million for FY2014. This was primarily due to the cumulative effects of the above factors.

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

Income tax credit

The Group recorded an income tax credit of RMB179.2 million for FY2015, compared to an income tax expense of RMB214.2 million for FY2014. This change was primarily due to the Group incurring loss before income tax in FY2015. The effective tax rate for FY2015 is 11% compared to an effective tax rate for FY2014 of 90%.

Net (loss)/profit for the year

As a result of the foregoing, our net loss for FY2015 was RMB1,525.3 million, compared to a net profit of RMB22.6 million for FY2014.

LIQUIDITY AND CAPITAL RESOURCES

Overview

The Group’s primary sources of cash during FY2015 were cash flow from operating activities and cash flow from financing activities.

In FY2015, we had net cash generated from operating activities of RMB326.1 million, net cash used in investing activities of RMB1,124.4 million, net cash generated from financing activities of RMB298 million, an exchange gain on cash and cash equivalent of RMB14.1 million, and a net decrease in cash and cash equivalent of RMB500.4 million.

Cash generated from operating activities

Net cash generated from operating activities was RMB326.1 million in the year ended December 31, 2015. In the year ended December 31, 2015, our net cash generated in operating activities included loss before income tax of RMB1,704.5 million adjusted for, depreciation, depletion and amortization of RMB596.9 million, net interest expenses of RMB393.9 million, impairment charge of RMB724.0 million, loss on re-measurement of disposal group classified as held for sale of RMB328.5 million, provision for bad debt of RMB86.7 million, employee share option of RMB22.5 million, share of loss from investments in joint ventures of RMB26.6 million, offset by gains on write-off payables of RMB29.4 million, exchange gain of RMB85.8 million. The cash movements from changes in working capital which included decrease in trade and other payables of RMB29.5 million, a decrease in trade and other receivables of RMB344.7 million and a decrease in inventories of RMB0.1 million, and interest paid of RMB337.9 million and income tax paid of RMB10.5 million.

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

changes of fair value of derivative financial instruments of RMB11.3 million, gains on oil hedge options of 19.6 million. The cash movements from changes in working capital which included decrease in trade and other payables of RMB140.5 million, a decrease in trade and other receivables of RMB226.2 million and a decrease in inventories of RMB2.5 million, and interest paid of RMB326.0 million and income tax paid of RMB155.3 million.

Cash used in investing activities

Net cash used in investing activities in the year ended December 31, 2015 amounted to RMB1,124.4 million, as a result of purchases of property, plant and equipment of RMB644.9 million, capital contribution to/acquisition of investments accounted for using the equity method of RMB30.9 million, loans to investments accounted for using equity method of RMB155.2 million, increase in restricted cash of RMB318.8 million, release of the deposit in relation to disposal of subsidiary of RMB48.5 million, offset by proceeds from disposal of RMB45.2 million, net cash inflow from investment in available for sale financial assets of RMB28.3 million, and interest received of RMB0.6 million.

Net cash used in investing activities in the year ended December 31, 2014 amounted to RMB1,311.1 million, as a result of purchases of property, plant and equipment of RMB1,314.0 million, capital contribution to/acquisition of investments accounted for using the equity method of RMB269.4 million, loans to investments accounted for using equity method of RMB163.9 million, increase in restricted cash of RMB103.4 million, purchase of available-for-sale financial assets of RMB72.0 million, offset by proceeds from disposal of interest in subsidiaries net of disposal expenses, cash and cash equivalent balance as at disposal date of RMB532.5 million, deposit from disposal of subsidiary of RMB46.4 million, proceeds from contingent consideration receivable of RMB8.1 million and interest received of RMB14.4 million.

Cash generated from financing activities

Net cash generated from financing activities in the year ended December 31, 2015 amounted to RMB298 million primarily due to: (i) repayments of borrowings of RMB360.1 million; (ii) payment of fees of modification of terms in indenture of senior notes of RMB25.9 million, (iii) payment for repurchase of shares and cancellation of RMB17.6 million; and (iv) payment for shares purchased under Share Award Scheme of RMB11.1 million, offset by: (i) proceeds from issuance of ordinary shares of RMB200.0 million; (ii) proceeds from borrowings of RMB512.8 million.

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

term and RMB1.5 million long-term working capital loan from CCB, (iii) RMB120.2 million used for the payment of premium related to the repayments of the 2016 Notes, (iv) RMB10.4 million used for the payment for settlement of share options, (v) RMB15.0 million used for the payment of loan arrangement fees and other fees, (vi) settlement of options to consultants for investments in subsidiaries of RMB44.6 million and (vii) RMB13.6 million payment for buyback of shares and cancellation.

As at December 31, 2015, the Group’s bank borrowings and Senior Notes amounted to approximately RMB4,954.1 million, representing an increase of approximately RMB439.8 million as compared to December 31, 2014. Among which, borrowings repayable within one year amounted to approximately RMB529.9 million, representing an increase of RMB190.4 million as compared to December 31, 2014. All of the Group’s bank borrowings and Senior Notes are denominated in RMB and United States Dollars.

Our gearing ratio, which is defined as total borrowings less cash and cash equivalents (‘‘Net Borrowings’’) divided by the sum of Net Borrowings and total equity, increased slightly from 51.8% as at December 31, 2014 to 68.3% as at December 31, 2015, principally due to a decrease in cash and cash equivalents balance.

Our total borrowings to Adjusted EBITDA ratio, which is defined as total borrowings divided by Adjusted EBITDA increased from 2.83 as at December 31, 2014 to 13.39 as at December 31, 2015.

Borrowings

The carrying amount of borrowing are denominated in the following currencies: (i) RMB96.1 million worth of borrowing in RMB; and (ii) RMB4,858.0 million worth of borrowing in US Dollars.

The Group has the following undrawn banking facilities: (i) RMB290.0 million at floating rate and expiring within one year; and (ii) RMB143.9 million at fixed rate and expiring within one year.

MARKET RISKS

Our market risk exposures primarily consist of fluctuations in oil prices and exchange rates.

Oil price risk

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

Currency risk

CHARGES ON GROUP ASSETS

The secured bank loans totalling RMB96.1 million is secured by the Group’s right to receive its share of revenue allocated under Daan production sharing contract. The Group’s remaining secured bank loans totalling RMB433.8 million were secured by Group’s bank deposits of approximately RMB462.7 million.

EMPLOYEES

As at December 31, 2015, the Company had 1,684 employees, with 1,436 based in China (Mainland and Hong Kong), 244 based in Kazakhstan and 4 based in USA. There have been no material changes to the information disclosed in the Annual Report 2014 in respect of the remuneration of employees, remuneration policies and staff development.

The purpose of the Scheme is to enable the Company to grant options to selected participants as incentives or rewards for their contributions to the Group.

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

CONTINGENCIES

On August 28, 2000, MI Energy Corporation (‘‘MIE’’) entered into a PSC with Sinopec for exploration and development of Luojiayi 64 block at Shengli oilfield in Shandong Province, which was suspended since the end of 2004. In April 2005, MIE requested an extension from Sinopec to restart the project. On September 27, 2006, MIE received a letter from Sinopec denying the request to restart the project and seeking to terminate the PSC on the grounds that the extension period of the trial-development phase had expired and MIE had not met its investment commitment under the PSC. The Company believes its investment in the project at Shengli oilfield had met the required commitment amount under the PSC. The PSC with Sinopec has not been formally terminated and the dispute has not entered any judicial proceedings. As advised by the external legal counsel of the Company, the probability of claim from Sinopec for unfulfilled investment commitment, if any, in relation to the pilot-development phase is remote as the statute of limitations has run out.

FUTURE PLANS FOR MATERIAL INVESTMENTS OR CAPITAL ASSETS AND THEIR EXPECTED SOURCES OF FUNDING IN THE COMING YEARS

In summary, the sharp slump of international crude oil prices since the second half of 2014 undoubtedly affected oil producers around the world. Oil companies ranging from independents to international majors have announced further substantial cuts to work plans and budgets for the coming year. Accordingly, whilst the Group continue to closely monitor the development of global oil & gas market and keep abreast of attractive assets that would fit well with the Group’s long term development and growth, for FY2016 the Group shall maintain a strategy of reduced Capex, minimal drilling and work programs, as well as focusing on operational efficiency and cost reduction.

(iii) FOR THE YEAR ENDED DECEMBER 31, 2016

BUSINESS REVIEW AND PROSPECTS

Overview

2016 marked a volatile year in the oil markets with oil prices hitting multi-year lows in February before rising and stabilizing above US$50/bbl as OPEC stepped in towards the end of the year with a commitment to cut production. The dramatic swings in crude oil prices reverberated around the world, prompting changes in both government spending and private sector investment.

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

Despite the challenging environment, the Group made achievements in managing and lowering our costs and the adaptability exhibited in executing our FY2016 work program. In particular, lifting costs in our China oilfields dropped 12.4% to US$8.31/bbl and the production was also stabilized at a better than expected declined rate, while those of Emir Oil project in Kazakhstan decreased 38.5% to US$2.25/bbl. The Group drilled total of 2 new wells in FY2016, in line with our original guidance, while work on Emir-Oil’s Central Processing Facility(‘‘CPF’’) completion was been deferred based on mutual agreement made between the shareholders. As of December 31, 2016, the Group operated a total of 2,610 wells, of which, 2,605 are located in China and 5 in the USA. In terms of overall overhead, the total headcount of the Group was reduced from approximately 1,700 as of year-end 2015 to 1,387 as of year-end 2016.

During 2016, the Group divested its stake in Asia Gas & Energy Ltd and a 60% stake in Palaeontol B.V. (‘‘PBV’’) while acquiring a 37.4% stake in Journey Energy Inc. a Canada listed company and a 34% stake in PetroBroad Copower Limited (‘‘PetroBroad’’), a contractor with China National Offshore Oil Company (‘‘CNOOC’’) who operates a production sharing contract in the South China Sea. Following the acquisition and divestment exercises of the Group, based on the year-end 2016 oil and gas reserves and resources estimates prepared by independent consultants, the Group’s Proved +Probable (‘‘2P’’) oil and gas reserves were 75.1 million BOE, representing a 45% decrease from year-end 2015. The decrease in the Group’s 2P oil and gas reserves is largely attributable to the Group’s asset sales.

Review of Operations by Segment

. China Operations

Oil Projects (Jilin Province: Daan, Moliqing)

During FY2016, total gross operated production for our two China oil projects, Daan and Moliqing, decreased 12.0% to 14,031 BOPD, as compared to FY2015. Total net production allocated to the Group decreased by 12.2% to 5,872 BOPD, which is within the 2016 annual guidance range of 5,600–6,300 BOPD. In line with the decline in global crude oil prices, the average realized Daqing oil price averaged approximately US$36.73/bbl for FY2016, representing a decrease of 21.3% year-onyear, compared to US$46.65 for FY2015.

Based on the Group’s strategic scale back of capital expenditures (‘‘Capex’’), no new wells were drilled for the China oil projects in FY2016. Total net Capex relating to sidetrack horizontal wells, converting development wells to injection wells and other surface engineering incurred was US$4 million.

Direct lifting costs for Daan and Moliqing decreased US$1.18/barrel, or 12.4%, from US$9.49/barrel for FY2015 to US$8.31/barrel for FY2016 as a result of lower transportation and staff costs costs, as well as enhanced operational efficiency and maintenance scheduling adjustments.

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

EBITDA per barrel for our Northeast China projects decreased by US$9.21/ barrel, or 29.1%, from US$31.66/barrel for FY2015 to US$22.45/barrel for FY2016. The decline in EBITDA per barrel was primarily due to the drop in average realized oil price, which was partially offset by the decrease in direct lifting cost.

. Kazakhstan Operations (Emir-Oil)

During the 11 months of 2016, gross oil production for Emir-Oil decreased to 3,328 BOPD, 2.5% lower as compared to FY2015, and below the 2016 annual guidance range of 3,600–4,200 BOPD. Gross gas production decreased 5.0% to 5,598 MSCF/day during the first 11 months of 2016, which is also below the 2016 annual guidance of 6,000–7,000 MSCF/day.

For the first 11 months of 2016, the average realized oil price for Emir-Oil was US$34.85/barrel (FY2015: US$43.95/barrel), with export sales comprising 86% of total sales volume (FY2015: 88%). The average realized export price was US$38.39/barrel (FY2015: US$48.41/barrel) while the average realized domestic price was US$13.25/ barrel (FY2015: US$12.02/barrel). Average realized gas price was US$0.78/MSCF (FY2015: US$0.95/MSCF).

The direct lifting cost for Emir-Oil decreased by US$1.41/barrel, or 38.5%, from US$3.66/barrel for FY2015 to US$2.25/barrel for the first 11 months of 2016. The decrease in lifting cost was primarily due to the operation of higher efficiency wells, reduction in administrative expenses, depreciation of Tenge and higher operational efficiencies.

EBITDA per barrel for the export sales oil of Emir-Oil increased by US$8.74/barrel, or 437%, from US$2.00/barrel for FY2015 to US$10.74/barrel for the first 11 months of 2016. The EBITDA per barrel for the domestic sales oil of Emir-Oil increased by US$9.70/barrel, or 184%, from US$(5.29)/barrel for FY2015 to US$4.42/barrel for the first 11 months of 2016. Weighted average EBITDA per barrel for Emir-Oil increased by US$9.08/barrel, or 1681%, from US$0.54/barrel for FY2015 to US$9.62/barrel for the first 11 months of 2016. The increase in EBITDA per barrel was primarily due to the decrease in taxes, distribution and administrative expense and employee compensation costs, as well as lower lifting costs.

In FY2016, Emir-Oil completed 2 exploration wells, Dolinnoe-8 and Yessen-3, as per the requirements under its exploration license. Logs of both wells indicate oil and gas shows, and plans are for these wells to be tested in 2017. Total Capex for Emir-Oil incurred in FY2016 amounted to about US$12 million, which was mainly related to the drilling of the two wells. As agreed between both shareholders, work on Emir-Oil’s CPF construction has been deferred.

In January 2017, Emir-Oil and the Kazakhstan Ministry of Energy executed an agreement extending the expiration date of the Aksaz-Dolinnoe-Emir-Kariman (‘‘ADEK’’) Exploration Contract by three years to January 9, 2020. Under the terms of the contract

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

extension, Emir-Oil will have to drill 6 exploration wells. Based on incremental reserves and resources attributable to prior exploration work within the ADEK area, the Group is excited about the upside potential provided by this exploration contract extension.

. USA Operations (Condor) and Others

There were no drilling activities during FY2016 in our US business. The Group’s subsidiary, Condor Energy Technology LLC (‘‘Condor’’), operates 5 horizontal wells in the Niobrara project. For FY2016, the average daily operated oil and gas production was 53BOPD and 81MSCF/day, net oil and gas production was 41 BOPD and 65 MSCF/day, respectively. Average realized oil and gas price was US$37.77/barrel and US$2.30/MSCF, respectively.

FY2017 Guidance

The following is our preliminary guidance for FY2017:

			Group Net
		Numbers	Capex
	Interest	of Wells	Investment	Net Production	Comments
	(%)	(Gross)	(millions of
			US$)
China Onshore Projects	90%	17	$17	5,500–6,000 BOPD	.	15 wells in Daan
(Daan, Moliqing)					.	2 wells in Moliqing
China Offshore Project	34%	—	—	—
(28/03 Block)
Canada	33.6%	14	—	3,394–3,528 BOED
(Journey Energy)				(49% liquids)
USA (Condor)	100%	—	—	30 BOPD 50 MCFD
Group Total		31	$17	8,932–9,566 BOED

FINANCIAL RESULTS

The Group’s management and shareholders approved the disposal of 60% equity interest in PBV on June 20, 2016. Emir-Oil, which is located in Kazakhstan, is the 100% wholly-owned subsidiary of PBV (collectively, the ‘‘PBV Group’’). The Kazakhstan operation is recognized as a disposal group and discontinued operation as at December 31, 2016, as Emir-Oil represents the business in Kazakhstan segment, which is a major line of business of the Group. Emir-Oil’s operating results from the Kazakhstan operation were recorded as a loss for the period from discontinued operations, and were not included in the results of continuing operations.

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

Continuing operations

Revenue

The Group’s revenue is generated from sales of oil and gas products and rendering of technical services.

The Group’s revenue from sales of oil and gas decreased by RMB189.2 million, or 26.5%, from RMB713.5 million for 2015 to RMB524.3 million for 2016.

This decrease was mainly due to the significant drop in crude oil prices over 2016 as well as the decrease of the Group’s overall sales volumes. Average realized oil price was US$36.74 per barrel for 2016, compared to US$46.6 per barrel for 2015. The Group’s total crude oil sales volume was 2.14 million barrels for 2016, compared to 2.46 million barrels for 2015.

The Group’s revenue from rendering of technical services is RMB10.6 million for 2016.

. China

Revenue from our China oil fields decreased from RMB707.1 for 2015 to RMB519.6 million for 2016. The average realized oil price was US$36.73 per barrel for 2016, compared to US$46.65 per barrel for 2015. Our sales volume was 2.12 million barrels for 2016, compared to 2.44 million barrels for 2015.

. North America

In 2016, our North America oil fields realized revenue from crude oil sales of RMB3.9 million. The average realized oil price was US$37.77 per barrel, with sales volume of 15,328 barrels. In 2015, our North America oil fields realized revenue from crude oil sales of RMB5.1 million. For 2015, the average realized oil price was US$40.68 per barrel, with sales volume of 20,085 barrels.

Our North America operations realized revenue from gas sales of RMB0.2 million, with a realized gas price of US$2.30 per MSCF and total gas sales volume of 13,981 MSCF for 2016. In 2015, revenue from gas sales of RMB0.3 million was recorded from realized gas price of US$2.61 per MSCF and total gas sales volume of 20,124 MSCF.

Depreciation, depletion and amortization

The Group’s depreciation, depletion and amortization decreased by RMB156.3 million, or 30.0%, from RMB520.2 million for 2015 to RMB363.9 million for 2016. The decrease in depreciation, depletion and amortization was mainly due to: (i) the decrease in sales and production volumes in 2016; (ii) RMB763.8 million and RMB153.3 million impairment provision for the oil and gas properties made in 2015 and in 2016 decreased the net book value and depreciable amount of the company’s property, plant and equipment.

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

Taxes other than income taxes

The Group’s taxes other than income taxes decreased by RMB9.9 million, or 42.5%, from RMB23.3 million for 2015 to RMB13.4 million for 2016.

China

The Ministry of Finance of the People’s Republic of China (‘‘MOF’’) announced that the threshold of the special oil income levy was revised from US$55 to US$65 per barrel, effective from January 1, 2015. As no sales were realized at or above US$65 per barrel during 2016, no special oil levy was incurred for our China oilfields.

Corporate

Withholding Tax

Withholding tax represents accrual of withholding tax on interest charged on intercompany loans.

Employee compensation costs

The Group’s employee compensation costs decreased RMB10.5 million, or 7.3%, from RMB143.8 million for 2015 to RMB133.3 million for 2016. The decrease in employee compensation costs was primarily due to (i) a reduction of headcount during 2016 which caused wages, salaries and allowances to decrease by RMB4.5 million; and (ii) a decrease in stock appreciation right liabilities of RMB11.2 million as a result of lower share price at the year-end.

Purchases, services and other expenses

Our purchases, services and other expenses decreased RMB15.4 million, or 12.7%, from RMB121.0 million for 2015 to RMB105.6 million for 2016. The decrease in purchase, services and other expenses was primarily due to the decrease in production and sales during 2016.

Distribution expenses

The Group’s distribution expenses decreased RMB2.3 million, or 11.2%, from RMB20.5 million in 2015 to RMB18.2 million in 2016. The decrease in distribution expenses was primarily due to the decrease in sales during 2016.

General and administrative expenses

The Group’s general and administrative expenses decreased RMB31.5 million, or 31.8%, from RMB99.2 million for 2015 to RMB67.7 million for 2016. The decrease in administrative expenses was primarily due to consulting fee of RMB9.9 million, technical services fee of RMB7.6 million and legal fee of RMB4.5 million for potential project acquisition in 2015.

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

Impairment charges

Due to significant lower global oil prices in 2016, the Group recognized: (i) impairment charge amounting to RMB150.3 million and RMB3.0 million on the long-live assets (including mineral extractions rights) relating to assets in the PRC and North America respectively, to reflect their carrying value to the respective estimated recoverable amount calculated based on value-in-use; and (ii) an impairment charge amounting to RMB81.3 million on the investment in PetroBroad.

Other (losses)/income

The Group incurred other income of RMB297.8 million for 2016, compared to other loss of RMB47.9 million for 2015. Other income for 2016 arose primarily from: (i) gain on disposal of AGE of RMB526.1 million in July 2016; (ii) gains arising from acquisition of Journey of RMB29.8 million; (iii) provision for bad debts of RMB252.8 million due to long aging receivables and less collectibility; and (iv) losses on derivative financial instruments of RMB19.6 million. Other loss for 2015 includes mainly: (i) provision for bad debts of RMB84.4 million; (ii) gain on acquisition of Condor 20% equity interest and debt restructure between Condor, PEDEVCO Corp. and MIE Jurassic Energy Corporation of RMB29.4 million.

Finance income/(costs), net

The Group’s finance income decreased by RMB2.1 million, or 10.7%, from RMB19.6 million for 2015 to RMB17.5 million for 2016.

Finance cost decreased by RMB37.4 million, or 8.5%, from RMB441.4 million for 2015 to RMB404.0 million for 2016.

Share of profit of associate

The Group holds a 34.0% interest in PetroBroad which was purchased in May 2016, 37.4% interest in Journey which was purchased in September 2016, and 40.0% in PBV (60.0% of which was sold in November 2016). These investments are accounted for as associates by the Group and our share of profit of amounted to RMB35.7 million in 2016.

Share of loss of joint ventures

The Group held a 51% interest in SGE before July 2016. This investment was accounted for as a joint venture by the Group and our share of loss of SGE decreased for the period from RMB26.6 million in 2015 to RMB3.4 million for January to July 2016. This is mainly due to lower losses incurred by SGE as SGE realized pilot gas sales in 2016.

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

Loss before income tax

The Group’s loss before income tax was RMB458.0 million for 2016, compared to the loss before income tax of RMB1,467.3 million for 2015. This was primarily due to the cumulative effects of the above factors.

Income tax expense

The Group recorded an income tax expense of RMB147.2 million for 2016, compared to an income tax credit of RMB121.1 million for 2015. This change was primarily due to (i) the tax from the gain on disposal of Pan-China Resources Ltd. in 2014 and AGE in 2016 of RMB63.8 million and RMB54.1 million respectively; and (ii) the increase in loss before income tax in 2016. The effective tax rate for 2016 is -32% compared to an effective tax rate for 2015 of 8%.

Loss for the year from continuing operations

As a result of the foregoing, our net loss for 2016 was RMB605.1 million, compared to a net loss of RMB1,346.1 million for 2015.

Loss for the year from discontinued operations

The Group’s net loss for 2016 from discontinued operations was RMB717.1 million, representing the net loss from our Kazakhstan operations, which is recognized as a disposal group and discontinued operation, compared to the net loss of RMB179.1 million for 2015. This change was primarily due to: (i) loss from disposal of 60% equity interest in PBV of RMB358.7 million; (ii) impairment of oil & gas property and intangible assets of RMB335.6 million for 2016, compared to the RMB233.9 million for 2015; and (iii) a foreign exchange gain of RMB85 million recorded in 2015 as net result of the devaluation of the Tenge.

Loss for the year

The Group’s net loss for 2016 was RMB1,322.2 million, compared to the net loss of RMB1,525.3 million for 2015.

LIQUIDITY AND CAPITAL RESOURCES

Overview

The Group’s primary sources of cash during 2016 were cash generated from investing activities.

In 2016, we had net cash used in operating activities of RMB370.9 million, net cash generated from investing activities of RMB1,790.7 million, net cash used in financing activities of RMB750.3 million, an exchange gain on cash and cash equivalent of RMB32.4 million, and a net increase in cash and cash equivalent of RMB669.6 million.

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

Cash used in/generated from operating activities

Net cash used in operating activities was RMB370.9 million in the year ended December 31, 2016. In the year ended December 31, 2016, our net cash used in operating activities included loss before income tax of RMB458.0 million adjusted for, depreciation, depletion and amortization of RMB363.9 million, net interest expenses of RMB362.6 million, provision for bad debt of RMB252.8 million, gains arising from acquisition of Journey of RMB29.8, employee share option of RMB28.0 million, share of loss from investments in associates of RMB35.7 million, exchange loss of RMB23.9 million, impairment charge of RMB234.7 million, loss on oil hedge options of RMB19.6 million, which was offset by gains on disposal of AGE of RMB526.1 million. The cash movements from changes in working capital which included increase in trade and other payables of RMB65.5 million, an increase in trade and other receivables of RMB123.0 million and an increase in inventories of RMB4.6 million, and interest paid of RMB383.0 million and income tax paid of RMB69.6 million, and net cash used in discontinued operations of RMB81.1 million.

Net cash generated from operating activities was RMB326.1 million in the year ended December 31, 2015. In the year ended December 31, 2015, our net cash generated in operating activities included loss before income tax of RMB1,467.3 million adjusted for, depreciation, depletion and amortization of RMB520.2 million, net interest expenses of RMB387.7 million, provision for bad debt of RMB84.4 million, employee share option of RMB22.1 million, share of loss from investments in joint ventures of RMB26.6 million, exchange loss of RMB34.0 million, impairment charge of RMB765.0 million, offset by gains on write-off payables of RMB29.4 million. The cash movements from changes in working capital which included decrease in trade and other payables of RMB161.4 million, a decrease in trade and other receivables of RMB298.6 million and a decrease in inventories of RMB0.1 million, and interest paid of RMB337.9 million and income tax paid of RMB9.1 million, and net cash generated from discontinued operations of RMB192.2 million.

Cash generated from/used in investing activities

Net cash generated from investing activities in the year ended December 31, 2016 amounted to RMB1,790.7 million, as a result of receipts of proceeds from disposal of subsidiaries of RMB2,283.7 million, decrease in restricted cash of RMB462.6 million, and interest received of RMB20.2 million, which was offset by purchases of property, plant and equipment of RMB21.6 million, increase in financial assets of RMB96.4 million, loan and deposit to third parties of RMB375.0 million, contribution and loans to/acquisition of investments accounted for using equity method of RMB277.0 million, and net cash used in discontinued operations of RMB205.7 million.

Net cash used in investing activities in the year ended December 31, 2015 amounted to RMB1,124.4 million, as a result of purchases of property, plant and equipment of RMB249.6 million, deposit paid to third parties of RMB48.5 million, contribution and loans to/acquisition of investments accounted for using equity method of RMB186.1 million, increase in restricted cash of RMB324.1 million, net cash outflow from

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APPENDIX I

discontinued operations of RMB390.1 million, offset by proceeds from disposal of RMB45.2 million, decrease in financial assets of RMB28.3 million, and interest received of RMB0.065 million.

Cash used in/generated from financing activities

Net cash used in financing activities in the year ended December 31, 2016 amounted to RMB750.3 million primarily due to: (i) repayments of borrowings of RMB930.2 million, (ii) payments relating to share-based compensation of RMB63.7 million, (iii) payment for repurchase and cancellation of 2019 Notes RMB110.7 million, (iv) cash paid to non-controlling interest for additional interest in subsidiary of RMB103.9 million, (v) financing expenses and others of RMB33.2 million, offset by proceeds from borrowings of RMB491.5 million.

Net cash generated from financing activities in the year ended December 31, 2015 amounted to RMB298.0 million primarily due to: (i) proceeds from issuance of ordinary shares of RMB200.0 million, (ii) proceeds from borrowings of RMB512.8 million; and offset by:(i) payments relating to share-based compensation RMB28.7 million, (ii) repayments of borrowings of RMB360.1 million, (iii) financing expenses and others of RMB25.9 million.

As at December 31, 2016, the Group’s bank borrowings and Senior Notes amounted to approximately RMB4,690.6 million, representing a decrease of approximately RMB263.5 million as compared to December 31, 2015. Among which, borrowings repayable within one year amounted to approximately RMB104.0 million, representing a decrease of RMB425.9 million as compared to December 31, 2015. All of the Group’s bank borrowings and Senior Notes are denominated in RMB and United States Dollars. The Group’s bank borrowings and Senior Notes are all at fixed interest rates. No hedging instruments are used for bank borrowings and Senior Notes.

Our gearing ratio, which is defined as total borrowings less cash and cash equivalents (‘‘Net Borrowings’’) divided by the sum of Net Borrowings and total equity, increased from 68.2% as at December 31, 2015 to 85.5% as at December 31, 2016, principally due to a decrease in equity.

Our total borrowings to Adjusted EBITDA ratio, which is defined as total borrowings divided by Adjusted EBITDA increased from 14.14 as at December 31, 2015 to 16.56 as at December 31, 2016.

Borrowings

The carrying amount of borrowing are denominated in the following currencies: (i) RMB104.0 million worth of borrowing in RMB; and (ii) RMB4,586.6 million worth of Senior Notes in US Dollars.

The Group has no undrawn banking facilities expiring within one year.

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APPENDIX I

Market Risks

Our market risk exposures primarily consist of fluctuations in oil prices and exchange rates.

Oil price risk

Our realized oil prices are determined by reference to oil prices in the international market, changes in international oil prices will have a significant impact on us. Unstable and highly volatile international oil prices may have a significant impact on our revenue and profit. During 2016, the Group entered into oil hedge options contracts to manage its price risk.

Currency risk

The Group currently does not engage in hedging activities designed or intended to manage foreign exchange rate risk. The Group will continue to monitor foreign exchange changes to best preserve the Group’s cash value.

CHARGES ON GROUP ASSETS

As at December 31, 2016, a bank loan in the sum of RMB104.0 million was secured by the Group’s trade receivable of RMB84.7 million. On March 24, 2017, the Group repaid the loan in full.

PROVISION OF LOAN

On December 16, 2016, the Company entered into a loan agreement with BostonPower, Inc., (the ‘‘Borrower’’), pursuant to which the Company agreed to grant a loan of US$30 million to the Borrower for a term of six months at an interest rate of 9% per annum. Subsequent to December 31, 2016 and up to the date of this announcement, US$30 million was drawn by the Borrower. The loan is secured by a pledge over 50% of the shareholding of an indirectly wholly-owned subsidiary of the Borrower.

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

Details of the transaction are set out in the announcement of the Company dated December 19, 2016.

EMPLOYEES

As at December 31, 2016, the Company had 1,387 employees, with 1,371 based in China (Mainland and Hong Kong), 11 based in Kazakhstan and five based in USA. There have been no material changes to the information disclosed in the Annual Report 2015 in respect of the remuneration of employees, remuneration policies and staff development.

The share option scheme adopted by the Company was approved by shareholders on November 27, 2010 in accordance with Chapter 17 of the Listing Rules. The purpose of the Scheme is to enable the Company to grant options to selected participants as incentives or rewards for their contributions to the Group.

Apart from the above plan and scheme, to recognize the contributions by certain grantees and to give incentives thereto in order to retain them for the continuing operation and development of the Group, and to attract suitable personnel for further development of the Group, the Board of Directors resolved to adopt the 2015 Share Award Scheme on January 6, 2015.

CONTINGENCIES

On August 28, 2000, MIE entered into a PSC with Sinopec for exploration and development of the Shengli oilfield in Shandong Province. In 2000, MIE began the trialdevelopment phase of its operations at the Shengli oilfield and drilled a dry hole. The project has been suspended since the end of 2004. In April 2005, MIE requested an extension from Sinopec to restart the project at the Shengli oilfield. On September 27, 2006, MIE received a letter from Sinopec denying the request to restart the project and seeking to terminate the PSC on the grounds that the extension period of the trialdevelopment phase had expired and MIE had not met its investment commitment of at least USD2 million under the PSC. MIE believes its investment in the project at Shengli oilfield had met the required commitment amount under the PSC. The PSC with Sinopec has not been formally terminated and the dispute has not entered any judicial proceedings. As advised by the external legal counsel of the Company, the probability of claim from Sinopec for unfulfilled investment commitment, if any, in relation to the pilotdevelopment phase is remote as the statute of limitations has run out.

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

FUTURE PLANS FOR MATERIAL INVESTMENTS OR CAPITAL ASSETS AND THEIR EXPECTED SOURCES OF FUNDING IN THE COMING YEARS

Despite the recent recovery in oil prices, the challenges that the Group has faced still persist. Since the Group’s initial public offering in Hong Kong in 2010, the Group have maintained close ties with the international capital market and created returns for market participants. The Group are cognizant that our bondholders are paying close attention to both bonds which are due in 2018 and 2019, and the Group will spend utmost efforts in 2017 to balance both the development of the Company and the optimization of our capital structure.

BUSINESS REVIEW AND PROSPECTS

In the first half of 2017 (‘‘1H2017’’ or the ‘‘Current Period’’), MIE Holdings Corporation (the ‘‘Company’’), together with its subsidiaries (collectively, the ‘‘Group’’), continued its strategy of controlling capital expenditure and enhancing operational efficiency, in response to the continually low international crude oil prices and in 1H2017, the gas and oil operational production and net production of the Group decreased sharply compared with the same period in 2016. The Group’s oil and gas production decreased by 30.6% to about 2.4 million barrels of oil equivalent (‘‘BOE’’) compared with the first half of 2016 (‘‘1H2016’’ or the ‘‘Prior Period’’). Net oil gas production decreased by 45.9% to about 1.0 million BOE compared with the Prior Period. During the Current Period, our crude oil sales decreased by 40.9% to approximately 1.0 million barrels from the Prior Period, while our natural gas sales decreased to 9.6 million standard cubic feet (‘‘MMscf’’). After the disposal of 60% equity interest of Emir-Oil LLP, a wholly-owned subsidiary of the Group in Kazakhstan, in the second half of 2016, the Group became a non-controlling shareholder of Emir-Oil LLP, therefore, operational production volume, net production, crude oil sales in 1H2017 from Emir-Oil LLP were not consolidated with the corresponding items of the Group. Excluding the impact of the Kazakhstan project, the Group’s operational production volume, net production and crude oil sales decreased by 10.6%,8.0% and 5.2% respectively. The average realized crude oil price of the Group increased by 41.7 % to US$47.1 per barrel, with average natural gas prices rising to US$4.68 per thousand metric cubic feet (‘‘Mscf’’). As crude oil prices rebounded, the sales revenue realized during 1H2017 increased by 46.6% to RMB336.4 million compared with the Prior Period. EBITDA recorded a loss of RMB236.8 million, and the loss amount increased RMB77.5 million as compared to the Prior Period. The adjusted EBITDA increased by 133.1% to approximately RMB205.1 million in the Current Period. During the Current Period, the Group recorded a net loss of RMB673.5 million.

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

The following table sets out a summary of the expenditures incurred in our exploration, development and production activities for the six months ended June 30, 2017:

(millions of RMB) China (Daan, Moliqing) USA (Condor) Total	Exploration expenditures — — —	Development expenditures 23 — 23	Production/ operating expenditures 42 1
			43

The Group incurred development expenses of RMB23 million for the six months ended June 30, 2017, all of which were expenses incurred in China; the production expenses amounted to RMB43 million, of which RMB42 million was spent on projects in China and RMB1 million on projects in USA.

China operation (Daan, Moliqing, South China Sea)

In relation to the Daan project and Moliqing project, the Group plans to drill 17 wells in 2017, including 15 wells in Daan and two wells in Moliqing, and nine of them have been completed In 1H2017. Net daily production decreased by 7.28% to 5,590 barrels per day from 6,029 barrels per day in 1H2016, mainly due to the natural decline of oil reservoirs. Considering a 11.01% drop in net production in 1H2016 from 1H2015, net production decline has slowed in 1H2017. We forecast that the total annual net production of China’s domestic projects in 2017 will be in line with our guidance for 2017.

In relation to the South China Sea project, China National Offshore Oil Corp. (‘‘CNOOC’’) has been engaged to compile a reserve report and an overall development plan (‘‘ODP’’) in preparation for the development. The first draft of reserve report was ready in July. The ODP is being compiled and expected to be completed by December 2018. A successful development of the block will help the Group gain experience in operating offshore oil fields.

USA Operations (Condor)

During the Current Period, the average daily production of crude oil was 30 barrels per day, having decreased by 25.0% from 44 barrels per day in the Prior Period and the daily average natural gas production was 17 Mscf per day, having decreased by 70.7% from 58 Mscf per day in the Prior Period. Two wells were suspended due to gas engine problems.

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

Kazakhstan Operations (Emir-Oil)

One exploration well is planned to be drilled during 2017 in relation to the Emir-Oil project in Kazakhstan. The drilling of this well was in the preparation stage as at the end of June 30, 2017 and is planned to be drilled in the second half of 2017. With the recovery of oil price, three production wells have been opened again and the total number of producing wells in 1H2017 is 17.

Canada Operations (Journey)

Journey Energy Inc. plans to drill 14 wells in 2017, with four wells having been completed in 1H 2017. Daily production increased by 18% to 10,194 barrels per day from 8,640 barrels per day in Prior Period. The group generated investment income of RMB10.9 million in 1H2017.

Overall, as at the end of June 2017, the Group’s main oilfield projects were located in Northeastern China, and the free cash flow contributed by these projects is critical in supporting the Group’s other projects. In 1H2017, our oil fields in Northeastern China continued to maintain high production levels through the implementation of new advanced techniques, as well as optimization of conventional drilling methods in Kazakhstan as an important shareholder in the Emir-Oil LLP joint venture, we are also actively promoting the construction of new wells to further increase their production capacity.

As part of its strategy of rebuilding its asset portfolio and creating value for its investors as oil prices remain low, the Group constantly evaluates strategic investment opportunities globally and is particularly drawn by Canada’s vast oil and natural gas resources.

On June 9, 2017, the Group announced its proposed very substantial acquisition of 100% partnership interests in a Canadian corporation, CQ Energy Canada Partnership (‘‘CQ Company’’), for a consideration of C$722,000,000 equivalent to approximately HK$4,176,336,800. The consideration represents multiples of C$2.1/BOE (EV/2P), being the consideration divided by the total proved and probable reserves.

The CQ Company owns a diverse base of producing, resource and infrastructure portfolio located throughout the Western Canadian Sedimentary and Williston basins in Alberta, Saskatchewan, Manitoba, Ontario and British Columbia in Canada. The CQ Company also has a high working interest in all its key assets. Its portfolio also includes midstream infrastructure assets in active areas including Ferrier, Hanlan, Carrot Creek and Wildcat Hills. Currently, the CQ Company has ownership in 11 major facilities including three sweet and eight sour plants with net processing capacity of 630 MMscf per day. The CQ Company has an average working interest (average percentage of ownership) of 67% in the relevant assets and properties in relation to its oil and gas reserves, which as of June 6, 2017 covered an area with gross land coverage of 3,492,600 acres (or net coverage of 2,200,814 acres).

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

The CQ Company possesses natural gas resources producing low decline, long life asset base products and infrastructure. It has vast acreage of undeveloped land and has potential for growth. Furthermore, the CQ Company’s prolific assets have been able to generate positive EBITDA/netback under current oil and gas prices. Most of its assets are natural gas assets, and the impact of low oil prices on income is very limited. With the rise of the number of natural gas export projects in western Canada, the potential for future growth is expected. The said acquisition will provide the Group with a clear direction to enhance the Group’s ability in the development of natural gas resources in Canada and to provide advantages for the Group to participate more effectively in the rapidly expanding Canadian natural gas exploration and development projects.

The consideration will be funded through a combination of the Group’s internal resources, debt or equity financing and proceeds to be raised from convertible preferred shares.

For further details, please refer to the announcement of the Company dated 9 June 2017.

OUTLOOK FOR 2017

High production by the Organization of the Petroleum Exporting Countries (the ‘‘OPEC’’), US shale and non-OPEC suppliers created an unprecedented global glut that has driven oil prices lower since 2014, and long-term stay at low levels. In 1H2017, West Texas Intermediate (the ‘‘WTI’’) oil prices have been fluctuating in the range of 42 to 52 US dollars per barrel. With the OPEC controlling crude oil production, crude oil prices, the oil and gas industry and the global economy are expected to rebound moderately in the second half of 2017, but due to the increase of US shale gas production and the number of drilling rigs, there remains a high level of uncertainty and potential volatility with respect to global oil prices. When operating in such a challenging macro environment, the Group will focus on its ability to remain flexible and to react promptly to drastic changes.

The ability to develop natural gas in Canada will be further enhanced due to the acquisition of the CQ Company. Upon the successful completion of the acquisition of the CQ Company in the second half of the year, the CQ Company’s financial statements will be consolidated into the Group’s consolidated financial statements, and the CQ Company will become an important part of the Group and enhance the Group’s financial stability and strength. It is expected that the Group’s revenue and EBITDA will increase substantially in the second half of 2017, while the Group’s total revenue from overseas projects will increase significantly. The business structure, personnel composition and management methods of the Group will be more international in future, which are beneficial to the widening of our global footprint, development of a more balanced oil and gas business portfolio, expansion of our operational capabilities and elevation of our profile and image as an international energy company.

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

REVIEW OF OPERATING RESULTS

Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016

Revenue

The Group’s revenue increased by RMB107.0 million, or 46.6%, from RMB229.4 million for the six months ended June 30, 2016 to RMB336.4 million for the six months ended June 30, 2017.

This increase was mainly due to the increase in crude oil prices over the same period. Average realized oil price was US$47.10 per barrel for the six months ended June 30, 2017, compared to US$32.16 per barrel for the six months ended June 30, 2016.

. China

During the six months ended June 30, 2017, our China oil fields realized revenue of RMB334.6million, including RMB332.6 million, RMB0.4 million and RMB1.6 million from oil sales, gas sales and services respectively.

The average realized oil price was US$47.10 per barrel for the six months ended June 30, 2017, compared to US$32.15 per barrel for the six months ended June 30, 2016. Our sales volume was 1.03 million barrels for the six months ended June 30, 2017, compared to 1.08 million barrels for the six months ended June 30, 2016.

. North America

During the Current Period, our North America oil fields realized revenue from crude oil sales of RMB1,755.0 thousand. The average realized oil price was North America US$46.85 per barrel, with sales volume of 5,461 barrels. During the six months ended June 30, 2016, our North America oil fields realized revenue from crude oil sales of RMB1.8 million. The average realized oil price was US$33.75 per barrel, with a sales volume of 7,991 barrels for the six months ended June 30, 2016.

North America operations realized revenue from gas sales of RMB28.4 thousand, with a realized gas price of US$4.68 per Mscf and total gas sales volume of 886 Mscf for the six months ended June 30, 2017. The realized revenue from gas sales of RMB49.7 thousand, with realized gas price of US$1.51 per Mscf and total gas sales volume of 5,038 Mscf was recorded for the six months ended June 30, 2016.

Operating expenses

. Depreciation, depletion and amortization. The Group’s depreciation, depletion and amortization increased by RMB19.0 million, or 12.0%, from RMB157.9 million for the six months ended June 30, 2016 to RMB176.9 million for the six months ended June 30, 2017. The increase in depreciation, depletion and amortization was mainly due to there being no depreciation, depletion and amortization expenses recorded for

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FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

the six months ended June 30, 2016 for Riyadh Energy Limited’s (‘‘Riyadh’’) property, plant and equipment and intangible assets after Riyadh’s assets and liabilities were reclassified as ‘‘held for sale’’.

. Taxes other than income taxes. The Group’s taxes other than income taxes increased by RMB1.4 million, or 21.5%, from RMB6.5 million for the six months ended June 30, 2016 to RMB7.9 million for the six months ended June 30, 2017. The following table summarizes the Group’s taxes other than income taxes for the six months ended June 30, 2017 and 2016:

PRC Urban construction tax and education surcharge Others Corporate and other segments Withholding tax and others	Six months ended June 30, 2017 2016 RMB’000 RMB’000 1,755 1,196 43 50 1,798 1,246 6,137 5,278 7,935 6,524	Six months ended June 30, 2017 2016 RMB’000 RMB’000 1,755 1,196 43 50 1,798 1,246 6,137 5,278 7,935 6,524
		1,246
		5,278
		6,524

China

The Ministry of Finance of the People’s Republic of China (‘‘MOF’’) has decided to increase the threshold of the special oil income levy from US$55 to US$65 per barrel, effective from January 1, 2015. As no sales were realized at or above US$65 per barrel during the Current Period, no special oil levy was incurred.

Corporate and other segments

Withholding Tax

Withholding tax represents accrual of withholding tax on interest charged on intercompany loans.

. Employee compensation costs. The Group’s employee compensation costs decreased by RMB2.7 million, or 4.3%, from RMB63.4million for the six months ended June 30, 2016 to RMB60.7 million for the six months ended June 30, 2017. The decrease in employee compensation costs was primarily due to a reduction in the total number of personnel for the six months ended June 30, 2017.

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APPENDIX I

. Purchases, services and other expenses. Our purchases, services and other expenses decreased by RMB4.8 million, or 9.9%, from RMB48.7 million for the six months ended June 30, 2016 to RMB43.9 million for the six months ended June 30, 2017. The decrease in purchase, services and other expenses was primarily due to: (i) the decrease of production and sales volumes during Current Period; and (ii) the stringent cost control measures implemented by the Group.
. Distribution and administrative expenses. The Group’s distribution and administrative expenses increased by RMB18.6 million, or 49.7%, from RMB37.4 million for the six months ended June 30, 2016 to RMB56.0 million for the six months ended June 30, 2017. The increase in distribution and administrative expenses was primarily due to expenses incurred in relation to acquisition of the CQ Company of RMB18.3 million.
. Impairment. For the six months ended June 30, 2017, the Group has recognized an impairment charge amounting to RMB3.4 million on investment in PetroBroad Copower Limited (‘‘PetroBroad’’), compared to total impairment of RMB196.1 million for the six months ended June 30, 2016, which decreased by RMB192.7 million, or 98.3%, mainly due to: (i) lower global oil prices for the six months ended June 30, 2016 and made impairment charge amounting to RMB150.2 million and RMB3.0 million on the long-live assets (including mineral extractions rights) relating to assets in the PRC and North America, respectively, to reflect their carrying value to the respective estimated recoverable amount calculated based on value-in-use; (ii) an impairment charge amounting to RMB42.9 million on investment in PetroBroad for the six months ended June 30, 2016.
. Other loss, net. The Group had net other losses of RMB412.0 million for the six months ended June 30, 2017, compared to other income of RMB33.7 million for the six months ended June 30, 2016. Other losses for the six months ended June 30, 2017 arose primarily from: (i) provisions for receivables amounting to RMB422.0 million due to long aging of receivables and lower collectability; and (ii) losses on disposal of available-for-sale financial assets of RMB22.2 million; partially offset by: (i) gains on change in fair value of derivative financial instruments amounting to RMB20.8 million; and (ii) tax refund from tax department of RMB7.2 million.

Finance costs, net

The Group’s net finance cost increased by RMB27.5 million, or 16.1%, from RMB170.5 million for the six months ended June 30, 2016 to RMB197.9 million for the six months ended June 30, 2017. The increase in finance cost was mainly due to: (i) amortizing costs for Global Oil Corporation (‘‘GOC’’) receivables of RMB24.4 million, compared to a negative amortizing cost of RMB7.1 million for the six months ended June 30, 2016; (ii) financing costs of RMB6.3 million incurred on a loan from Strong Petrochemical Limited; (iii) amortization of discounts of RMB0.6 million arising from a loan from Brilliant Shine; and which were partially offset by an increase of exchange gain

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APPENDIX I

amounting to RMB14.8 million. Finance income was RMB21.8 million for the six months ended June 30, 2017 compared to RMB10.9 million for the six months ended June 30, 2016.

Share of loss of associate

As at June 30, 2017, the Group held a 34% interest in PetroBroad, 32.13% interest in Journey Energy Inc. (‘‘Journey’’) and 40% interest in PBV, respectively. These investments are accounted as associates by the Group and our share of profit amounted to RMB10.9 million for the six months ended June 30, 2017.

Loss before income tax

The Group’s loss before income tax was RMB611.6 million for the six months ended June 30, 2017, compared to the loss before income tax RMB487.7 million for the six months ended June 30, 2016, representing an increase of RMB123.9 million, or 25.4%. This increase was primarily due to the cumulative effects of the above factors.

Income tax expense

The Group recorded income tax expense of RMB62.0 million for the six months ended June 30, 2017, compared to income tax expense of RMB66.6 million for the six months ended June 30, 2016, representing a decrease of RMB4.6 million, or 6.9%. The effective tax rate for the six months ended June 30, 2017 was –10%, compared to the effective tax rate for the six months period ended June 30, 2016 of –14%.

Loss for the period

The Group’s loss for the six months ended June 30, 2017 was RMB673.5 million, compared to the loss of RMB1,399.2 million for the six months ended June 30, 2016, having decreased by RMB725.7 million, or 51.9%. This decrease was primarily due to the loss from discontinued operations of RMB844.9 million included in the six months ended June 30, 2016 and the cumulative effects of the above factors.

EBITDA AND ADJUSTED EBITDA

We provide a reconciliation of EBITDA and adjusted EBITDA to loss for the Current Period, with our most directly comparable financial performance calculated and presented in accordance with IFRS. EBITDA refers to earnings before finance income, finance costs, income tax and depreciation, depletion and amortization. Adjusted EBITDA refers to EBITDA adjusted to exclude non-cash and non-recurring items such as sharebased compensation expense, assets impairment loss, (gains)/losses on changes in fair value of derivative financial instruments, provisions for receivables, geological and geophysical expense, withholding tax arising from intercompany loan, gains on write-off payables, losses from disposal of available-for-sale financial assets and any other noncash or non-recurring income/expenses.

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APPENDIX I

We have included EBITDA and adjusted EBITDA as we believe EBITDA is a financial measure commonly used in the oil and gas industry. We believe that EBITDA and adjusted EBITDA are used as supplemental financial measures by our management and by investors, research analysts, bankers and others, to assess our operating performance, cash flow and return on capital as compared to those of other companies in our industry, and our ability to take on financing. However, EBITDA and adjusted EBITDA should not be considered in isolation or construed as alternatives to profit from operations or any other measure of performance or as an indicator of our operating performance or profitability. EBITDA and adjusted EBITDA fail to account for tax, finance income, finance costs and other non-operating cash expenses. EBITDA and adjusted EBITDA do not consider any functional or legal requirements of the business that may require us to conserve and allocate funds for any purposes.

The following table presents a reconciliation of EBITDA and adjusted EBITDA (for continuing operations only) to loss before income tax for each period indicated.

Loss before income tax Finance income Finance costs Depreciation, depletion and amortization EBITDA Value of employee services under stock option schemes Impairment (Gains)/losses on changes in fair value of derivative financial instruments Geological and geophysical Withholding tax Provisions for receivables Losses on disposal of available- for-sale financial assets Others Adjusted EBITDA	Six months ended June 30, 2017 2016 RMB’000 RMB’000 (611,558) (487,714) (21,756) (10,895) 219,676 181,436 176,872 157,918 (236,766) (159,255) 13,122 9,282 3,430 196,154 (20,802) 12,251 — 1,227 6,137 5,278 422,005 23,040 22,190 — (4,249) — 205,067 87,977

The Group’s EBITDA decreased by approximately RMB77.5 million, or 48.7%, from approximately negative RMB159.3 million for the six months ended June 30, 2016 to approximately negative RMB236.8 million for the six months ended June 30, 2017. The decrease was due to: (i) the decrease in sales volume; (ii) provisions for receivables amounting to RMB422.0 million during the six months ended June 30, 2016; (iii)loss on disposal of available-for-sale financial assets of RMB22.2 million; and (iv) employee stock option compensation cost increased by RMB3.8 million due to new stock option issued and shares awarded on December 9, 2016; which was offset by: (i) the increase in

– I-54 –

FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

realized oil price; (ii) impairment decreased by RMB192.8 million as compared to the first half year of 2016; and (iii) gains on changes in fair value of derivative financial instruments of RMB20.8 million.

The Group’s adjusted EBITDA increased by approximately RMB117.1 million, or 133.1%, from approximately RMB88.0 million for the six months ended June 30, 2016 to approximately RMB205.1 million for the six months ended June 30, 2017. The increase in adjusted EBITDA was also due to: (i) the increase in realized oil price resulted in revenue increased by RMB107.0 million; and (ii) share of profits of investments accounted for using the equity method increased by RMB13.7 million.

The Group’s EBITDA and Adjusted EBITDA by operating segment for the six months ended June 30, 2016 and 2017 are set out below:

Loss before income tax
Finance income
Finance costs
Depreciation, depletion and
amortization
EBITDA
Value of employee services
under stock option
schemes
Impairment
Gains on changes in fair
value of derivative
financial instrument
Withholding tax
Provisions for receivables
Losses on disposal of
available- for-sale
financial assets
Others
Adjusted EBITDA

Six months ended June 30, 2017
PRC
North
America
Corporate
Total
RMB’000
RMB’000
RMB’000
RMB’000
(7,953)
9,473
(613,078)
(611,558)
(230)
(5)
(21,521)
(21,756)
34,070
(13,391)
198,997
219,676
175,905
878
89
176,872
201,792
(3,045)
(435,513)
(236,766)
2,310
—
10,812
13,122
—
—
3,430
3,430
—
—
(20,802)
(20,802)
—
190
5,947
6,137
40,363
—
381,642
422,005
—
—
22,190
22,190
(2,719)
—
(1,530)
(4,249)
241,746
(2,855)
(33,824)
205,067

– I-55 –

FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

Loss before income tax
Finance income
Finance costs
Depreciation, depletion and
amortization
EBITDA
Value of employee services
under stock options
schemes
Impairment
Losses from changes in fair
value of derivative
financial instrument
Geological and geophysical
Withholding tax
Provisions for receivables
Adjusted EBITDA

Six months ended June 30, 2016
PRC
North
America
Corporate
Total
RMB’000
RMB’000
RMB’000
RMB’000
(183,632)
(4,840)
(299,242)
(487,714)
(591)
(2,665)
(7,639)
(10,895)
10,917
7
170,512
181,436
155,922
1,770
226
157,918
(17,384)
(5,728)
(136,143)
(159,255)
1,643
—
7,639
9,282
150,245
3,030
42,879
196,154
—
—
12,251
12,251
—
—
1,227
1,227
—
—
5,278
5,278
—
—
23,040
23,040
134,504
(2,698)
(43,829)
87,977

LIQUIDITY AND CAPITAL RESOURCES

Overview

Our primary source of cash during the six months ended June 30, 2017 was cash generated from financing activities.

In 1H2017, we had net cash generated from operating activities of RMB53.0 million, net cash used in investing activities of RMB642.2 million and net cash generated from financing activities of RMB861.6 million and a translation loss for foreign currency exchange of RMB20.2 million, resulting in a net increase in cash and cash equivalent of RMB252.2 million compared to the cash balance of RMB905.0 million as at December 31, 2016.

Cash generated from/(used in) operating activities

Net cash generated from operating activities was RMB53.0 million for the six months ended June 30, 2017.In 1H2017, our net cash used in operating activities included a loss before income tax of RMB611.6 million adjusted for, among other things, depreciation, depletion and amortization of RMB176.9 million, net interest expenses of

– I-56 –

FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

RMB212.7 million, an unrealized foreign exchange gain of RMB14.8 million, an impairment loss on assets of RMB3.4 million, gains on changes in fair value of derivative financial instruments of RMB20.8 million, value of employee services under stock option scheme of RMB13.1 million, losses on disposal of available-for-sale financial assets of RMB22.2 million, share of profits from investments accounted for using the equity method of RMB10.9 million, provisions for receivables of RMB422.0 million and others of RMB4.2 million. The cash movements from changes in working capital in the six months ended June 30, 2017 included a decrease in trade and other receivables of RMB44.6 million; a decrease in trade and other payables of RMB11.2 million; a decrease in inventories of RMB2.9 million; interest paid of RMB171.2 million and income tax paid of RMB0.2 million.

Net cash used in operating activities was RMB223.7 million for the six months ended June 30, 2016.In 1H2016, our net cash used in operating activities included a loss before income tax of RMB487.7 million adjusted for, among other things, depreciation, depletion and amortization of RMB157.9 million, net interest expenses of RMB163.0 million, an unrealized foreign exchange loss of RMB7.6 million, an impairment loss on assets of RMB196.2 million, loss from changes in fair value of derivative financial instruments of RMB12.3 million, value of employee services under stock option scheme of RMB9.3 million, share of loss from investments accounted for using the equity method of RMB2.8 million and provision for bad debt of RMB23.0 million. The cash movements from changes in working capital in the six months ended June 30, 2016 included an increase in trade and other receivables of RMB112.5 million; a decrease in trade and other payables of RMB3.1 million; an increase in inventories of RMB6.6 million; interest paid of RMB189.5 million; income tax paid of RMB5.5 million and cash generated from discontinued operations of RMB9.1 million.

Cash (used in)/generated from investing activities

Net cash used in investing activities for the six months ended June 30, 2017 amounted to RMB642.2 million, mainly as a result of purchases of: (i) property, plant and equipment of RMB38.4 million, (ii) Contribution and loans to/acquisition of investments accounted for using the equity method of RMB24.0 million, (iii) net cash flow from investment in available-for-sale financial assets of RMB115.2 million, (iv) an increase in restricted bank deposits of RMB44.9 million, (v) loans and deposits to third parties of RMB104.2 million, (vi) deposit for acquiring of RMB365.0 million and (vii) others of RMB41.2 million, offset by proceeds from disposal of derivative financial instruments of RMB90.7 million.

Net cash generated from investing activities for the six months ended June 30, 2016 amounted to RMB625.3 million, mainly as a result of purchases of: (i) property, plant and equipment of RMB37.7 million, (ii) capital investment in associate accounted for using the equity method of RMB43.5 million, (iii) net cash flow from investment in available for sale financial assets of RMB3.0 million, (iv) loans to investments accounted for using the equity method of RMB13.0 million, (v) acquisition of non-controlling interests of RMB90.5 million, (vi) net cash flow from investment in derivative financial instruments of RMB97.3 million, and (vii) cash used in investing activities in discontinued operations

– I-57 –

FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

of RMB118.6 million, offset by: (i) a decrease in restricted bank deposits of RMB412.9 million, (ii) proceeds from disposal of subsidiaries of RMB595.8 million, and (iii) interest received of RMB20.2 million.

Cash generated from/(used in) financing activities

Net cash generated from financing activities for the six months ended June 30, 2017 amounted to RMB861.6 million due to proceeds from borrowings of RMB1,162.1 million, offset by repayments of borrowings of RMB300.5 million.

Net cash used in financing activities for the six months ended June 30, 2016 amounted to RMB106.7 million due to proceeds from borrowings of RMB481.5 million, offset by: (i) payment to repurchase and cancellation of 2019 Notes of RMB110.7 million; (ii) repayments of borrowings of RMB463.2 million, and (iii) payment of loan arrangement and other fees of RMB14.3 million.

As at June 30, 2017, the Group’s borrowings and Senior Notes amounted to approximately RMB5,471.0 million, representing an increase of approximately RMB780.4 million as compared to December 31, 2016. Among which, borrowings repayable within one year amounted to approximately RMB1,341.8 million, representing an increase of RMB1,237.8 million as compared to December 31, 2016.

Our gearing ratio, which is defined as total borrowings less cash and cash equivalents (‘‘Net Borrowings’’) divided by the sum of Net Borrowings and total equity, increased from 85.5% as at December 31, 2016 to 99.4% as at June 30, 2017.

Our Total Borrowings to Adjusted EBITDA ratio, which is defined as total borrowings divided by Adjusted EBITDA decrease from 16.56 as at December 31, 2016 to 13.34 (annualized) as at June 30, 2017.

Borrowings

All of the Group’s borrowings and Senior Notes are denominated in US dollars. The Group’s borrowings and Senior Notes are all at fixed interest rates. No hedging instruments were used for borrowings and Senior Notes. The Group has no undrawn banking facilities.

Market Risks

Our market risk exposures primarily consist of fluctuations in oil prices and exchange rates.

– I-58 –

FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

Oil price risk

Currency risk

CHARGES ON GROUP ASSETS

As at 30 June 2017, the Group has a term loan with a third party in aggregate of US$147.0 million and the Company was as Guarantor. The loan is secured by a deposit in an escrow account, charge over shares in respect of the entire issued share capital of Gobi Energy Limited (a wholly-owned subsidiary of the Company) and the Group’s right to receive its share of revenue allocated and interests under Daan PSC. As at June 30, 2017, all facilities have been drawn down by Gobi Energy and the balance of deposit is US$6.6 million (equivalent to RMB44.9 million).

EMPLOYEES

As at June 30, 2017, the Company had 1,373 employees, with 1,371 based in China (Mainland and Hong Kong) and 2 based in USA. There have been no material changes to the information disclosed in the Company’s annual report 2016 in respect of the remuneration of employees, remuneration policies and staff development.

CONTINGENCIES

On August 28, 2000, MI Energy Corporation (‘‘MIE’’) entered into a production sharing contract (the ‘‘PSC’’) with Sinopec for the exploration and development of Luojiayi 64 block at the Shengli oilfield in Shandong Province, which has been suspended since the end of 2004. In April 2005, MIE requested an extension from Sinopec to restart the project. On September 27, 2006, MIE received a letter from Sinopec denying the request to restart the project and seeking to terminate the PSC on the grounds that the extension period of the trial-development phase had expired and MIE had not met its investment commitment under the PSC. The Company believes its investment in the project at Shengli oilfield had met the required commitment amount under the PSC. The

– I-59 –

FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

PSC with Sinopec has not been formally terminated and the dispute has not entered any judicial proceedings. As advised by the external legal counsel of the Company, the probability of claim from Sinopec for unfulfilled investment commitment, if any, in relation to the pilot- development phase is remote as the statute of limitations has run out.

C. STATEMENT OF INDEBTEDNESS

At the close of business on July 31, 2017, being the latest practicable date for the purpose of ascertaining the information contained in this statement of indebtedness, the Group had outstanding borrowings of approximately RMB4,267.9 million, comprising secured finance institution loans of approximately RMB968.9 million and interest bearing notes carrying at a book value of RMB3,299.0 million of which RMB1,212.4 million will be due within one year from July 31, 2017. The finance institution loans totaling RMB968.9 million are secured by the Group’s right to receive revenue allocated to the Group under Daan Production Sharing Contract (‘‘PSC’’) in the Daan oilfield located in Northeast region in the PRC during respective loan agreement periods.

Save as aforesaid or otherwise disclosed herein, and apart from intra-group liabilities and normal trade payables in the normal course of business, at the close of business on July 31, 2017, the Group did not have any other loan capital issued and outstanding or agreed to be issued, bank overdrafts, loans or other similar indebtedness, liabilities under acceptances or acceptable credits, debentures, mortgages, charges, finance lease commitments, guarantees or other contingent liabilities.

D. WORKING CAPITAL STATEMENT

The Directors are of the opinion that, after taking into account the present available financial resources to the Enlarged Group, including internally generated funds, cash and cash equivalents on hand, the cash flow impact of the Acquisition, other undrawn financing facilities amounting to RMB1,654.8 million presently available, and subject to:

(i) the proceeds of C$204,000,000 from the subscription of Convertible Preferred Shares by Gastown and Mercuria;
(ii) the C$190,000,000 committed Senior Secured Revolving Credit Facility to be provided by a syndicate of banks; and,
(iii) the US$100,000,000 committed term loan facility to be provided by a subsidiary of China Huarong Asset Management Co., Ltd.

which are expected to be available prior to the Closing, the Enlarged Group will have sufficient working capital for its business for at least the next twelve months from the date of this circular in the absence of unforeseen circumstances.

– I-60 –

FINANCIAL INFORMATION OF THE GROUP

APPENDIX I

E. FINANCIAL AND TRADING PROSPECTS OF THE GROUP

High production by OPEC, US shale and Non-OPEC suppliers created an unprecedented global glut that has driven oil prices lower since 2014, with oil prices ultimately reaching multi-year lows in February 2016 before rising and stabilizing above US$50/bbl as OPEC stepped in towards the end of 2016 with a commitment to cut production. With the OPEC production cuts continuing to hold, the oil and gas industry and the global economy are expected to recover moderately in 2017, However, with the recent moderate oil price recovery in 2017, US shale production has begun to rise again, which could lead OPEC to once again increase its production in an effort to regain market share, thereby driving oil prices lower once more. So, there remains a high level of uncertainty and potential volatility with respect to global oil prices. 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 2016, 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 dropped 12.4% to US$8.31/bbl, while those of the Emir Oil project in Kazakhstan decreased 38.4% to US$2.25/ bbl. In terms of overall overhead, the total headcount of the Group was reduced from 1,684 as of year-end 2015 to 1,387 as of year-end 2016. 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.

At the same time, the Target Company will be an important addition to the Group, enhancing its financial stability and strength. The Target Company’s prolific assets have been able to generate positive EBITDA/netback even in the current challenging oil and gas price environment, and the Target Company has the ability to self-finance its future capital expenditures via its own cash flows and financing capabilities. The majority of the Target Company’s assets are natural gas assets and the impact from low oil price on revenue is limited. With the start of export natural gas from the United States and the on-going projects for gas export in Western Canada. The Target Company will enjoy the potential and added value from natural gas price upsides in North America. The future growth potential of the Target Company is considerable, as manifested by its large diversified portfolio of producing assets, infrastructure and undeveloped land (approximately 760 thousand net acres), which will provide invaluable optionality and expansion opportunities. Furthermore, this acquisition, by providing a significant position in the mature, stable and technologically advanced Canadian oil and gas sector, will allow the Group to widen its global footprint, develop a more balanced and diversified oil and gas business portfolio, expand its technological and operational capabilities, and elevate its profile and image as an international energy company.

F. 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, 2016, being the date to which the latest published audited consolidated financial statements of the Company were made up.

– I-61 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

The following is the text of a report set out on pages II-1 to II-3, received from the Company’s reporting accountant, PricewaterhouseCoopers LLP, Chartered Professional Accountants, Canada, for the purpose of incorporation in this circular.

==> picture [97 x 64] intentionally omitted <==

ACCOUNTANT’S REPORT ON HISTORICAL FINANCIAL INFORMATION TO THE DIRECTORS OF MIE HOLDINGS CORPORATION

Introduction

We report on the historical financial information of CQ Energy Canada Partnership (the ‘‘Target’’) and its subsidiaries (together, the ‘‘Target Group’’) set out on pages II-4 to II-31, which comprises the consolidated and partnership balance sheets as at December 31, 2014, 2015 and 2016 and March 31, 2017, and the consolidated statements of net loss and comprehensive loss, the consolidated statements of changes in partners’ equity and the consolidated statements of cash flows for the years ended December 31, 2014, 2015, and 2016 and the three months ended March 31, 2017 (the ‘‘Track Record Period’’) and a summary of significant accounting policies and other explanatory information (together, the ‘‘Historical Financial Information’’). The Historical Financial Information set out on pages II-4 to II-31 forms an integral part of this report, which has been prepared for inclusion in the circular of MIE Holdings Corporation (the ‘‘Company’’) dated September 7, 2017 (the ‘‘Circular’’) in connection with the proposed acquisition of the Target by the Company.

Directors’ responsibility for the Historical Financial Information

The directors of the Company are responsible for the preparation of Historical Financial Information that gives a true and fair view in accordance with the basis of preparation set out in Note 1(b) to the Historical Financial Information, and for such internal control as the directors determine is necessary to enable the preparation of Historical Financial Information that is free from material misstatement, whether due to fraud or error.

The Historical Financial Information in this report was prepared by the directors of the Company based on the previously issued financial statements and management accounts of the Target Group for the Track Record Period (‘‘Historical Financial Statements’’). Management of the Target are responsible for the preparation and fair presentation of the Historical Financial Statements in accordance with International Financial Reporting Standards (‘‘IFRSs’’) issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of Historical Financial Statements that are free from material misstatement, whether due to fraud or error.

PricewaterhouseCoopers LLP, Canada

Suncor Energy Centre, 111 5th Avenue SW, Suite 3100, East Tower, Calgary, Alberta, Canada T2P 5L3 T: +1 403 509 7500, F: +1 403 781 1825, www.pwc.com/ca

– II-1 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

Reporting accountant’s responsibility

Our responsibility is to express an opinion on the Historical Financial Information and to report our opinion to you. We conducted our work in accordance with Hong Kong Standard on Investment Circular Reporting Engagements 200, Accountants’ Reports on Historical Financial Information in Investment Circulars issued by the Hong Kong Institute of Certified Public Accountants (‘‘HKICPA’’). This standard requires that we comply with ethical standards and plan and perform our work to obtain reasonable assurance about whether the Historical Financial Information is free from material misstatement.

Our work involved performing procedures to obtain evidence about the amounts and disclosures in the Historical Financial Information. The procedures selected depend on the reporting accountant’s judgement, including the assessment of risks of material misstatement of the Historical Financial Information, whether due to fraud or error. In making those risk assessments, the reporting accountant considers internal control relevant to the entity’s preparation of Historical Financial Information that gives a true and fair view in accordance with the basis of preparation set out in Note 1(b) to the Historical Financial Information in order to design procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Our work also included evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by the directors, as well as evaluating the overall presentation of the Historical Financial Information.

We believe that the evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.

Opinion

In our opinion the Historical Financial Information gives, for the purposes of the accountant’s report, a true and fair view of the financial position of the Target as at December 31, 2014, 2015 and 2016 and March 31, 2017, and the consolidated financial position of the Target Group as at December 31, 2014, 2015 and 2016 and March 31, 2017 and of its consolidated financial performance and its consolidated cash flows for the Track Record Period in accordance with the basis of preparation set out in Note 1(b) to the Historical Financial Information.

– II-2 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

Review of stub period comparative financial information

We have reviewed the stub period comparative financial information of the Target Group which comprises the consolidated statements of net loss and comprehensive loss, changes in partners’ equity and cash flows for the three months ended March 31, 2016 and other explanatory information (the ‘‘Stub Period Comparative Financial Information’’). The directors of the Company are responsible for the preparation and presentation of the Stub Period Comparative Financial Information in accordance with the basis of preparation set out in Note 1(b) to the Historical Financial Information. Our responsibility is to express a conclusion on the Stub Period Comparative Financial Information based on our review. We conducted our review in accordance with International Standard on Review Engagements 2410, Review of Interim Financial Information Performed by the Independent Auditor of the Entity issued by the International Auditing and Assurance Standards Board (‘‘IAASB’’). A review consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion. Based on our review, nothing has come to our attention that causes us to believe that the Stub Period Comparative Financial Information, for the purposes of the accountant’s report, is not prepared, in all material respects, in accordance with the basis of preparation set out in Note 1(b) to the Historical Financial Information.

Report on matters under the Rules Governing the Listing of Securities on The Stock Exchange of Hong Kong Limited

Adjustments

The Historical Financial Information is stated after making such adjustments to the Historical Financial Statements as were considered necessary.

PricewaterhouseCoopers LLP

Chartered Professional Accountants Calgary, Alberta Canada

September 7, 2017

– II-3 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

I HISTORICAL FINANCIAL INFORMATION OF THE TARGET GROUP

Preparation of Historical Financial Information

Set out below is the Historical Financial Information which forms an integral part of this accountant’s report. The Historical Financial Information in this report was prepared by the directors of the Company based on the previously issued consolidated financial statements and management accounts of the Target Group for the Track Record Period. The previously issued consolidated financial statements were audited by PricewaterhouseCoopers LLP, Canada in accordance with Canadian generally accepted auditing standards issued by the Canadian Auditing and Assurance Standards Board. The Historical Financial Information is presented in Canadian dollars and all values are rounded to the nearest thousand (C$’000) except when otherwise indicated.

– II-4 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

Consolidated Balance Sheets

(in thousands of Canadian dollars)

Assets Current Cash and cash equivalents Accounts receivable Prepaid expenses Due from related parties (note 20) Non-Current Goodwill (note 11) Exploration and evaluation assets (note 9) Property, plant and equipment (note 10) Liabilities Current Accounts payable and accrued liabilities Current portion of asset retirement obligation (note 13) Due to related parties (note 20) Partnership distribution payable (note 15) Note payable (note 12) Non-current Asset retirement obligation (note 13) Note payable (note 12) Partners’ Equity Partners’ capital (note 15) Retained earnings (deficit)	As 2014 78,603 59,317 8,565 12,226 158,711 112,338 261,494 1,831,554 2,205,386 2,364,097 162,689 12,750 — 15,000 — 190,439 576,344 50,000 626,344 1,367,419 179,895 1,547,314 2,364,097	at December 31, 2015 2016 66,587 52,744 61,638 43,488 9,632 12,431 — 349 137,857 109,012 — — 199,004 193,135 1,269,712 1,155,832 1,468,716 1,348,967 1,606,573 1,457,979 127,796 97,458 21,697 14,341 7,598 1,095 15,000 15,000 19,000 — 191,091 127,894 508,696 501,466 50,000 50,000 558,696 551,466 1,367,419 1,312,419 (510,633) (533,800) 856,786 778,619 1,606,573 1,457,979	As at March 31, 2017 72,170 35,740 11,726 — 119,636 — 172,640 1,062,080 1,234,720 1,354,356 108,728 14,341 2,402 — 50,000 175,471 533,885 — 533,885 1,306,409 (661,409) 645,000 1,354,356

– II-5 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

Partnership Balance Sheets

(in thousands of Canadian dollars)

Assets Current Note receivable Non-Current Investment in subsidiary Liabilities Current Partnership distribution payable Note payable Non-current Due to related parties Note payable Partners’ Equity Partners’ capital Deficit	As 2014 — — 1,732,406 1,732,406 15,000 — 15,000 120,092 50,000 170,092 1,367,419 179,895 1,547,314 1,732,406	at December 31, 2015 2016 19,000 — 19,000 — 1,041,710 963,549 1,060,710 963,549 15,000 15,000 19,000 — 34,000 15,000 119,924 119,930 50,000 50,000 169,924 169,930 1,367,419 1,312,419 (510,633) (533,800) 856,786 778,619 1,060,710 963,549	As at March 31, 2017 — — 814,930 814,930 — 50,000 50,000 119,930 — 119,930 1,306,409 (661,409) 645,000 814,930

– II-6 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

Consolidated Statements of Net Loss and Comprehensive Loss

(in thousands of Canadian dollars)

Revenue Oil and natural gas sales (note 16) Royalties Expenses Direct operating Transportation General and administrative (note 17) Depletion, depreciation and amortization (note 10) Exploration & evaluation lease expiries (note 9) Impairment (note 9, 10 and 11) Gain on acquisitions and dispositions (note 6, 7, 8) Finance expense (note 13) Foreign exchange (gain) loss Post-closing purchase price adjustments (note 10, 19) Other Net loss and comprehensive loss	Year ended December 31, 2014 2015 2016 569,369 478,343 334,161 (80,400) (23,339) (19,492) 488,969 455,004 314,669 170,923 280,446 133,446 16,751 24,269 27,993 39,210 54,378 39,312 173,318 228,121 125,459 349 3,597 11,592 80,134 558,726 — (12,600) (13,624) (10,747) 25,556 27,198 24,699 — (3,307) (64) — — (13,346) — 789 (508) 493,641 1,160,593 337,836 (4,672) (705,589) (23,167)	Three months period ended March 31, 2016 2017 (unaudited) 80,464 113,710 (3,950) (10,410) 76,514 103,300 38,641 40,821 5,112 8,150 13,464 8,601 33,189 29,801 3,099 2,665 — 135,045 (3,079) (48) 6,175 6,005 8 20 — (194) (147) 43 96,462 230,909 (19,948) (127,609)

– II-7 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

Consolidated Statements of Changes in Partners’ Equity

(in thousands of Canadian dollars)

Partners’ Capital Balance — January 1, 2014 Partnership funding of post-closing purchase price adjustment Partnership capital contribution (note 8) Partnership distribution paid (note 15) Balance — December 31, 2014 Balance — December 31, 2015 Partnership distribution declared and paid (note 15) Balance — December 31, 2016 Balance — December 31, 2015 Balance — March 31, 2016 (unaudited) Balance — December 31, 2016 Partnership distribution paid Post-closing purchase price adjustment Balance — March 31, 2017 Retained Earnings (Deficit) Balance — January 1, 2014 Net loss and comprehensive loss Common control transaction reserve (note 8) Partnership distribution paid and payable (note 15) Balance — December 31, 2014 Balance — December 31, 2014 Net loss and comprehensive loss Common control transaction reserve (note 8) Balance — December 31, 2015	DERP 182,190 (8,908) 681,400 (34,231) 820,451 820,451 (33,000) 787,451 820,451 820,451 787,451 (3,490) (116) 783,845 (23,630) (2,803) 149,460 (15,089) 107,938 107,938 (423,353) 9,037 (306,378)	A Partner 121,460 (5,939) 454,267 (22,820) 546,968 546,968 (22,000) 524,968 546,968 546,968 524,968 (2,326) (78) 522,564 (15,754) (1,869) 99,640 (10,060) 71,957 71,957 (282,236) 6,024 (204,255)	Total 303,650 (14,847) 1,135,667 (57,051) 1,367,419 1,367,419 (55,000) 1,312,419 1,367,419 1,367,419 1,312,419 (5,816) (194) 1,306,409 (39,384) (4,672) 249,100 (25,149) 179,895 179,895 (705,589) 15,061 (510,633)

– II-8 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

Net loss and comprehensive loss Balance — December 31, 2016 Balance — December 31, 2015 Net loss and comprehensive loss Balance — March 31, 2016 (unaudited) Balance — December 31, 2016 Net loss and comprehensive loss Balance — March 31, 2017 Partners’ Equity Balance — December 31, 2014 Balance — December 31, 2015 Balance — December 31, 2016 Balance — March 31, 2016 (unaudited) Balance — March 31, 2017	DERP (13,900) (320,278) (306,378) (11,969) (318,347) (320,278) (76,565) (396,843) 928,389 514,073 467,173 502,104 387,002	A Partner (9,267) (213,522) (204,255) (7,979) (212,234) (213,522) (51,044) (264,566) 618,925 342,713 311,446 334,734 257,998	Total (23,167) (533,800) (510,633) (19,948) (530,581) (533,800) (127,609) (661,409) 1,547,314 856,786 778,619 836,838 645,000

– II-9 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

Consolidated Statements of Cash Flows

(in thousands of Canadian dollars)

Operating activities Net loss Add items not involving cash Depletion, depreciation and amortization (note 10) Impairment (note 9, 10 and 11) Finance expense (note 13) Gain on acquisitions and dispositions (note 6, 7, 8) Exploration & evaluation lease expiries (note 9) Unrealized foreign exchange gain Post-closing purchase price adjustments (note 10, 19) Asset retirement obligation expenditures (note 13) Change in non-cash working capital (note 19) Cash flow from operating activities Investing activities Capital expenditures Acquisitions and disposals (note 6, 7, 10) Post-closing purchase price adjustments Change in non-cash working capital (note 19) Cash flow used in investing activities	Year ended December 31, 2014 2015 2016 (4,672) (705,589) (23,167) 173,318 228,121 125,459 80,134 558,726 — 25,556 27,198 24,699 (12,600) (13,624) (10,747) 349 3,597 11,592 — — (20) — — (13,346) (10,691) (15,727) (9,310) (34,081) 30,371 (9,571) 217,313 113,073 95,589 (154,178) (112,345) (48,246) (42,500) 13,040 11,716 (2,665) — — 37,639 (44,784) 1,098 (161,704) (144,089) (35,432)	Three months period ended March 31, 2016 2017 (unaudited) (19,948) (127,609) 33,189 29,801 — 135,045 6,175 6,005 (3,079) (48) 3,099 2,665 — 27 — (194) (3,058) (4,736) 19,223 15,730 35,601 56,686 (7,406) (22,216) 3,912 150 — — (2,965) 5,622 (6,459) (16,444)

– II-10 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

Financing activities (Repayment) proceeds of/from issuance of notes (note 12) Partnership distribution (note 15) Change in non-cash working capital (note 19) Cash flow (used in)/generated from financing activities Change in cash and cash equivalents Cash and cash equivalents — Beginning of period Cash and cash equivalents — End of period	Year ended December 31, 2014 2015 2016 — 19,000 (19,000) (82,200) — (55,000) 154 — — (82,046) 19,000 (74,000) (26,437) (12,016) (13,843) 105,040 78,603 66,587 78,603 66,587 52,744	Three months period ended March 31, 2016 2017 (unaudited) (19,000) — — (5,816) — (15,000) (19,000) (20,816) 10,142 19,426 66,587 52,744 76,729 72,170

– II-11 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

II NOTES TO THE HISTORICAL FINANCIAL INFORMATION OF THE TARGET GROUP

1 (a) GENERAL INFORMATION

CQ Energy Canada Partnership (the ‘‘Target’’) and its subsidiaries (collectively referred to as the ‘‘Target Group’’) is a partnership governed by the laws of the Province of Alberta, Canada. The primary place of business is located at Suite 2600 237 4th Ave SW, Calgary AB T2P 4K3. Direct Energy Resources Partnership (‘‘DERP’’) owns a 60% interest in the Partnership. A Partner owns a 40% interest in the Partnership. DERP is a subsidiary of Direct Energy Marketing Ltd. (‘‘DEML’’) and the ultimate parent is Centrica PLC. The Target was formed on September 25, 2013. The business of the Target Group is to explore for, develop and hold interests in petroleum and natural gas properties directly and through investments in other partnership holdings in oil and natural gas properties or related production infrastructure.

(b) Basis of preparation

The financial information of the Target Group has been prepared by the Directors of the Company on a basis of International Financial Reporting Standards (‘‘IFRS’’) issued by the International Accounting Standards Board and IFRS Interpretations Committee (‘‘IFRIC’’) interpretations applicable to entities reporting under IFRS, as adjusted for the accounting policies of the Company.

The financial information has been prepared under the historical cost basis expect as disclosed in the significant accounting policies in Note 2. The financial information is presented in Canadian dollars, which is the Target Group’s function currency.

The preparation of financial information in conformity with IFRS requires the use of certain critical accounting estimates. It also requires management to exercise its judgement in the process of applying accounting policies. The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are significant to the financial information are disclosed in Note 5 below.

2 SIGNIFICANT ACCOUNTING POLICIES

The following accounting policies are applied consistently.

(a) Basis of consolidation

The consolidated financial information includes the financial information of the Target and the subsidiaries the Target controls. All inter-company transactions and balances have been eliminated upon consolidation. The target owns 100% of 8401268 Canada Inc. and CQ Energy Canada Resources Partnership. 8401268 Canada Inc. owns a 43% interest in 509760 Alberta Ltd., formerly Phillip JGC Joint Venture. 509760 Alberta Ltd. is not material to the Target’s operations.

(b) Business combinations and goodwill

Business combinations are accounted for using the acquisition method of accounting in which the identifiable assets acquired, liabilities assumed and any non-controlling interests are recognized and measured at their fair value at the date of acquisition. If the business combination is achieved in stages, the acquisition date fair value of the Target’s previously held equity interest in the acquiree is re-measured to fair value at the acquisition date through earnings as impairment. Any excess of the purchase price plus any non-controlling interest over the fair value of the net assets acquired is recognized as goodwill. Any deficiency of the purchase price over the fair value of the net assets acquired is credited to net income as a gain on acquisition. Subsequent measurement of goodwill is at cost less any accumulated impairment losses.

– II-12 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

(c) Joint operations

Certain exploration and production activity is conducted through joint operations, where the operators have a direct interest in and jointly control the assets of the operation. The results, assets, liabilities and cash flows of these jointly controlled operations are included in the consolidated financial information in proportion to the Target’s interest.

(d) Revenue recognition

Revenue associated with sales of natural gas, crude oil and natural gas liquids is recognized when title passes to the customer and collectability is reasonably assured. Transportation costs are reported as a separate expense and are not netted against revenue.

(e) Cash and cash equivalents

Cash equivalents include cash on hand, market deposits and similar type instruments, with an original maturity of three months or less when purchased.

(f) Exploration and evaluation assets (‘‘E&E’’)

Geological and geophysical costs are expensed when incurred. Costs of exploratory wells (including certain geophysical costs which are directly attributable to the drilling of these wells) are capitalized as exploration and evaluation assets pending determination of whether the wells find proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

Exploratory wells in areas not requiring major capital expenditures are evaluated for economic viability within one year of completion of drilling. The related well costs are expensed as dry holes if it is determined that such economic viability is not attained. Otherwise, the related well costs are reclassified to oil and gas properties and subject to impairment review. For exploratory wells that are found to have economically viable reserves in areas where major capital expenditure will be required before production can commence, the related well costs remain capitalized only if additional drilling is under way or firmly planned. Otherwise the related well costs are expensed as dry holes. The Target does not have any costs of unproved properties capitalized in oil and gas properties.

Identifiable exploration assets acquired are recognized as assets at their fair value, as determined by the requirements of business combinations. Exploration and evaluation expenditures incurred subsequent to the acquisition of an exploration asset in a business combination is accounted for in accordance with the policy outlined above.

E&E assets are assessed for impairment if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. If an area or exploration well is no longer considered commercially viable, the related capitalized costs are charged to impairment expense.

(g) Property, plant and equipment (‘‘PP&E’’)

Items of PP&E which include oil and gas development, production assets and administrative assets that are directly attributable are measured at cost less accumulated depletion, depreciation and amortization and accumulated impairment losses.

All field development costs are capitalized as property, plant and equipment. Such costs relate to the acquisition and installation of production facilities and include development drilling costs, project-related engineering and other technical services costs. Changes in these estimates are dealt with prospectively.

– II-13 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

Gains and losses on disposal of an item of PP&E are determined by comparing the proceeds from disposal with the carrying amount of PP&E and are recognized separately in the statement of comprehensive income (loss).

Exchanges of properties are measured at fair value, unless the transaction lacks commercial substance or fair value cannot be reasonably measured. Where the exchange is measured at fair value, a gain or loss is recognized in the statement of comprehensive income (loss).

Salaries and wages, which are directly attributable to bringing an asset to the location and condition necessary for it to be capable of use in the manner intended by management are capitalized.

The carrying values of PP&E are reviewed for impairment when events or changes in circumstances indicate that the carrying value may not be recoverable.

(h) Depletion, depreciation and amortization

Development and production assets are componentized into groups of assets with similar useful lives for the purposes of preforming depletion calculations. Depletion expense is calculated on the UOP basis based on:

(i) total estimated proved and probable developed reserves;
(ii) total capitalized costs; and
(iii) relative volumes of petroleum and natural gas reserves and production, before royalties, converted at the energy equivalent conversion ratio of six thousand cubic feet of natural gas to one barrel of oil.

Depreciation on other assets is calculated using the straight-line method to allocate their cost to their residual values over their estimated useful lives, as follows:

Buildings and improvements	7–10 years
Office equipment	3 years
Motor vehicles and production equipment	10 years

(i) Impairment

The Target Group assesses PP&E and E&E assets whenever events or changes in circumstances indicate that the carrying amount of an asset or group of assets may not be recoverable. Indications of impairment include the existence of low benchmark commodity prices for an extended period of time, significant downward revisions of estimated reserve volumes, significant increase in estimated future development expenditures, or significant adverse change in the applicable legislative or regulatory frameworks. If any such indication of impairment exists, the Target Group performs an impairment test related to the assets. Individual assets are grouped for impairment assessment purposes into cash generating units (‘‘CGUs’’) which are the lowest level at which there are identifiable cash inflows that are largely independent of the cash inflows of other groups of assets. A CGUs recoverable amount is the higher of its fair value less costs of disposal and its value in use. Where the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and is written down to its recoverable amount.

An impairment loss is reversed only if there has been a change in the estimate used to determine the assets recoverable amount since the last impairment loss was recognized. Where an impairment loss subsequently reverses the carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognized for the asset or CGU in prior years. A reversal of an impairment loss is recognized in the statement of comprehensive income (loss) immediately. After such a reversal the depreciation or amortization charge, where relevant, is adjusted in future periods to allocate the assets’ revised carrying amount less any residual value, on a systematic basis over its remaining useful life.

– II-14 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

Goodwill is tested annually for impairment or earlier if impairment indicators exist. Goodwill is allocated to the Target level for the purposes of impairment testing as this is the level at which goodwill is monitored by management. Goodwill impairments are not reversed.

Financial assets are also assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of that asset. An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate. Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics. All impairment losses are recognized in the statement of comprehensive income (loss) in the period incurred. An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. For financial assets measured at amortized cost the reversal is recognized in the statement of comprehensive income (loss).

(j) Asset retirement obligations

The Target Group recognizes an asset retirement obligation (‘‘ARO’’) in the period in which it has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. ARO is determined by discounting the expected future cash flows at a credit-adjusted rate. A corresponding asset equal to the initial estimated liability is capitalized as part of the related long-lived asset. The increase in the provision due to the passage of time is recognized as a finance or accretion expense in the statement of comprehensive income (loss). Actual expenditures incurred are charged against the accumulated liability. Revisions to the estimated amount and timing of the obligations are reflected as increases or decreases to the ARO.

(k) Financial instruments

Financial assets and financial liabilities are recognized when the Target Group becomes a party to the contractual provisions of the instrument. Financial assets are derecognized when the rights to receive cash flows from the assets have been expired or have been transferred and the Target Group has transferred substantially all risk and rewards of ownership.

Financial liabilities are derecognized when the obligation specified in the contract is discharged, cancelled or expires. All financial instruments are initially recognized at fair value on the balance sheet. Measurement of financial instruments subsequent to the initial recognition, as well as resulting gains and losses, are based on how each financial instrument was initially classified. The Target Group has classified each identified financial instrument into the following categories: fair value through profit or loss, loans and receivables, available for sale financial assets and other financial liabilities. Fair value through profit or loss financial instruments are measured at fair value with gains and losses recognized in income immediately. Available for sale financial assets are measured at fair value with gains and losses, other than impairment losses, recognized in other comprehensive income and transferred to income when the asset is derecognized. Loans and receivables and other financial liabilities are recognized at amortized cost using the effective interest method and impairment losses are recorded in comprehensive income when incurred.

Cash and cash equivalents, accounts receivable, and due from partners have been classified as loans and receivables. Due to related party, accounts payable and accrued liabilities, partnership distribution payable and note payable have been classified as other financial liabilities.

(l) Common control transaction

A business combination involving entities under common control is a business combination in which all of the combining entities are ultimately controlled by the same party, both before and after the business combination, and control is not transitory. Business combinations involving entities under common control are outside the scope of IFRS 3 Business Combinations. IFRS provides no guidance on the accounting for these types of transactions and an entity is required to develop an accounting policy. The three most common methods utilized are the purchase method, the predecessor values since inception method, and the predecessor values from date of transaction method. Management has determined the predecessor values from date of

– II-15 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

transaction method to be most appropriate. This method requires the consolidated financial information to be prepared using the predecessor carrying values without any step up to fair value. The difference between any consideration and the aggregate carrying value of the assets and liabilities are recorded as a reserve from the common control transaction in Partners’ equity. Transaction costs associated with a common control transaction are recognized as an expense in the period.

(m) Income taxes

The Target is not a taxable entity for federal and provincial income tax purposes. Accordingly, no recognition is given to income taxes for financial reporting purposes. Tax on the Target’s net income is borne by the individual partners through the allocation of taxable income. Net income for financial statement purposes may differ significantly from taxable income for individual partners as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the partnership agreement.

(n) Share-based Compensation Plans

Under the Target’s Memorandum of Agreement, share-based awards may be granted to executives and employees as a part of total compensation. Share-based awards are granted to the Target Group’s Operators executives and employees by the Target Group’s ultimate parent and compensation expense related to these awards is recognized in Direct operating and General and administrative expense.

Share-based award options that give the holder the right to purchase common shares are accounted for as equity-settled plans. The fair value of the options are determined at grant date based on market value of the target group’s parent’s share price and is recognized over the vesting periods of the respective options. A corresponding increase is recorded in Accounts payable and accrued liabilities as the Target Group is ultimately responsible for settling the cost of the options through recharges.

3 FINANCIAL RISK MANAGEMENT

The Target Group’s normal operating, investing and financing activities expose it to a variety of financial risks: market risk (including commodity price risk, currency risk), credit risk and liquidity risk. The Target Group’s overall risk management process is designed to identify, manage and mitigate business risk, which includes among other risks, financial risk.

Financial risk management is overseen by the Management Committee of the Target Group.

(a) Commodity price risk

The Target Group’s operational results and financial condition are largely dependent on the commodity prices received for its oil and natural gas production. Commodity prices have fluctuated widely during recent years due to global and regional factors including supply and demand fundamentals, inventory levels, weather, economic and geopolitical factors. Movement in commodity prices could have a significant positive or negative impact on the Target Group’s net income. The Target Group has not entered into any contracts to manage commodity price risk.

(b) Foreign exchange risk

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 Target Group has not entered into any contracts to manage foreign exchange risk.

– II-16 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

(c) Credit risk

Credit risk is the risk of financial loss to the Target Group if a partner or counterparty to a product sales contract or financial instrument fails to meet its contractual obligations. The Target Group is exposed to credit risk with respect to its accounts receivable and due from related parties. The maximum exposure to credit risk is as follows:

Accounts receivable Due from related parties Allowance for doubtful accounts	December 31, 2014 C$’000 61,817 12,226 (2,500) 71,543	December 31, 2015 C$’000 64,138 — (2,500) 61,638	December 31, 2016 C$’000 47,118 349 (3,630) 43,837	March 31, 2017 C$’000 39,576 — (3,836
				35,740

Accounts receivable are subject to credit risk exposure and the carrying values reflect management’s assessment of the associated maximum exposure to such credit risk. The Target Group mitigates such credit risk by closely monitoring significant counterparties and dealing with a broad section of partner’s that diversify risk within the sector.

Substantially all of the accounts receivables are due from customers and joint operation partners concentrated in the Canadian oil and gas industry. As such, accounts receivable are subject to normal industry credit risk. The Target Group generally extends unsecured credit to these customers and therefore the collection of accounts receivable may be affected by changes in economic or other conditions. Management believes the risk is mitigated by entering into transactions with long-standing, reputable counterparties and partners. Wherever possible, the Target Group requires cash calls from its partners on capital projects before they commence. Receivables related to the sale of the Target Group’s petroleum and natural gas production are mainly from major marketing companies who have very good credit ratings. These revenues are normally collected on the 25th day of the month following delivery.

The following table details the accounts receivable of the Target Group:

Accrued income and royalties Joint venture, partner and trade receivables Other receivables Allowance for doubtful accounts	December 31, 2014 C$’000 16,257 42,983 2,577 (2,500) 59,317	December 31, 2015 C$’000 12,010 42,588 9,540 (2,500) 61,638	December 31, 2016 C$’000 13,498 32,475 1,145 (3,630) 43,488	March 31, 2017 C$’000 11,933 24,232 3,411 (3,836
				35,740

The following table details the aging analysis of the Target Group’s joint venture, partner and trade receivables:

Current Over 30 Days Over 60 Days Over 90 Days Over 120 Days	December 31, 2014 C$’000 27,835 5,514 110 539 8,985 42,983	December 31, 2015 C$’000 2,248 23,876 6,026 100 10,338 42,588	December 31, 2016 C$’000 16,330 2,782 2,591 595 10,177 32,475	March 31, 2017 C$’000 14,564 148 840 1,630 7,050
				24,232

– II-17 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

(d) Liquidity risk

The Target Group is subject to liquidity risk from accounts payable, and accrued liabilities, partnership distribution payable, notes payable and due to related parties. Accounts payable and accrued liabilities are primarily due within one year of the balance sheet date and the Target Group does not anticipate any problems in satisfying the obligations from cash provided by operating activities and cash on hand.

The following tables detail the contractual maturities of the Target Group’s financial liabilities:

As at March 31, 2017 Accounts payable and accrued liabilities Due to related parties Notes payable As at December 31, 2016 Accounts payable and accrued liabilities Due to related parties Target Group distribution payable Notes payable As at December 31, 2015 Accounts payable and accrued liabilities Due to related parties Target Group distribution payable Notes payable As at December 31, 2014 Accounts payable and accrued liabilities Target Group distribution payable Notes payable	Carrying amount C$’000 108,728 2,402 50,000 161,130 97,458 1,095 15,000 50,000 163,553 127,796 7,598 15,000 69,000 219,394 162,689 15,000 50,000 227,689	1 year C$’000 108,728 2,402 50,000 161,130 97,458 1,095 15,000 — 113,553 127,796 7,598 15,000 19,000 169,394 162,689 15,000 — 177,689	2–3 years C$’000 — — — — — — — 50,000 50,000 — — — 50,000 50,000 — — 50,000 50,000	Beyond 3 years C$’000 — — —
				—
				— — — —
				—
				— — — —
				—
				— — —
				—

– II-18 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

The following tables detail the aging analysis of the Target Group’s trade payables:

Current Over 30 Days Over 60 Days Over 90 Days Over 120 Days	December 31, 2014 C$’000 11,095 1,580 73 27 3,341 16,116	December 31, 2015 C$’000 500 830 520 163 2,006 4,019	December 31, 2016 C$’000 5,472 631 705 728 3,062 10,598	March 31, 2017 C$’000 7,848 978 1,799 3 8,255
				18,883

4 NEW ACCOUNTING POLICIES

Future accounting policy changes

The following standards are mandatory for future accounting periods which the Target Group has not early adopted.

In May 2014, the IASB issued IFRS 15, ‘‘Revenue from Contracts with Customers’’, which replaces IAS 18 Revenue, IAS 11 Construction Contracts, and related interpretations. The standard is required to be adopted either retrospectively or using a modified transition approach for fiscal years beginning on or after January 1, 2018, with earlier adoption permitted. The Target Group is currently evaluating the impact of this standard on the consolidated financial information of the Target Group.

In July 2014, the IASB issued IFRS 9, ‘‘Financial Instruments’’ as a complete standard, including the requirements previously issued related to classification and measurement of financial assets and liabilities, and additional amendments to introduce a new expected loss impairment model for financial assets including credit losses. Retrospective application of this standard with certain exemptions is effect for fiscal years beginning on or after January 1, 2018, with earlier application permitted. The Target Group is currently assessing the impact of this standard on the consolidated financial information of the Target Group.

In January 2016, the IASB issued IFRS 16, ‘‘Leases’’, which replaces IAS 17 ‘‘Leases’’. The standard moves to a single recognition and measurement model for leases, with required recognition of assets and liabilities for most leases. This standard is required to be adopted for annual periods beginning on or after January 1, 2019, with earlier adoption permitted if the entity is also applying IFRS 15 ‘‘Revenue from Contracts with Customers’’. The Target Group is currently evaluating the impact of this standard on the consolidated financial information of the Target Group.

There are no other IFRS or IFRIC interpretations that are not yet effective that would be expected to have a material impact on the Target Group.

5 MANAGEMENT JUDGMENTS AND ESTIMATION UNCERTAINTY

The preparation of consolidated financial information in conformity with IFRS requires the use of certain critical accounting estimates. It requires management to exercise its judgment in the processes of applying the Target Group’s accounting policies. The areas involving a higher degree of judgment, complexity or areas where assumptions and estimates are significant to the consolidated financial information are described below.

(a) Business combinations

The fair value of PP&E recognized in a business combination is based on market values. The market value of PP&E is the estimated amount for which PP&E could be exchanged on the acquisition date between a willing buyer and a willing seller in an arm’s length transaction after proper marketing wherein the parties had each acted knowledgeably, prudently and without compulsion. The market value of oil and natural gas interests (included in PP&E) are estimated with reference to the discounted cash flow expected to be derived

– II-19 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

from oil and natural gas production based on externally prepared reserve reports. The market value of E&E assets are estimated with reference to the market values of current arm’s length transactions in comparable locations.

Decommissioning liabilities are determined by discounting the expected future cash flows at a creditadjusted rate.

(b) Recoverability of asset carrying values

The recoverability of development production asset carrying values is assessed at the CGU level. Determination of what constitutes a CGU is subject to management judgments. The asset composition of a CGU can directly impact the recoverability of the assets included therein. In assessing the recoverability of oil and gas properties, each CGUs carrying value is compared to its recoverable amount, defined as the greater of its fair value less costs of disposal and value in use. Assets that are in close geographical proximity and have geographic similarities that use same or similar infrastructure have been grouped into a CGU. This is consistent with how Management reviews the business.

For purposes of property, plant and equipment, E&E asset, and goodwill impairment testing, the recoverable amounts of the Target Group’s CGUs were estimated as their fair value less cost of disposal based on the following information:

(i) The net present value of the after-tax flows from oil and gas reserves of each CGU based on the reserves estimated by the Target Group and recent market information; and
(ii) The fair value of undeveloped land based on use of a discounted cash flow model and estimates provided by acquisition metrics of recent transactions completed on similar assets to those contained within the relevant CGU.

Key input estimates used in the determination of cash flows from oil and gas reserves include the following:

(i) Proved plus probable reserves are determined using estimates of oil and natural gas in place, recovery factors and future prices. Future development costs are estimated using assumptions as to the number of wells required to produce the reserves, the cost of such wells and associated production facilities and other capital costs. Proved and probable reserves are estimated using internal reserve engineer reports and represent the estimated quantities of oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is highly likely that the actual remaining quantities recovered will exceed the estimated proved 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 and probable reserves.
(ii) Oil and natural gas prices — Forward price estimates of the oil and natural gas prices are used in the cash flow model.
(iii) Discount rate — The discount rate used to calculate the net present value of cash flows is based on estimates of an approximate industry peer group weighted average cost of capital. Changes in the general economic environment could result in significant changes to this estimate.

– II-20 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

(c) Depletion of oil and gas assets

Oil and gas properties are depleted using the UOP basis over proved plus probable developed reserves. The calculation of the UOP rate of depletion could be impacted to the extent that actual production in the future is different from current forecast production based on proved plus probable developed reserves. This would generally result from significant changes in any of the factors or assumptions used in estimating reserves.

(d) Asset retirement obligation

The Target Group estimates the asset retirement obligations for oil and gas wells and their associated production facilities and infrastructure. In most instances, dismantling of assets and remediation occurs many years into the future. The value of the ultimate asset retirement obligation can fluctuate in response to many factors including changes to relevant legal requirements, the emergence of new restoration techniques, experience at other production sites, and changes to the discount rate. The expected timing and amount of expenditure can also change, for example, in response to changes in reserves or changes in laws and regulations or their interpretation. Judgments include the most appropriate discount rate to use, which management has determined to be a credit-adjusted rate. The Target Group estimates abandonment and reclamation costs based on a combination of publically available industry benchmarks and internal site specific information. The expected timing of settlement is estimated based on the proved plus probable period to abandonment each asset, as per the independent reserve evaluation, unless the timing to abandon and reclaim a specific well site or facility is known based on budgeted expenditures.

6 ACQUISITIONS

On May 13, 2014, the Target Group signed a purchase & sale agreement with Shell Canada Energy (‘‘Shell’’) to acquire Shell’s 50% working interest in Panther River assets of which the Target Group previously owned a working interest, along with Shell’s working interest in adjacent Burnt Timber and Hunter Valley assets. In addition, DEML transferred its working interest ownership in the Shell Burnt Timber gas processing facilities to the Target Group and the Target Group relinquished ownership in the Shell Burnt Timber gas processing facilities along with Waterton mineral land interests to Shell. The acquisition was completed on June 27, 2014. The transaction was accounted for as a business combination under IFRS 3. A net gain on the acquisition of C$12.6 million was recorded relating to the re-measurement of the Target Group’s previously held equity interest in Panther River and Burnt Timber assets.

Consideration of C$42.5 million is comprised of:

Property, plant and equipment Disposal of Target Group interest in Burnt Timber gas plant interest and Waterton mineral land interests Gain on acquisition Asset retirement obligation acquired Asset retirement obligation disposed Cash paid	C$’000 85,562 (5,600) (12,600) (30,462) 5,600 42,500

– II-21 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

7 DISPOSITIONS

On August 19, 2015, the Target Group signed a purchase & sale agreement for the disposition of working interests in Craigmyle and Endiang assets for net proceeds of C$10.7 million. The assets had a net carrying amount including PP&E, E&E, prepaid expenses and decommissioning liability of C$0.7 million resulting in a gain on disposition of C$10.0 million.

8 COMMON CONTROL TRANSACTION

On October 1, 2014, the Target Group acquired the remaining wholly owned Canadian natural gas assets of DEML and DERP. The transaction was executed through a cash contribution by A Partner of C$215 million to the Target Group and an estimated capital contribution of C$537 million, subject to post-closing adjustments, comprising of natural gas assets by DERP into CQ Energy Canada Resources Target Group. At the date of closing DEML, DERP and CQ Energy Canada Resources Target Group were subsidiaries of Centrica PLC; consequently, the entities were under common control at the time of the acquisition. The acquisition has been accounted for using the predecessor values from the date of transaction method, whereby the acquired assets are transferred to the Target Group based on the historical carrying value carved-out of DEML and DERP. The carrying value of the assets transferred was tested for impairment at the time of transfer and no impairment was recorded.

The following table summarizes the carrying value of the net assets transferred as of October 1, 2014:

Exploration and evaluation assets Property, plant and equipment Cost Accumulated depletion and depreciation Decommissioning obligations Carrying value of net assets transferred	C$’000 104,700 2,126,276 (1,154,358) (290,518) 786,100

The difference between the consideration of C$537 million and the carrying value of acquired assets is recognized as common control transaction reserve in Partners’ equity, as follows:

Partnership capital contribution Carrying value of net assets transferred Partnership contribution loan conversion Common control transaction reserve	C$’000 1,135,667 (786,100) (598,667) (249,100)

The following table summarizes the adjustments made to the provisional amounts stated above as a result of obtaining information required to reliably measure the transfer of net assets in the Acquisition:

	Provisional
	amounts as at	Adjustments to	Final amounts as
	December 31,	provisional	at December 31,
	2014	amounts	2015
	C$’000	C$’000	C$’000
Property, plant and equipment
Cost	2,126,276	19,526	2,145,802
Accumulated depletion and depreciation	(1,154,358)	(9,174)	(1,163,532)
Net working capital	—	4,709	4,709
Common control transaction reserve	(249,100)	(15,061)	(264,161)

– II-22 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

9 EXPLORATION AND EVALUATION ASSETS

Cost Balance — Beginning of year/period Disposals (notes 6, 7) Common control transaction (note 8) Additions Transfer to property, plant and equipment Impairment Lease expiries Balance — End of year/period	Year ended December 31, 2014 C$’000 140,710 — 104,700 16,433 — — (349) 261,494	Year ended December 31, 2015 C$’000 261,494 (2,726) — 8,908 — (65,075) (3,597) 199,004	Year ended December 31, 2016 C$’000 199,004 (188) — 6,670 (759) — (11,592) 193,135	Period ended March 31, 2017 C$’000 193,135 (102 — 1,643 — (19,371 (2,665
				172,640

At March 31, 2017, the Target Group calculated the recoverable amount as the fair value less costs of disposal based on the market price observed in the subsequent transaction described in note 22. As a result of the test, the Target Group determined that the recoverable amount was lower than the remaining carrying value of the assets, and as such, an impairment of C$19.4 million was recorded.

At December 31, 2015, as a result of declining commodity prices, the Target Group performed an impairment test on its E&E assets. The recoverable amounts were calculated as the fair value less costs of disposal using a discounted cash flow model. As a result of the test, the Target Group determined that the recoverable amount was lower than the remaining carrying value of the assets, and as such, an impairment of C$65.1 million was recorded. A further impairment test was performed by the Target Group at December 31, 2016. The Target Group determined that the recoverable amount exceeded the remaining carrying value of the assets, and as such, no impairment was recorded.

10 PROPERTY, PLANT AND EQUIPMENT

Cost Balance — Beginning of year/period Capital additions Acquisitions (note 6) Transfer from exploration and evaluation assets Disposals (note 7) Common control transaction (note 8) Change in asset retirement obligation (note 13) Balance — End of year/period Accumulated depletion, depreciation and amortization Balance — Beginning of year/period Depletion, depreciation and amortization Disposals (notes 6, 7) Common control transaction (note 8) Impairment Balance — End of year/period Net book value — End of year/period	Year ended December 31, 2014 C$’000 1,268,436 136,211 85,562 — (6,726) 2,126,276 (342,744) 3,267,015 30,311 173,318 (2,660) 1,154,358 80,134 1,435,461 1,831,554	Year ended December 31, 2015 C$’000 3,267,015 103,437 — — (8,200) 19,526 (57,997) 3,323,781 1,435,461 228,121 — 9,174 381,313 2,054,069 1,269,712	Year ended December 31, 2016 C$’000 3,323,781 41,576 — 759 (2,151) — (28,605) 3,335,360 2,054,069 125,459 — — — 2,179,528 1,155,832	Period ended March 31, 2017 C$’000 3,335,360 20,573 — — — — 31,150
				3,387,083
				2,179,528 29,801 — — 115,674
				2,325,003
				1,062,080

– II-23 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

During 2016 the Target Group finalized the April 15, 2013 acquisition of a partnership from Suncor Energy Inc. and recognized a gain related to post-closing purchase price adjustments of C$13.3 million in net loss. The adjustments occurred after the measurement period (12 months from closing date) and are treated as a change in estimate in the current year. As the final purchase price adjustments have been recorded directly in net loss, there were no fair value adjustments made to the allocation of the purchase price. See supplemental cash flow information (note 19) for additional information.

During the years ended December 31, 2014, 2015, and 2016 and the periods ended March 31, 2016 and 2017, the Target Group capitalized salaries and wages of C$3.6 million; C$8.7 million; C$4.1 million; C$1.2 million; and C$1.0 million, within PP&E. These costs were determined to be directly attributable to bringing an asset to the location and condition necessary for it to be capable of use in the manner intended by management.

At December 31, 2014, 2015 and 2016, the Target Group calculated the recoverable amount as the fair value less costs of disposal using a discounted cash flow model. The following key assumptions were used in developing the cash flow model and applied over the fifty year expected life of the CGUs:

	December 31, 2014	December 31, 2015	December 31, 2016
Oil Price	C$54.90/bbl–C$59.58/bbl	C$40.63/bbl–C$275.10/bbl	C$56.83/bbl–C$269.65/bbl
Gas Price	C$2.56/mcf–C$2.88/mcf	C$2.31/mcf–C$12.98/mcf	C$2.04/mcf–C$14.81/mcf
After-tax Discount Rate	9%	9%	9%

At December 31, 2014, 2015 and 2016, the Target Group recorded impairment expense of C$80.1 million; C$381.3 million; and C$nil respectively, as a result of declining forward commodity prices for natural gas and crude oil and was allocated among CGUs as follows:

Foothills Hanlan Robb Peace River Arch North South Total	Year ended December 31, 2014 C$’000 34,571 — — — 45,563 80,134	Year ended December 31, 2015 C$’000 141,674 — 113,454 104,436 21,749 381,313	Period ended March 31, 2017 C$’000 25,030 23,423 8,075 37,282 21,864
			115,674

At December 31, 2014, 2015 and 2016, a 10 percent decrease in the commodity prices over the expected life of the assets would result in impairment to PP&E of C$38.0 million; C$214.0 million; and C$98.2 million respectively. At December 31, 2014, 2015 and 2016, a 10 percent increase in the commodity prices over the expected life of the assets would reduce impairment to PP&E by C$43.4 million; C$192.5 million; and C$nil respectively.

– II-24 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

11 GOODWILL

Cost Balance — Beginning of year Post-closing purchase price adjustment Impairment Balance — End of year	Year ended December 31, 2014 C$’000 119,673 (7,335) — 112,338	Year ended December 31, 2015 C$’000 112,338 — (112,338
		—

For the purposes of determining whether impairment of goodwill has occurred, management exercises their judgment in estimating future cash flows for the recoverable amount, being the higher of fair value less costs of disposal and value in use. The estimated recoverable amounts used in the impairment calculation of goodwill are equivalent to those used to test for impairment of property, plant and equipment and exploration and evaluation assets, less estimated corporate administrative overlays.

Goodwill recorded in 2015 was tested for impairment at the Target Group level. This recoverable amount did not exceed the carrying value of the CGUs, including goodwill, and as such, Goodwill impairment expense of C$112.3 million was recorded. There was no goodwill recorded at March 31, 2017.

12 NOTES PAYABLE

The balance of Notes Payable is comprised of the following:

Year of Issue 2015 Notes Current Note payable to 1773648 Alberta Ltd 2015 Note payable to A Partner 2015 Balance — End of year/period 2013 Notes Non-current Note payable to 1773648 Alberta Ltd 2013 Note payable to A Partner 2013 Balance — End of year/period Current Note payable to 1773648 Alberta Ltd 2013 Note payable to A Partner 2013 Balance — End of year/period	Year ended December 31, 2014 C$’000 — — — 30,000 20,000 50,000 — — —	Year ended December 31, 2015 C$’000 11,400 7,600 19,000 30,000 20,000 50,000 — — —	Year ended December 31, 2016 C$’000 — — — 30,000 20,000 50,000 — — —	Period ended March 31, 2017 C$’000 — —
				—
				— —
				— 30,000 20,000
				50,000

– II-25 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

In May 2015, the Target Group issued promissory notes to 1773648 Alberta Ltd and A Partner in the amount of C$11.4 million and C$7.6 million, respectively. Both promissory notes are non-interest bearing and were due to mature on June 30, 2015. The Target Group entered into an agreement whereby the maturity date was extended until March 31, 2016. On February 5, 2016, the Target Group settled the full amounts in cash.

The 2013 Note Payable to 1773648 Alberta Ltd and A Partner are non-interest bearing and due upon the date of completion of certain conditions or such other date as agreed with the Target Group and DERP. Should the balance not be repaid at the maturity date, interest accrues at Canadian prime plus 1%. In advance of the closing of the transaction described in note 22, the Target Group will convert the amounts to partner capital. The full amounts are classified as current as at March 31, 2017.

At December 31, 2014, 2015, and 2016 and at March 31, 2017, the fair value of the Notes payable was C$50.0 million; C$69.0 million; C$50.0 million; and C$50.0 million respectively.

13 ASSET RETIREMENT OBLIGATION

The total future asset retirement obligations were estimated by management based on the Target Group’s net ownership interest in all wells and facilities, estimated costs to reclaim and abandon the wells, pipelines and facilities and the estimated timing of the costs to be incurred in future periods. At December 31, 2014, 2015, and 2016 and at March 31, 2017, the Target Group has estimated the net present value of its total asset retirement obligations to be C$589.1 million; C$530.4 million, C$515.8 million; and C$548.2 million respectively, based on a total future undiscounted liability of C$2.6 billion; C$1.5 billion; C$1.4 billion; and C$1.4 billion respectively. At each period presented, management estimates that these payments are expected to be made over the next 50 years with the majority being made in the latter quarter of the 50 year period. At December 31, 2014, 2015, and 2016 and at March 31, 2017, a credit-adjusted rate of 6.75%; 6.75%; 6.75% and 6.40%, respectively and inflation rate of 2.0% for each period were used to calculate the present value of the asset retirement obligations.

Balance — Beginning of year/period Obligations acquired (note 6) Obligations disposed (note 6, 7) Settlement of reclamation liabilities during the year Revisions to estimates Common control transaction (note 8) Post-closing purchase price adjustments Accretion expense Less: current portion Balance — End of year/period	Year ended December 31, 2014 C$’000 611,593 30,462 (5,600) (10,691) (342,744) 290,518 (10,000) 25,556 589,094 (12,750) 576,344	Year ended December 31, 2015 C$’000 589,094 — (12,175) (15,727) (57,997) — — 27,198 530,393 (21,697) 508,696	Year ended December 31, 2016 C$’000 530,393 — (1,370) (9,310) (28,605) — — 24,699 515,807 (14,341) 501,466	Period ended March 31, 2017 C$’000 515,807 — — (4,736) 31,150 — — 6,005 548,226 (14,341) 533,885

During each period presented, the Target Group reassessed cost estimates and the timing of cash out-flows related to its asset retirement obligations. These assessments were based on the most recent and relevant information available as at each reporting date to make such estimates and resulted in a decrease in the estimate of the Target Group’s asset retirement obligation at December 31, 2014, 2015, and 2016 and at March 31, 2017 of C$342.7 million; C$58.0 million; C$28.6 million; and an increase C$31.2 million respectively.

– II-26 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

14 FINANCIAL INSTRUMENTS

Financial instruments of the Target Group include cash and cash equivalents, accounts receivables, accounts payable and accrued liabilities, due from (to) related party and notes payable.

Fair value is determined following a three level hierarchy:

Level 1: Quoted prices in active markets for identical assets and liabilities. The Target Group uses Level 1 inputs to determine the fair value of the Notes Payable (note 12).

Level 2: Inputs other than quoted prices included within Level 1 that are observable, either directly or indirectly. Such inputs can be corroborated with other observable inputs for substantially the complete term of the contract.

Level 3: Under this level, fair value is determined using inputs that are not observable. The fair value calculation of the Target Group’s E&E and PP&E uses Level 3 inputs. See exploration and evaluation assets (note 9) and property plant and equipment (note 10) for additional information.

The carrying value of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, due to/from related parties included in the balance sheet approximate fair value due to the short-term nature of those instruments.

15 PARTNERS’ CAPITAL

On June 30, September 30, and December 31, 2014, resolutions by the Management Committee were made to distribute a total of C$82.2 million to the partners based on their share of Target Group interest. Of the C$82.2 million in distributions paid and payable, C$25.1 million was distributed through retained earnings.

On October 1, 2014, C$215 million of the cash received by the Target Group was used to repay a portion of a note payable to 1773648 Alberta Ltd, and C$538 million was issued to Centrica Energy Canada in exchange for assets. On October 1, 2014, C$144 million and C$239 million of the remaining note payable to 1773648 Alberta Ltd and A Partner, respectively, were assigned to DERP and A Partner, and subsequently converted into partner’s capital. Refer to Note 8 for total Target Group contribution. C$15.1 million was reversed out of partners’ capital in 2014 due to change in Partner funding on a prior year post close adjustment; the Partners were no longer required to fund the post-close adjustment so their partner capital was reduced by this amount.

On December 19, 2016 a resolution by the Management Committee was made to distribute C$55 million to the partners based on their share of Target Group interest. As at December 31, 2016, C$40 million of this was paid. The remainder was paid on March 23, 2017.

On January 12, 2017, a resolution by the Management Committee was made to distribute C$5.8 million to the partners based on their share of Target Group interest. As at March 31, 2017, the entire balance was paid.

– II-27 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

16 SALES

Oil Natural gas Natural gas liquids Sulphur Royalty income and other Oil and natural gas sales	Year ended December 31, 2014 C$’000 76,034 400,409 60,600 16,686 15,640 569,369	Year ended December 31, 2015 C$’000 102,084 329,547 10,553 22,938 13,221 478,343	Year ended December 31, 2016 C$’000 74,912 233,979 9,753 6,219 9,298 334,161	Period ended March 31, 2016 C$’000 (unaudited) 14,626 60,127 1,321 3,051 1,339 80,464	Period ended March 31, 2017 C$’000 23,085 81,730 4,200 1,765 2,930
					113,710

17 GENERAL AND ADMINISTRATIVE EXPENSES

Staff salaries and benefits Rent and insurance Office and other costs Overhead recoveries Allocations Bad debt expense	Year ended December 31, 2014 C$’000 32,400 1,964 10,401 (15,152) 9,597 — 39,210	Year ended December 31, 2015 C$’000 54,873 2,953 15,100 (23,034) 4,486 — 54,378	Year ended December 31, 2016 C$’000 38,104 2,121 11,106 (16,574) 3,375 1,180 39,312	Period ended March 31, 2016 C$’000 (unaudited) 12,991 673 2,294 (3,575) 1,056 25 13,464	Period ended March 31, 2017 C$’000 8,997 288 2,169 (4,146 869 424
					8,601

18 SHARE-BASED COMPENSATION

The Target Group’s share-based awards are granted under the On Track Incentive Plan (‘‘OTIP’’) of Centrica PLC and are accounted for as an equity-settled plan. The fair values of awards granted under the OTIP are measured at market value on the grant date. The awards vest subject to continued employment in two stages: half after two years and the other half after three years. At the vesting dates, participants have the right to acquire shares at nil cost.

Total compensation expense recognized in the Consolidated Statements of Net loss and Comprehensive loss is as follows:

Direct operating expense General and administrative	Year ended December 31, 2014 C$’000 153 1,688 1,841	Year ended December 31, 2015 C$’000 427 3,234 3,661	Year ended December 31, 2016 C$’000 574 3,900 4,474	Period ended March 31, 2016 C$’000 (unaudited) 144 975 1,119	Period ended March 31, 2017 C$’000 103 925
					1,028

– II-28 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

19 SUPPLEMENTAL CASH FLOW INFORMATION

The following tables provide a detailed breakdown of certain line items contained within cash flow from operating and investing activities:

Operating activities Changes in non-cash working capital Due from partners Accounts receivable Prepaid expenses Due to/from related parties Accounts payable and accrued liabilities Working capital on post-closing adjustments Investing activities Changes in non-cash working capital Accounts payable and accrued liabilities Financing activities Changes in non-cash working capital Partnership distribution payable Due from related parties	Year ended December 31, 2014 C$’000 2,620 (37,019) (1,326) (48,081) 49,725 — (34,081) 37,639 37,639 15,000 (14,846) 154	Year ended December 31, 2015 C$’000 12,226 (2,321) 2,977 7,598 9,891 — 30,371 (44,784) (44,784) — — —	Year ended December 31, 2016 C$’000 — 18,150 (2,799) (6,832) (31,436) 13,346 (9,571) 1,098 1,098 — — —	Period ended March 31, 2016 C$’000 (unaudited) — 5,789 (1,926) 11,834 3,526 — 19,223 (2,965) (2,965) — — —	Period ended March 31, 2017 C$’000 — 7,748 705 1,629 5,648 — 15,730 5,622 5,622 (15,000) — (15,000)

Included within operating activities for 2016 are amounts related to accounts receivable and accounts payable whereby the Target Group made adjustments based on the Suncor acquisition (see note 10 for additional information).

Included within operating activities for 2015 are amounts related to prepaid expenses whereby the Target Group made adjustments to provisional amounts recorded in the common control transaction of C$4.7 million. The Target Group disposed of C$0.7 million of prepaid expenses as a result of the asset disposals in August 2015 (see note 7 and 8 for additional information).

– II-29 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

20 RELATED PARTY TRANSACTIONS

(i) The followings transactions and balances were carried out with related parties:

During the years ended December 31, 2014, 2015, 2016 and the periods ended March 31, 2016 and 2017, the Target Group sold a portion of its natural gas production to DEML. Revenue of C$383.9 million; C$313.8 million; C$220.8 million; C$55.4 million and C$77.7 million, respectively, was recorded at the exchange amount. This accounted for 67%; 65%; 66%; 69%; and 70%, respectively, of the Target Group’s revenue. The Target Group is charged a fee by Centrica Energy PLC and DEML for corporate support. During the years ended December 31, 2014, 2015, 2016 and the periods ended March 31, 2016 and 2017, the Target Group recorded C$9.6 million, C$4.5 million, C$3.4 million, C$1.1 million and C$0.9 million, respectively, of expenses and the entire amount was recorded as due to related party at each period end. The amount is recorded at exchange amount.

The Target Group’s notes payable are transactions with related parties. See note 12 for additional information.

(ii) The balance of due (to) from related parties is comprised of the following:

Direct Energy Resources Partnership Centrica PLC Balance — End of year/period	Year ended December 31, 2014 C$’000 — — —	Year ended December 31, 2015 C$’000 (6,962) (636) (7,598)	Year ended December 31, 2016 C$’000 349 (1,095) (746)	Period ended March 31, 2017 C$’000 (1,280 (1,122
				(2,402

The amounts are non-interest bearing.

(iii) Key Management compensation:

Salaries Bonuses Share-based compensation	Year ended December 31, 2014 C$’000 2,543 1,207 403 4,153	Year ended December 31, 2015 C$’000 2,377 1,226 884 4,487	Year ended December 31, 2016 C$’000 2,416 1,639 2,153 6,208	Period ended March 31, 2016 C$’000 (unaudited) 604 425 538 1,567	Period ended March 31, 2017 C$’000 620 235 483
					1,338

– II-30 –

ACCOUNTANT’S REPORT ON THE TARGET GROUP

APPENDIX II

21 COMMITMENTS AND CONTINGENCIES

The Target Group is committed to future payments under the following agreements:

Payments due by period/year As at March 31, 2017 Operating leases Capital commitments Firm transportation commitments As at December 31, 2016 Operating leases Capital commitments Firm transportation commitments As at December 31, 2015 Operating leases Capital commitments Firm transportation commitments As at December 31, 2014 Operating leases Capital commitments Firm transportation commitments	1 year C$’000 2,825 40,493 19,759 63,077 3,191 13,418 26,139 42,748 3,492 15,079 21,744 40,315 7,539 12,138 24,362 44,039	2–3 year C$’000 2,538 — 21,342 23,880 3,079 — 34,251 37,330 90 — 27,503 27,593 1,637 — 33,890 35,527	4–5 years C$’000 — — 15,748 15,748 293 — 17,507 17,800 — — 11,960 11,960 144 — 6,249 6,393	45 years C$’000 — — 20,095 20,095 — — 6,063 6,063 — — 5,098 5,098 — — 5,938 5,938	Total C$’000 5,363 40,493 76,944
					122,800
					6,563 13,418 83,960
					103,941
					3,582 15,079 66,305
					84,966
					9,320 12,138 70,439
					91,897

The Target Group is involved in various claims and litigation in the normal course of business and records provisions for claims if considered more than probable. At December 31, 2014, 2015 and 2016 and at March 31, 2017, the Target Group recorded C$nil in provisions for claims and litigation.

22 SUBSEQUENT EVENTS

On May 31, 2017, the Target Group entered into the Purchase Agreement with HK Listco, and its subsidiary, the Purchaser, Canlin Energy Corporation, pursuant to which it agreed to sell all of its interest in its sole whollyowned operating subsidiary to the Purchaser. The initial purchase price is C$722 million and is subject to various closing adjustments.

23 SUBSEQUENT FINANCIAL STATEMENTS

No audited financial statements have been prepared by the Target or any of its subsidiaries in respect of any period subsequent to March 31, 2017 and up to the date of this report. No dividend or distribution has been declared or made by the Target or any of its subsidiaries in respect of any period subsequent to March 31, 2017.

– II-31 –

UNAUDITED PRO FORMA FINANCIAL INFORMATION OF THE ENLARGED GROUP

APPENDIX III

The following is the text of a report received from PricewaterhouseCoopers, Certified Public Accountants, Hong Kong, for the purpose of incorporation in this circular.

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INDEPENDENT REPORTING ACCOUNTANT’S ASSURANCE REPORT ON THE COMPILATION OF UNAUDITED PRO FORMA FINANCIAL INFORMATION

TO THE DIRECTORS OF MIE HOLDINGS CORPORATION

We have completed our assurance engagement to report on the compilation of unaudited pro forma financial information of MIE Holdings Corporation (the ‘‘Company’’) and its subsidiaries (collectively the ‘‘Group’’), and CQ Energy Canada Partnership and its subsidiaries (the ‘‘Target Group’’) (collectively the ‘‘Enlarged Group’’) by the directors for illustrative purposes only. The unaudited pro forma financial information consists of the unaudited pro forma consolidated statement of financial position as at June 30, 2017, the unaudited pro forma consolidated statement of comprehensive income for the year ended December 31, 2016, the unaudited pro forma consolidated statement of cash flows for the year ended December 31, 2016, and related notes (the ‘‘Unaudited Pro Forma Financial Information’’) as set out on pages III-4 to III-14 of the Company’s circular dated September 7, 2017, in connection with the proposed acquisition of the entire interest in the Target Group (the ‘‘Transaction’’) by the Group. The applicable criteria on the basis of which the directors have compiled the Unaudited Pro Forma Financial Information are described on pages III-4 to III-14.

The Unaudited Pro Forma Financial Information has been compiled by the directors to illustrate the impact of the Transaction on the Group’s financial position as at June 30, 2017 and the Group’s financial performance and cash flows for the period ended December 31, 2016 as if the Transaction had taken place at June 30, 2017 and January 1, 2016 respectively. As part of this process, information about the Group’s financial position has been extracted by the directors from the Group’s financial statement for the six months ended June 30, 2017, on which no audit or review report has been published, and financial performance and cash flows has been extracted by the directors from the Group’s financial statements for the year ended December 31, 2016, on which an audit report has been published.

– III-1 –

UNAUDITED PRO FORMA FINANCIAL INFORMATION OF THE ENLARGED GROUP

APPENDIX III

Directors’ Responsibility for the Unaudited Pro Forma Financial Information

The directors are responsible for compiling the Unaudited Pro Forma Financial Information in accordance with paragraph 4.29 of the Rules Governing the Listing of Securities on The Stock Exchange of Hong Kong Limited (the ‘‘Listing Rules’’) and with reference to Accounting Guideline 7 Preparation of Pro Forma Financial Information for Inclusion in Investment Circulars (‘‘AG 7’’) issued by the Hong Kong Institute of Certified Public Accountants (‘‘HKICPA’’).

Our Independence and Quality Control

We have complied with the independence and other ethical requirements of the Code of Ethics for Professional Accountants issued by the HKICPA, which is founded on fundamental principles of integrity, objectivity, professional competence and due care, confidentiality and professional behaviour.

Our firm applies Hong Kong Standard on Quality Control 1 issued by the HKICPA and accordingly maintains a comprehensive system of quality control including documented policies and procedures regarding compliance with ethical requirements, professional standards and applicable legal and regulatory requirements.

Reporting Accountant’s Responsibilities

Our responsibility is to express an opinion, as required by paragraph 4.29(7) of the Listing Rules, on the Unaudited Pro Forma Financial Information and to report our opinion to you. We do not accept any responsibility for any reports previously given by us on any financial information used in the compilation of the Unaudited Pro Forma Financial Information beyond that owed to those to whom those reports were addressed by us at the dates of their issue.

We conducted our engagement in accordance with Hong Kong Standard on Assurance Engagements 3420, Assurance Engagements to Report on the Compilation of Pro Forma Financial Information Included in a Prospectus, issued by the HKICPA. This standard requires that the reporting accountant plans and performs procedures to obtain reasonable assurance about whether the directors have compiled the Unaudited Pro Forma Financial Information in accordance with paragraph 4.29 of the Listing Rules and with reference to AG 7 issued by the HKICPA.

For purposes of this engagement, we are not responsible for updating or reissuing any reports or opinions on any historical financial information used in compiling the Unaudited Pro Forma Financial Information, nor have we, in the course of this engagement, performed an audit or review of the financial information used in compiling the Unaudited Pro Forma Financial Information.

The purpose of unaudited pro forma financial information included in a circular is solely to illustrate the impact of a significant event or transaction on unadjusted financial information of the entity as if the event had occurred or the transaction had been undertaken at an earlier date

– III-2 –

UNAUDITED PRO FORMA FINANCIAL INFORMATION OF THE ENLARGED GROUP

APPENDIX III

selected for purposes of the illustration. Accordingly, we do not provide any assurance that the actual outcome of the Transaction at June 30, 2017 or January 1, 2016 would have been as presented.

A reasonable assurance engagement to report on whether the unaudited pro forma financial information has been properly compiled on the basis of the applicable criteria involves performing procedures to assess whether the applicable criteria used by the directors in the compilation of the unaudited pro forma financial information provide a reasonable basis for presenting the significant effects directly attributable to the event or transaction, and to obtain sufficient appropriate evidence about whether:

. The related pro forma adjustments give appropriate effect to those criteria; and
. The unaudited pro forma financial information reflects the proper application of those adjustments to the unadjusted financial information.

The procedures selected depend on the reporting accountant’s judgment, having regard to the reporting accountant’s understanding of the nature of the company, the event or transaction in respect of which the unaudited pro forma financial information has been compiled, and other relevant engagement circumstances.

The engagement also involves evaluating the overall presentation of the unaudited pro forma financial information.

We believe that the evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.

Opinion

In our opinion:

(a) the Unaudited Pro Forma Financial Information has been properly compiled by the directors of the Company on the basis stated;
(b) such basis is consistent with the accounting policies of the Group; and
(c) the adjustments are appropriate for the purposes of the Unaudited Pro Forma Financial Information as disclosed pursuant to paragraph 4.29(1) of the Listing Rules.

PricewaterhouseCoopers Certified Public Accountants Hong Kong, September 7, 2017

– III-3 –

UNAUDITED PRO FORMA FINANCIAL INFORMATION OF THE ENLARGED GROUP

APPENDIX III

UNAUDITED PRO FORMA FINANCIAL INFORMATION OF THE ENLARGED GROUP

INTRODUCTION

The following is an illustrative unaudited pro forma consolidated statement of financial position, unaudited pro forma consolidated statement of comprehensive income, and unaudited pro forma consolidated statement of cash flows (the ‘‘Unaudited Pro Forma Financial Information’’) of MIE Holdings Corporation and its subsidiaries (the ‘‘Group’’) and CQ Energy Canada Partnership and its subsidiaries (the ‘‘Target Group’’) (hereinafter collectively referred to as the ‘‘Enlarged Group’’) which have been prepared on the basis of the notes set out below for the purpose of illustrating the effect of the proposed acquisition by the Group of the Target Group (the ‘‘Transaction’’) as if it had taken place on June 30, 2017 for the unaudited pro forma consolidated statement of financial position and as if it had taken place on January 1, 2016 for the unaudited pro forma consolidated statement of comprehensive income and the unaudited pro forma consolidated statement of cash flows.

The Unaudited Pro Forma Financial Information has been prepared by the directors of the Company in accordance with paragraph 4.29 of the Rules Governing the Listing of Securities on The Stock Exchange of Hong Kong Limited for illustrative purposes only and because of its hypothetical nature, it may not give a true picture of the financial position of the Enlarged Group had the Transaction been completed on June 30, 2017 and comprehensive income and cash flows of the Enlarged Group had the Transaction been completed on January 1, 2016, or any future dates.

The Unaudited Pro Forma Financial Information has been prepared based on the unaudited condensed interim consolidated statement of financial position of the Group as at June 30, 2017, which has been extracted from the Group’s published interim report, the audited consolidated statement of comprehensive income and audited consolidated statement of cash flows of the Group for the year ended December 31, 2016, which has been extracted from the Group’s published annual report; and the consolidated balance sheet as at March 31, 2017, consolidated statement of net loss and comprehensive loss and consolidated statement of cash flows for the year ended December 31, 2016 of the Target Group, which has been derived from the historical financial information included in the accountant’s report as set out in Appendix II to this circular.

The Unaudited Pro Forma Financial Information has been prepared under accounting policies consistent with those of the Group as set out in the published annual report of the Company for the year ended December 31, 2016.

The Unaudited Pro Forma Financial Information should be read in conjunction with the historical financial information of the Group as set out in Appendix I and the historical financial information of the Target Group as set out in Appendix II to this circular and other financial information included elsewhere in this circular.

– III-4 –

UNAUDITED PRO FORMA FINANCIAL INFORMATION OF THE ENLARGED GROUP

APPENDIX III

(i) Unaudited pro forma consolidated statement of financial position

	Pro forma adjustments	Pro forma adjustments	Pro forma adjustments	Unaudited pro forma consolidated statement of financial position of the Enlarged Group as at June 30, 2017 RMB’000 8,668,822 14,009 256,476 2,845 52,231 1,541,832 44,877
Consolidated balance sheet of the Target Group as at March 31, 2017 RMB’000 (Note 2) 6,391,158 — — — — — — 6,391,158 — 120,264 — 125,430 — 373,566 619,260 7,010,418 6,762,234 — (3,423,585) 3,338,649 — 3,338,649	RMB’000 (Note 3) 19,732 — — — — — — 19,732 — — — — — — — 19,732 — 14,602 — 14,602 — 14,602	RMB’000 (Note 4) — 7,966 — — — — — 7,966 — — — — — (3,620,027) (3,620,027) (3,612,061) (6,762,234) (14,602) 3,423,585 (3,353,251) — (3,353,251)	RMB’000 (Note 5) — — — — — — — — — — — — — 4,397,320 4,397,320 4,397,320 — — — — — —
				10,581,092
				24,579 564,874 113,526 219,898 446 2,308,097
				3,231,420
				13,812,512
				1,068,796 (84,836 (1,042,671
				(58,711 (27
				(58,738

– III-5 –

UNAUDITED PRO FORMA FINANCIAL INFORMATION OF THE ENLARGED GROUP

APPENDIX III

Pro forma adjustments

LIABILITIES Non-current liabilities Borrowings Deferred income tax liabilities Trade and notes payable Provisions, accruals and other liabilities Current liabilities Trade and notes payable Provisions, accruals and other liabilities Current income tax liabilities Financial liabilities at fair value through profit or loss Borrowings TOTAL LIABILITIES TOTAL EQUITY AND LIABILITIES	Unaudited condensed interim consolidated statement of financial position of the Group as at June 30, 2017 RMB’000 (Note 1) 4,129,256 90,423 21,817 66,177 4,307,673 47,886 219,273 55,145 — 1,341,758 1,664,062 5,971,735 5,997,103	Consolidated balance sheet of the Target Group as at March 31, 2017 RMB’000 (Note 2) — — — 2,763,496 2,763,496 356,552 551,721 — — — 908,273 3,671,769 7,010,418	RMB’000 (Note 3) — 5,130 — — 5,130 — — — — — — 5,130 19,732	RMB’000 (Note 4) — — — — — (258,810) — — — — (258,810) (258,810) (3,612,061)	RMB’000 (Note 5) 3,341,375 — — — 3,341,375 — — — 1,055,945 — 1,055,945 4,397,320 4,397,320	RMB’000 (Note 6) — — — — — — 84,106 — — — 84,106 84,106 —	Unaudited pro forma consolidated statement of financial position of the Enlarged Group as at June 30, 2017 RMB’000 7,470,631 95,553 21,817 2,829,673
							10,417,674
							145,628 855,100 55,145 1,055,945 1,341,758
							3,453,576
							13,871,250
							13,812,512

– III-6 –

UNAUDITED PRO FORMA FINANCIAL INFORMATION OF THE ENLARGED GROUP

APPENDIX III

(ii) Unaudited pro forma consolidated statement of comprehensive income

Pro forma adjustments	Pro forma adjustments	Pro forma adjustments	Unaudited pro forma consolidated statement of comprehensive income of the Enlarged Group for the year ended December 31, 2016 RMB’000 2,117,350
Consolidated statement of net loss and comprehensive loss of the Target Group for the year ended December 31, 2016 RMB’000 (Note 2) 1,582,376 (630,896) — (191,614) (729,353) (140,768) (6,075) — 123,711 — (123,882) — — (116,501) —	RMB’000 (Note 6) — — — — — — (84,106) — — — — — — (84,106) —	RMB’000 (Note 7) — (1,831) — — — — — — — — — — — (1,831) 476
			(996,587 (13,414 (324,905 (834,926 (158,940 (157,847 (234,667 313,442
			17,490 (857,592 35,682 (3,382
			(1,098,296 (146,690

– III-7 –

UNAUDITED PRO FORMA FINANCIAL INFORMATION OF THE ENLARGED GROUP

APPENDIX III

Pro forma adjustments

Loss for the year from continuing operations Discontinued operations Loss for the year from discontinued operations Loss for the year Other comprehensive income/ (loss): Items that may be reclassified to profit or loss Change in value of available- for-sale financial assets Share of other comprehensive income of investments in associates Currency translation differences Other comprehensive loss for the year, net of tax Total comprehensive (loss)/ income for the year	Audited consolidated statement of comprehensive income of the Group for the year ended December 31, 2016 RMB’000 (Note 1) (605,147) (717,086) (1,322,233) 18,405 2,799 (129,976) (108,772) (1,431,005)	Consolidated statement of net loss and comprehensive loss of the Target Group for the year ended December 31, 2016 RMB’000 (Note 2) (116,501) — (116,501) — — — — (116,501)	RMB’000 (Note 6) (84,106) — (84,106) — — 390,839 390,839 306,733	RMB’000 (Note 7) (1,355) — (1,355) — — — — (1,355)	RMB’000 (Note 8) (437,877) — (437,877) — — — — (437,877)	Unaudited pro forma consolidated statement of comprehensive income of the Enlarged Group for the year ended December 31, 2016 RMB’000 (1,244,986
						(717,086
						(1,962,072
						18,405 2,799 260,863
						282,067
						(1,680,005

– III-8 –

UNAUDITED PRO FORMA FINANCIAL INFORMATION OF THE ENLARGED GROUP

APPENDIX III

(iii) Unaudited pro forma consolidated statement of cash flows

Pro forma adjustments Consolidated statement of cash flows of the Target Group for the year ended December 31, 2016 RMB’000 RMB’000 RMB’000 (Note 2) (Note 4, 6) (Note 5, 8) 480,688 (84,106) — — — (309,959) — — — — — (82,068) — — — 480,688 (84,106) (392,027) (183,698) — — — — — — — — — — — — — — — — — — — — — (3,620,027) — 5,522 — — — — — (178,176) (3,620,027) —	Pro forma adjustments Consolidated statement of cash flows of the Target Group for the year ended December 31, 2016 RMB’000 RMB’000 RMB’000 (Note 2) (Note 4, 6) (Note 5, 8) 480,688 (84,106) — — — (309,959) — — — — — (82,068) — — — 480,688 (84,106) (392,027) (183,698) — — — — — — — — — — — — — — — — — — — — — (3,620,027) — 5,522 — — — — — (178,176) (3,620,027) —	Unaudited pro forma consolidated statement of cash flow of the Enlarged Group for the year ended December 31, 2016 RMB’000 559,324 (692,956 (69,567 (82,068 (81,057
Consolidated statement of cash flows of the Target Group for the year ended December 31, 2016 RMB’000 (Note 2) 480,688 — — — — 480,688 (183,698) — — — — — — — 5,522 — (178,176)	RMB’000 (Note 4, 6) (84,106) — — — — (84,106) — — — — — — — (3,620,027) — — (3,620,027)
		(366,324
		(205,319 462,646 (96,422 2,283,724 (375,045 (277,007 20,171 (3,620,027 5,522 (205,736
		(2,007,493

– III-9 –

UNAUDITED PRO FORMA FINANCIAL INFORMATION OF THE ENLARGED GROUP

APPENDIX III

Pro forma adjustments

Cash flows from financing activities Continuing operations Repayments of borrowings Proceeds from financing facilities Proceeds from issuance of Convertible Preferred Shares Payment for repurchase and cancellation of 2019 Notes Cash paid to non-controlling interest for additional interest in subsidiary Payments relating to share-based compensation Repayment of issuance of notes Partnership distribution Others Net cash (used in)/generated from financing activities Net increase/(decrease) in cash and cash equivalents Cash and cash equivalents at beginning of the period Exchange gains on cash and cash equivalents Cash and cash equivalents at end of the period	Audited consolidated statement of cash flows of the Group for the year ended December 31, 2016 RMB’000 (Note 1) (930,224) 491,534 — (110,739) (103,919) (63,706) — — (33,206) (750,260) 669,571 202,967 32,423 904,961	Consolidated statement of cash flows of the Target Group for the year ended December 31, 2016 RMB’000 (Note 2) — — — — — — (95,545) (276,579) — (372,124) (69,612) 334,846 — 265,234	RMB’000 (Note 4, 6) — — — — — — — — — — (3,704,133)	RMB’000 (Note 5, 8) — 3,341,375 1,055,945 — — — — — — 4,397,320 4,005,293	Unaudited pro forma consolidated statement of cash flow of the Enlarged Group for the year ended December 31, 2016 RMB’000 (930,224 3,832,909 1,055,945 (110,739 (103,919 (63,706 (95,545 (276,579 (33,206
					3,274,936
					901,119 537,813 32,423
					1,471,355

– III-10 –

UNAUDITED PRO FORMA FINANCIAL INFORMATION OF THE ENLARGED GROUP

APPENDIX III

Notes:

The amounts are extracted from the unaudited condensed interim consolidated statement of financial position of the Group as at June 30, 2017 as set out in the published interim report of the Group for the six months ended June 30, 2017 and the audited consolidated statement of comprehensive income and the audited consolidated statement of cash flows of the Group for the year ended December 31, 2016 as set out in the published annual report of the Group for the year ended December 31, 2016.
The amounts are derived from the consolidated balance sheet of the Target Group as at March 31, 2017 and the consolidated statement of net loss and comprehensive loss and the consolidated statement of cash flows of the Target Group for the year ended December 31, 2016 as set out in Appendix II to this circular. For the purpose of the unaudited pro forma consolidated statement of financial position, the balances denominated in Canadian Dollars (‘‘C$’’) have been translated into Renminbi (‘‘RMB’’) at C$1=RMB5.1762, the exchange rate prevailing as at March 31, 2017. For the purpose of the unaudited pro forma consolidated statement of comprehensive income and unaudited pro forma consolidated statement of cash flows, the amounts denominated in C$ have been translated into RMB at C$1=RMB5.0287, the average exchange rate prevailing for the year ended December 31, 2016.
Upon completion of the Transaction, the identifiable assets and liabilities of the Target Group will be accounted for in the consolidated financial statements of the Enlarged Group at their fair values as required by the acquisition method of accounting as set out in the International Financial Reporting Standard 3 (revised) ‘‘Business Combinations’’ (‘‘IFRS 3’’).

The adjustments represent (i) the recognition of an increase in fair value in property, plant and equipment of approximately RMB19.7 million, which is determined based on the fair values of the assets and liabilities of the Target Group as at March 31, 2017 as estimated by an independent professional valuer; and, (ii) the corresponding estimated deferred income tax liabilities of approximately RMB5.1 million.

The fair value of the identifiable assets and liabilities of the Target Group at the date of completion may be substantially different from the estimated fair value used in the preparation of this Unaudited Pro Forma Financial Information. Accordingly, the actual amount of goodwill may be different from the amount (note 4 below) as adopted in this Unaudited Pro Forma Financial Information.

These adjustments represent recognition of the consideration paid/payable, accrual of estimated transaction costs and elimination of the share capital and pre-acquisition reserves of in the Target Group, other terms as stipulated in the Partnership Interest Purchase and Sale Agreement (‘‘PSA’’) dated May 31, 2017.

The adjustment to intangible assets represents the recognition of goodwill of RMB8.0 million arising from the Transaction. The following table summarises the consideration to be paid for the Transaction, the fair value of net assets acquired and the goodwill recognised.

note Total consideration (i) Fair value of the identifiable net assets of the Target Group (ii) Deferred income tax liabilities recognised as a result of the fair value adjustment (iii) Goodwill arising on the acquisition	C$’000 699,360 698,812 991 1,539	RMB’000 3,620,027 3,617,191 5,130
		7,966

– III-11 –

UNAUDITED PRO FORMA FINANCIAL INFORMATION OF THE ENLARGED GROUP

APPENDIX III

(i) The net amount of consideration paid of C$699.4 million (equivalent to approximately RMB3,620.0 million) is estimated based on the Base Purchase price of C$722.0 million (equivalent to approximately RMB3,737.2 million) after adjustments as stipulated in the PSA. The Group presently intends to satisfy payments for the consideration by internal resources of the Group and other equity/debt financing as arranged by the Board (Note 5).
(ii) The fair value of the identifiable assets and liabilities of the Target Group as at March 31, 2017 is estimated by an independent professional valuer. The details of the fair value of identifiable assets and liabilities of the Target Group are set out as below:

Carrying amount of the net assets of the Target Group (note (a)) Fair value adjustments — Property, plant and equipment (note (b)) Pre-closing adjustment (note (c)) Fair value of the identifiable net assets of the Target Group	C$’000 645,000 3,812 50,000 698,812	RMB’000 3,338,649 19,732 258,810
		3,617,191

(a) The carrying amount of the net assets of the Target Group under the Company’s accounting policies as at March 31, 2017 is extracted from the Accountant’s Report of the Target Group as set out in Appendix II to this circular.
(b) The fair value adjustment relates to property, plant and equipment. The book value of property, plant and equipment as at March 31, 2017 was C$1,234.7 million (equivalent to approximately RMB6,391.2 million) whereas the appraised value was C$1,238.5 million (equivalent to approximately RMB6,410.9 million) resulting in a fair value adjustment of C$3.8 million (equivalent to approximately RMB19.7 million). The fair value of the property, plant and equipment of the Target Group as at March 31, 2017 was estimated by an independent professional valuer, Asia-Pacific Consulting and Appraisal Limited. The fair value of the exploration and evaluation assets (the ‘‘E&E’’) is based on the comparable transactions under the market approach, while the fair value of buildings and equipment is based on the cost of replacement under the cost approach. The fair value of other property, plant and equipment is estimated using the income approach.
(c) In accordance with the PSA, C$50.0 million (equivalent to approximately RMB258.8 million) promissory notes issued in favour of the Vendors will be converted as capital of the Target Group prior to the closing of the Transaction.
(iii) Deferred income tax liabilities of approximately RMB5.1 million have been recognised for the temporary differences arising from the fair value adjustment.

The Directors have assessed whether there is any indication of impairment in respect of goodwill with reference to International Accounting Standard 36 ‘‘Impairment of Assets’’. The Directors are of the view that there are no significant changes with an adverse effect on the Target Group that will take place in the near future. The Directors therefore consider that there is no indication of impairment in the value of goodwill for the purpose of this unaudited pro forma financial information.

The Company will adopt consistent accounting policies and principal assumptions and valuation method (as used in the Unaudited Pro Forma Financial Information) to assess the impairment of the Enlarged Group’s goodwill in the future, and communicate such basis with its current auditor.

– III-12 –

UNAUDITED PRO FORMA FINANCIAL INFORMATION OF THE ENLARGED GROUP

APPENDIX III

The adjustment to other reserves represents the elimination of other reserves of the Target Group from the fair value adjustments of approximately RMB19.7 million net off against the corresponding estimated deferred income tax liabilities of approximately RMB5.1 million. The share capital of the Target is adjusted accordingly and eliminated against the Group’s investment in the Target Group.

The Transaction is assumed to be financed by the cash proceeds from: (1) the issuance of Convertible Preferred Shares (the ‘‘CPS’’) of RMB1,055.9 million; (2) net cash proceeds of a Senior Secured Revolving Credit Facility to be provided by a syndicate banks of RMB977.2 million; (3) net cash proceeds of other facilities of RMB2,364.2 million. Upon completion of the Transaction, all aforesaid cash proceeds will be obtained.
These adjustments represent estimated costs directly attributable to the Transaction, primarily professional services fees and other related expenses, amounting to US$12.2 million (equivalent to approximately RMB84.1 million), charged to the consolidated statement of comprehensive income.

A foreign exchange gain of RMB390.8 million, arising from the translation of the financial statements of the Target Group in its functional currency of C$ to the Group’s presentation currency of RMB, is recognised in other comprehensive income for the year ended December 31, 2016.

The adjustments will not have any continuing effect on the consolidated statement of comprehensive income of the Enlarged Group.

For the purpose of the unaudited pro forma consolidated statement of comprehensive income, the transaction is assumed to have been completed on January 1, 2016. These adjustments represent the additional amortization arising from the recognition of intangible assets for the year ended December 31, 2016 that is computed based on the unit of production method using proved developed producing reserves and a corresponding deferred income tax impact of the additional amortization.

This adjustment is expected to have a continuing effect on the consolidated statement of comprehensive income of the Enlarged Group.

For the purpose of the unaudited pro forma consolidated statement of comprehensive income and unaudited pro forma consolidated statement of cash flows, the financing of the Transaction is assumed to have been raised on January 1, 2016.

These adjustments represent the additional costs arising from the financing of the Transaction.

Pursuant to the terms of the Subscription Agreement, the Group will issue 204 million Convertible Preferred Shares at a price of C$1.00 per share for aggregate proceeds of C$204.0 million (equivalent to approximately RMB1,055.9 million) to the subscribers. For the purpose of the Unaudited Pro Forma Financial Information, the Directors determined the fair value of the CPS to be C$224.7 million (equivalent to approximately RMB1,163.2 million), after making reference to the valuation report prepared by an independent professional valuer. The difference between the subscription proceeds and the fair value calculated by valuation techniques upon completion of C$20.7 million (equivalent to approximately RMB107.3 million) would be amortized on a straight line basis over the 4-year life of the Convertible Preferred Shares as estimated by the management. Annual amortization of C$5.2 million (equivalent to approximately RMB26.0 million) is charged to other gains/(losses), net.

In accordance with International Accounting standard 39 ‘‘Financial Instruments: Recognition and Measurement’’ (‘‘IAS 39’’), the fair value changes in financial assets measured at fair value through profit or loss should be reflected in the income statement. For the purpose of the Unaudited Pro Forma Financial Information, it is assumed that there is no change in the fair value of the Convertible Preferred Shares during the year ended December 31, 2016. Annual fixed preferential dividends on the Convertible Preferred Shares are assumed to be C$16.3 million (equivalent to approximately RMB82.1 million), representing C$0.08 per share per annum, are charged to other gains/(losses), net and are assumed to be paid on December 31, 2016.

– III-13 –

UNAUDITED PRO FORMA FINANCIAL INFORMATION OF THE ENLARGED GROUP

APPENDIX III

The annual interests from the non-current Senior Secured Revolving Credit Facility and other facilities accrued on the financing are assumed to be paid on December 31, 2016. Annual interest expenses of RMB329.8 million, considering the impact of transaction costs, calculated with effective interest rate are charged to finance costs, and corresponding interest payments for the year are approximately RMB310.0 million.

This adjustment is expected to have a continuing effect on the consolidated statement of comprehensive income of the Enlarged Group.

Apart from the Transaction, no other adjustments have been made to the Unaudited Pro Forma Financial Information of the Enlarged Group to reflect any trading results or other transactions entered into by the Group subsequent to June 30, 2017, or the Target Group subsequent to March 31, 2017.

– III-14 –

FURTHER INFORMATION ON THE TARGET GROUP

APPENDIX IV

I MANAGEMENT DISCUSSION AND ANALYSIS OF THE TARGET GROUP

The selected historical consolidated financial data of the Target Group set forth below has been derived from the historical financial information for the years ended December 31, 2014, 2015 and 2016, and for the three months ended March 31, 2017 and 2016 (unaudited) as set out in the Accountant’s Report included as appendix II to this circular. Results for the interim periods should not be considered indicative of results for any other periods or for the full fiscal year. All data should be read in conjunction with the consolidated financial information and associated notes included in appendix II.

The financial information contained herein has been prepared in accordance with International Financial Reporting Standards (‘‘IFRS’’) and sometimes referred to in this MD&A as Generally Accepted Accounting Principles as issued by the International Accounting Standards Board (‘‘IASB’’). All dollar amounts are expressed in Canadian currency, unless otherwise noted.

Forward-Looking Information and Statements

This information below contains forward-looking statements. The use of any of the words ‘‘anticipate’’, ‘‘continue’’, ‘‘estimate’’, ‘‘expect’’, ‘‘may’’, ‘‘will’’, ‘‘project’’, ‘‘should’’, ‘‘believe’’ and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements.

Although the Target Group believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because the Target Group can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g. operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), commodity price and exchange rate fluctuations and constraint in the availability of services, adverse weather or break-up conditions and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects. Certain of these risks are set out in more detail under the heading ‘Risk Factors’ below. The forward-looking statements are made as of the date hereof and the Target Group undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

– IV-1 –

FURTHER INFORMATION ON THE TARGET GROUP

APPENDIX IV

Financial & Operating Highlights

The following table provides a recap of the Target Group’s key operational metrics and product prices:

				Three months period	Three months period
	Year ended December		31,	ended March 31,
	2014	2015	2016	2016	2017
Average Daily Production
(boe/d)	48,110	64,864	56,070	58,263	55,258
Average Daily Oil Production
(bbls/day)	3,702	5,380	4,135	4,211	4,175
Average Daily Gas
Production (Mcf/day)	256,703	345,168	302,136	313,835	297,342
Total wells drilled
Gross	21	5	4	—	8
Net	17	4	1	—	8

(1) For reference purpose only, barrels of oil equivalent is calculated using the conversion factor of 6 Mcf of natural gas being equivalent to one barrel of oil.

The following table is the summary of the expenditures incurred in our exploration, development and production activities:

				Three months period	Three months period
	Year ended	December	31,	ended March 31,
(C$’000)	2014	2015	2016	2016	2017
Cash capital expenditures	154,178	112,345	48,246	7,406	22,216
Cash (paid)/received for
acquisitions and disposals	(42,500)	13,040	11,716	3,912	150
Direct operating expenditures	170,923	280,446	133,446	38,641	40,821

Review of Operations

Natural Gas

During the three months ended March 31, 2017, gas production decreased to 297,342 mcf/d, 5.3% lower as compared to the same period in 2016. During the three months ended March 31, 2017 the realized natural gas price averaged C$2.99/mcf, representing an increase of 43.8% period over period, compared to C$2.08/mcf for the same period in 2016. The increased in realized prices is consistent with a 34.5% increase in AECO 7A benchmark during the period.

– IV-2 –

FURTHER INFORMATION ON THE TARGET GROUP

APPENDIX IV

During FY2016, gas production decreased to 302,136 mcf/d, 12.5% lower as compared to FY2015. The decrease in production is due to properties being shut in due to economics, severe cold weather impacting North, South and Edson volumes, as well as unplanned TransCanada Pipeline (‘‘TCPL’’) restrictions in Carrot Creek. In line with the decline in North American natural gas prices, the realized natural gas price averaged C$2.12/mcf for FY2016, representing a decrease of 19.1% year over year, compared to C$2.62/mcf for FY2015. The decrease in realized prices is consistent with a 24.5% decrease in AECO 7A benchmark year over year.

During FY2015, gas production increased to 345,168 mcf/d, 34.5% higher as compared to FY2014. The increase is largely due to significant acquisitions that occurred in 2014 and contributed a full year of production in 2015 compared to only part of fiscal 2014, as well as increased production from the 2014 drilling program. During the year the realized natural gas price averaged C$2.62/mcf, representing a decrease of 38.6% year over year, compared to C$4.27/mcf for FY2014. The decrease in realized prices is consistent with a 37.6% decrease in AECO 7A benchmark year over year.

Oil

During the three months ended March 31, 2017, oil production decreased to 4,175 bbl/d, 0.9% lower as compared to the same period in 2016. During the three months ended March 31, 2017 the realized oil price averaged C$60.10/bbl, representing an increase of 59.2% period over period, compared to C$37.75/bbl for the same period in 2016. The increased in realized prices is consistent with a 49.8% increase in WTI crude oil benchmark during the period.

During FY2016, oil production decreased to 4,135 bbl/d, 23.2% lower as compared to FY2015. The decrease in production is due to properties being shut in due to economics, severe cold weather impacting North, South and Edson volumes, as well as unplanned TCPL restrictions in Carrot Creek. The realized oil price averaged C$49.64/bbl for FY2016, representing a decrease of 4.5% year over year, compared to C$51.98/bbl for FY2015. The decrease in realized prices is consistent with a 7.9% decrease in WTI crude oil benchmark year over year.

During FY2015, oil production increased to 5,380 bbl/d, 45.3% higher as compared to FY2014. The increase is largely due to significant acquisitions that occurred in 2014 and contributed a full year of production in 2015 compared to only part of fiscal 2014, as well as increased production from the 2014 drilling program. The realized oil price averaged C$51.98/bbl for FY2015, representing a decrease of 37.5% year over year, compared to C$83.14/bbl for FY2014. The decrease in realized prices is consistent with a 39.4% decrease in WTI crude oil benchmark year over year.

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FURTHER INFORMATION ON THE TARGET GROUP

APPENDIX IV

Capital expenditures

During the three months ended March 31, 2017, capital expenditures increased 200.0% to C$22.2 million from C$7.4 million in the same period in 2016, primarily due to increased drilling activity in Peace River Arch and North cash generating units (‘‘CGU’s’’).

During FY2016, capital expenditures decreased 57.1% to C$48.2 million from C$112.3 million in FY2015, primarily due to lower capital activity in the year in response to the continued low commodity price environment.

During FY2015, capital expenditures decreased 27.2% to C$112.3 million, from C$154.2 million in FY2014, primarily due to the low commodity price environment and continued volatility of prices which created cash constraints and decreased economic development opportunities.

Acquisitions and disposals

During the three months ended March 31, 2017, the Target Group disposed of immaterial exploration and evaluation (‘‘E&E’’) properties for cash proceeds of C$0.2 million. During the three months ended March 31, 2016, the Target Group disposed of certain oil & natural gas properties with a net book value of C$2.0 million and associated decommissioning obligations of C$1.2 million for cash proceeds of C$3.9 million. A gain of C$3.1 million was recognized on the dispositions closing.

During FY2016, the Target Group disposed of certain oil & natural gas properties with a net book value of property, plant and equipment (‘‘PP&E’’) and E&E of C$2.4 million and associated decommissioning obligations of C$1.4 million for cash proceeds of C$11.7 million. A total gain of C$10.7 million was recognized on the closed dispositions.

During FY2016 the Partnership finalized the April 15, 2013 acquisition of a partnership from Suncor Energy Inc. and recognized a gain related to post-closing purchase price adjustments of C$13.3 million in net loss. As the final purchase price adjustments have been recorded directly in net loss, there were no fair value adjustments made to the allocation of the purchase price.

On August 19, 2015, the Target Group signed a purchase & sale agreement for the disposition of working interests in certain oil and natural gas properties for net proceeds of C$10.7 million. The assets had a net carrying value including PP&E, E&E, prepaid expenses and decommissioning liability of C$0.7 million resulting in a gain on disposition of C$10.0 million. The Target Group disposed of other oil and natural gas properties in FY2015 for cash proceeds of C$2.3 million, with a net carrying value including PP&E, E&E and decommissioning liability of C$1.3 resulting in a gain on dispositions of C$3.6 million.

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FURTHER INFORMATION ON THE TARGET GROUP

APPENDIX IV

On May 13, 2014, the Partnership signed a purchase & sale agreement with Shell Canada Energy (‘‘Shell’’) to acquire Shell’s 50% working interest in Panther River assets of which the Partnership previously owned a working interest, along with Shell’s working interest in adjacent Burnt Timber and Hunter Valley assets. In addition, Direct Energy Marketing Ltd. (‘‘DEML’’) transferred its working interest ownership in the Shell Burnt Timber gas processing facilities to the Partnership and the Partnership relinquished ownership in the Shell Burnt Timber gas processing facilities along with Waterton mineral land interests to Shell. The acquisition was completed on June 27, 2014. The transaction was accounted for as a business combination under IFRS 3. A net gain on the acquisition of C$12.6 million was recorded which included the acquisition of PP&E assets with a net carrying value of C$80.0 million and associated decommissioning liability of C$24.9 million, for net cash proceeds of C$42.5 million.

On October 1, 2014, the Target Group acquired the remaining wholly owned Canadian natural gas assets of DEML and Direct Energy Resources Partnership (‘‘DERP’’). The transaction was executed through a cash contribution of C$215.0 million to the Target Group and an estimated capital contribution of C$537.0 million, subject to post-closing adjustments, comprising of natural gas assets. The carrying value of the net assets included C$104.7 million of E&E, C$971.9 million of PP&E assets and associated decommissioning liability of C$290.5 million. The difference between the consideration of C$537.0 million and the carrying value of acquired assets was recognized as common control transaction reserve in Partners’ equity.

Direct operating

During the three months ended March 31, 2017, operating expense increased to C$40.8 million, or C$8.03/boe, from C$38.6 million, or C$7.21/boe, for the three months ended March 31, 2016. The increase is primarily due to a C$2.2 million decrease in processing income driven by lower third party volumes flowing through operated facilities.

During FY2016, operating expense decreased to C$133.4 million, or C$6.52/boe, from C$280.4 million or C$11.85/boe, for FY2015. The decrease was primarily driven by reductions in headcount and resulted in savings of C$29.9 million, processing fees savings of C$30.0 million due to rerouting productions volumes through operated plants and renegotiating processing contracts, a reduction in repairs, maintenance and optimizations work of C$28.5 million and other costs savings of C$58.6 million due to a focus by the business to reduce costs in the low commodity price environment.

During FY2015, operating expense increased to C$280.4 million, or C$11.85/boe, from C$170.9 million or C$9.73/boe, for FY2014. The increase is primarily due to the acquisition of Canadian natural gas assets of DEML and DERP which increased operating expenses of the Target Group for the full year of 2015 compared to three months of comparable operating expenses in 2014.

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FURTHER INFORMATION ON THE TARGET GROUP

APPENDIX IV

Review of Historical Results

Three months ended March 31, 2017 compared to the three months ended March 31, 2016

Oil and natural gas sales

The Target Group’s revenue is generated from sales of oil and natural gas products. During the three months ended March 31, 2017, the Target Group realized revenue from oil & natural gas sales of C$113.7 million compared to C$80.5 million during the three months ended March 31, 2016. The increase is primarily due to a 49.0% increase in realized price period over period, consistent with increases in oil and natural gas benchmarks.

Royalties

During the three months ended March 31, 2017, royalties increased to C$10.4 million, or 9.2% of revenue, from C$4.0 million, or 4.9% of revenue, for the three months ended March 31, 2016. The increase in royalties and rate is primarily due to the significant increase in realized prices period over period.

Transportation

During the three months ended March 31, 2017, transportation expense increased to C$8.2 million, or C$1.60/boe, from C$5.1 million, or C$0.95/boe, for the three months ended March 31, 2016. The increase is primarily due to an increase in pipeline tolls to bring production volumes to market and re-routing additional volume from British Columbia to Alberta to capture better commodity pricing.

General and administrative

During the three months ended March 31, 2017, general & administrative expense decreased to C$8.6 million, or C$1.69/boe, from C$13.5 million, or C$2.51/boe for the three months ended March 31, 2016. The decrease is primarily due to a reduction in headcount costs of C$4.2 million and a reduction of other general and administrative costs of C$0.7 million.

Depletion, depreciation and amortization

During the three months ended March 31, 2017, depletion, depreciation and amortization decreased to C$29.8 million, or C$5.86/boe, from C$33.2 million, or C$6.19/boe for the three months ended March 31, 2016.

Exploration & evaluation lease expiries

During the three months ended March 31, 2017, E&E lease expiries decreased 12.9% to C$2.7 million, from C$3.1 million, for the three months ended March 31, 2016.

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FURTHER INFORMATION ON THE TARGET GROUP

APPENDIX IV

Impairment

At March 31, 2017, the Target Group calculated the recoverable amount as the fair value less costs of disposal based on the market price observed in the subsequent transaction described in note 22 of the Accountant’s Report (included as appendix II in this circular). As a result of the test, the Target Group determined that the recoverable amount was lower than the remaining carrying value of the assets, and as such, an impairment of C$135.0 million was recorded.

Finance expense

During the three months ended March 31, 2017, finance expense decreased 3.2% to C$6.0 million, from C$6.2 million, for the three months ended March 31, 2016. Finance expense comprises accretion of the discount on decommissioning obligations and is discounted using a credit-adjusted rate of 6.75%.

Net loss

The Target Group’s net loss increased by C$107.7 million, or 541.2%, from a loss of C$19.9 million for the three months ended March 31, 2016, to C$127.6 million for the three months ended March 31, 2017. This was primarily due to the cumulative effects of the above factors.

Year ended December 31, 2016 compared to the year ended December 31, 2015

Oil and natural gas sales

The Target Group’s revenue is generated from sales of oil and natural gas products. During the year ended December 31, 2016, the Target Group realized revenue from oil & natural gas sales of C$334.2 million compared to C$478.3 million during the year ended December 31, 2015. The decrease is due to a combination of a drop in production by 13.6% during the year and a 19.2% decrease in realized oil and natural gas prices.

Royalties

During FY2016, royalties decreased to C$19.5 million, or 5.8% of revenue, from C$23.3 million, or 4.9% of revenue, for FY2015. The decrease in royalties and rate is due to the decline in production volumes and commodity prices during the year.

Transportation

During FY2016, transportation expense increased to C$28.0 million, or C$1.37/boe, from C$24.3 million or C$1.03/boe, for FY2015. The increase is primarily due to an increase in pipeline tolls to bring production volumes to market, offset by a decrease in volumes produced during 2016.

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FURTHER INFORMATION ON THE TARGET GROUP

APPENDIX IV

General and administrative

During FY2016, general & administrative expense decreased to C$39.3 million, or C$1.92/boe, from C$54.4 million, or C$2.30/boe for FY2015. The decrease is due to a reduction in headcount costs of C$21.4 million and in discretionary and non-discretionary costs of C$3.7 million, offset by decreases of C$6.4 million in overhead recoveries resulting from reduced capital activities and a reduction of C$3.6 million in capitalized labour due to lower headcount and other charges.

Depletion, depreciation and amortization

During FY2016, depletion, depreciation and amortization decreased to C$125.5 million, or C$6.13/boe, from C$228.1 million, or C$9.64/boe for FY2016. The decrease is largely due to the impairment recorded in FY2015 resulting in a lower depletable base in FY2016.

Exploration & evaluation lease expiries

During FY2016, E&E lease expiries increased 222.2% to C$11.6 million, from C$3.6 million, for FY2015. The increase is primarily due to lower lease expires in 2014.

Impairment

As at December 31, 2016, the Target Group performed an impairment test on its PP&E and E&E assets as a result of declining forward commodity prices for natural gas and crude oil prices. The recoverable amounts were calculated as the fair value less costs to sell using a discounted cash flow model and as a result of the test the Target Group determined that the recoverable amount exceeded the remaining carrying value of the assets, and as such, no impairment was recorded.

During FY2015, as a result of the significantly lower commodity price environment, management performed an impairment test on its PP&E and E&E assets which resulted in the carrying value exceeding the recoverable amount and a C$558.7 million impairment charge was recorded, impacting the Foothills, Peace River Arch, North and South CGU’s. Included within that value is C$112.3 million of goodwill impairment.

Finance expense

During FY2016, finance expense decreased 9.2% to C$24.7 million, from C$27.2 million in FY2015. Finance expense comprises accretion of the discount on decommissioning obligations and is discounted used a credit-adjusted rate of 6.75%. The decrease year over year is due to a downward revision of estimate to the asset retirement obligation relating to new cost estimates and timing of abandonment cash flows.

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APPENDIX IV

Net loss

The Target Group’s net loss improved by C$682.4 million, or 96.7%, from a loss of C$705.6 million for the year ended December 31, 2015, to a loss of C$23.2 million for the year ended December 31, 2016. This was primarily due to the cumulative effects of the above factors.

Year ended December 31, 2015 compared to the year ended December 31, 2014

Oil and natural gas sales

The Target Group’s revenue is generated from sales of oil and natural gas products. During the year ended December 31, 2015, the Target Group realized revenue from oil & natural gas sales of C$478.3 million compared to C$569.4 million during the year ended December 31, 2014. The decrease is due to a 37.7% decrease in realized oil and natural gas prices, offset by a 34.8% increase in production, year over year.

Royalties

During FY2015, royalties decreased to C$23.3 million, or 4.9% of revenue, from C$80.4 million, or 14.1% of revenue, for FY2014. The decrease in royalties is primarily due to the decrease in commodity prices compared to 2014.

Transportation

During FY2015, transportation expense increased to C$24.3 million, or C$1.03/boe, from C$16.8 million or C$0.95/boe, for FY2014. The increase was primarily driven by the additional volumes added as a result of the acquisition of Canadian natural gas assets of DEML and DERP by the Target Group in the fourth quarter of 2014.

General and administrative

During FY2015, general & administrative expense increased to C$54.4 million, or C$2.30/boe, from C$39.2 million, or C$2.23/boe for FY2014. The increase in G&A is primarily due to an increase of C$22.5 million in headcount costs as a result of the acquisition of Canadian natural gas assets of DEML and DERP by the Target Group in the fourth quarter of 2014.

Depletion, depreciation and amortization

During FY2015, depletion, depreciation and amortization increased to C$228.1 million, or C$9.64/boe, from C$173.3 million, or C$9.87/boe for FY2014. The increase in total depreciation, depletion and amortization is primarily due to an increase in the depletable base as a result of the acquisition of Canadian natural gas assets of DEML and DERP by the Target Group in the fourth quarter of 2014.

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FURTHER INFORMATION ON THE TARGET GROUP

APPENDIX IV

Exploration & evaluation lease expiries

During FY2015, E&E lease expiries increased to C$3.6 million, from C$0.3 million, for FY2014 as a result of the acquisition of Canadian natural gas assets of DEML and DERP by the Target Group in the fourth quarter of 2014.

Impairment

During Fy2015, as a result of the significantly lower commodity price environment, management performed an impairment test on its PP&E and E&E assets which resulted in the carrying value exceeding the recoverable amount and a C$558.7 million impairment charge was recorded. Included within that value is C$112.3 million of goodwill impairment.

During FY2014, as a result of the lower commodity price environment, management performed an impairment test on its PP&E and E&E assets which resulted in the carrying value exceeding the recoverable amount and a C$80.1 million impairment charge was recorded on the Foothills and South CGU’s.

Finance expense

During FY2015, finance expense increased 6.3% to C$27.2 million, from C$25.6 million in FY2014. Finance expense comprises accretion of the discount on decommissioning obligations and is discounted used a credit-adjusted rate of 6.75%.

Net loss

The Target Group recorded a net loss of C$705.6 million in FY2015 compared to net loss of C$4.7 million in FY2014. This was due to the cumulative effects of the above factors.

EBITDA and Adjusted EBITDA

The Target Group provides a reconciliation of EBITDA and adjusted EBITDA to profit for each period, our most directly comparable financial performance calculated and presented in accordance with IFRS. EBITDA refers to earnings before finance expenses and depreciation, depletion and amortization. Adjusted EBITDA refers to EBITDA adjusted to exclude non-cash and non-recurring items such as, assets impairment loss, bad debt provision, exploration and evaluation lease expiries, gain on acquisitions or dispositions and any other non-cash or non-recurring income/expenses.

The Target Group’s adjusted EBITDA reflects the recurring cash flow earnings from its core operations.

The Target Group has included EBITDA and adjusted EBITDA as they are a financial measure commonly used in the oil and gas industry. The Target Group believes that EBITDA and adjusted EBITDA are used as supplemental financial measures by its

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FURTHER INFORMATION ON THE TARGET GROUP

APPENDIX IV

management and by investors, research analysts, bankers and others, to assess operating performance, cash flow and return on capital as compared to those of other companies in the industry, and the ability to take on financing. However, EBITDA and adjusted EBITDA should not be considered in isolation or construed as alternatives to profit from operations or any other measure of performance or as an indicator of operating performance or profitability. EBITDA and adjusted EBITDA do not consider any functional or legal requirements of the business that may require us to conserve and allocate funds for any purposes.

The following table presents a reconciliation of EBITDA and adjusted EBITDA from net loss:

(C$’000) Net loss Finance expense Depletion, depreciation and amortization EBITDA EBITDA per boe Impairment Exploration & evaluation lease expiries Gain on acquisitions & disposition Post-closing purchase price adjustments Bad debt expense Adjusted EBITDA Adjusted EBITDA per boe	Year ended December 31, 2014 2015 2016 (4,672) (705,589) (23,167) 25,556 27,198 24,699 173,318 228,121 125,459 194,202 (450,270) 126,991 11.1 (19.0) 6.2 80,134 558,726 — 349 3,597 11,592 (12,600) (13,624) (10,747) — — (13,346) — — 1,180 262,085 98,429 115,670 14.9 4.2 5.7	Three months period ended March 31, 2016 2017 (19,948) (127,609) 6,175 6,005 33,189 29,801 19,416 (91,803) 3.6 (18.1) — 135,045 3,099 2,665 (3,079) (48) — (194) 25 424 19,461 46,089 3.6 9.1

The higher EBITDA in FY2014 and the three months ended March 31, 2017 is largely due to oil & natural gas commodity prices. AECO 7A pricing averaged C$4.43/ mcf and C$2.77/mcf in these periods compared to an average in FY2015, FY2016 and the three months ended March 31, 2016 of C$2.77/mcf, C$2.09/mcf and C$2.06/mcf, respectively. The Target Group also achieved cost efficiencies in both direct operating costs and general and administrative expenses that contributed to a higher EBITDA per boe from 2015 onwards.

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FURTHER INFORMATION ON THE TARGET GROUP

APPENDIX IV

Liquidity and Capital Resources

Overview

The Target Group operates in an industry which requires significant capital expenditures in the development phase that are funded primarily from cash generated from operating activities. The Target Group closely monitors its capital structure with a goal of maintaining a strong financial position in order to fund current operations and any future growth.

As at December 31, 2014, 2015, 2016 and at March 31, 2017, the Target Group did not have any loan/borrowing from banks or other material contingent liabilities.

The funding and treasury policies are established, with sufficient availability of funds at all times to meet all contractual commitments and fund its capital program.

The Target Group’s transactions were primarily denominated in Canadian Dollars.

Gearing Ratio

The gearing ratio, being amounts due to shareholders divided by total assets, was as follows:

(C$’000) Due from/(to) related parties Partnership distribution payable Note payable Total borrowing Total assets Gearing ratio	As 2014 (12,226) 15,000 50,000 52,774 2,364,097 2.2%	at December 31, 2015 2016 7,598 746 15,000 15,000 69,000 50,000 91,598 65,746 1,606,573 1,457,979 5.7% 4.5%	As at March 31, 2017 2,402 — 50,000
			52,402
			1,354,356
			3.9%

Cash generated from operating activities

During the three months ended March 31, 2017, cash flow from operations was C$56.7 million, from C$35.6 million for the three months ended March 31, 2016. The increase was primarily driven by an increase in commodity prices and a decrease in G&A cash costs due to lower headcount costs. These increases were partially offset by increased royalties, operating expenses and transportation costs.

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FURTHER INFORMATION ON THE TARGET GROUP

APPENDIX IV

During the year ended December 31, 2016, cash flow from operations was C$95.6 million, from C$113.1 million for the year ended December 31, 2015. The decrease was primarily driven by a 19.2% decrease in realized commodity prices as well as a reduction in production volumes, an increase in transportation costs to bring volumes to market and a decrease in working capital primarily due to the timing of the payment of accounts payable. These decreases were primarily offset by cash savings for royalties due to lower commodity prices and volumes and lower operating costs and administrative costs driven by reduced headcount costs.

During the year ended December 31, 2015, cash flow from operations was C$113.1 million, from C$217.3 million for the year ended December 31, 2014. The decrease was primarily driven by a 37.7% decrease in realized commodity prices, as well as an increase in cash costs due to the acquisition of the Canadian natural gas assets of DEML and DERP by the Target Group in the fourth quarter of 2014.

Cash used in investing activities

During the three months ended March 31, 2017, cash flow used in investing activities was C$16.4 million, from C$6.5 million for the three months ended March 31, 2016. The increase in cash used was primarily due to an increase in capital spending for drilling activities in the Peace River Arch and North CGU’s.

During the year ended December 31, 2016, cash flow used in investing activities was C$35.4 million, from C$144.1 million for the year ended December 31, 2015. The decrease in cash used was primarily due to a reduction in capital spending resulting from the decrease in commodity prices which reduced the Target Group’s ability to sustain drilling activities through cash generated by operating activities. In addition to minor dispositions which generated cash proceeds of C$11.7 million compared to C$13.0 million for the year ended December 31, 2015.

During the year ended December 31, 2015, cash flow used in investing activities was C$144.1 million, from C$161.7 million for the year ended December 31, 2014. The decrease in cash used was primarily due to a reduction in capital spending resulting from the decrease in commodity prices which reduced the Target Group’s ability to sustain drilling activities through cash generated by operating activities and a decrease in working capital due to the timing of payment of accounts payable. In addition to minor disposals which generated cash proceeds of C$13.0 million in 2015 compared to cash spent as part of the acquisition of the Canadian natural gas assets of DEML and DERP by the Target Group in the fourth quarter of 2014.

Cash used in/generated from financing activities

During the three months ended March 31, 2017, cash flow used in financing activities was C$20.8 million, from C$19.0 million for the three months ended March 31, 2016. Cash flow used in the three months ended March 31, 2017 was primarily driven by a distribution of cash to the Target Group’s partners for C$20.8 million, compared to the C$19.0 million repayment of notes for the three months ended March 31, 2016.

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FURTHER INFORMATION ON THE TARGET GROUP

APPENDIX IV

During the year ended December 31, 2016, cash flow used in financing activities was C$74.0 million, from C$19.0 million cash generated from financing activities for the year ended December 31, 2015. Cash flow used during the year ended December 31, 2016 was primarily driven by a distribution of cash to the Target Group’s partners for C$55.0 million and a repayment of the C$19.0 million repayment of notes issued in 2015.

During the year ended December 31, 2015, cash flow generated from financing activities was C$19.0 million, from C$82.0 million cash used in financing activities for the year ended December 31, 2014. Cash flow generated during the year ended December 31, 2015 was due to the issuance of C$19.0 million of notes, compared to the cash used in the year ended December 31, 2014 of C$82.0 million primarily due to a distribution of cash to the Target Group’s partners for C$82.2 million.

Commitments

The Target Group is committed to future payments under the following agreements:

Payments due by period/year (C$’000) As at March 31, 2017 Operating leases Capital commitments Firm transportation commitments As at December 31, 2016 Operating leases Capital commitments Firm transportation commitments As at December 31, 2015 Operating leases Capital commitments Firm transportation commitments As at December 31, 2014 Operating leases Capital commitments Firm transportation commitments	1 year 2,825 40,493 19,759 63,077 3,191 13,418 26,139 42,748 3,492 15,079 21,744 40,315 7,539 12,138 24,362 44,039	2–3 year 2,538 — 21,342 23,880 3,079 — 34,251 37,330 90 — 27,503 27,593 1,637 — 33,890 35,527	4–5 years — — 15,748 15,748 293 — 17,507 17,800 — — 11,960 11,960 144 — 6,249 6,393	45 years — — 20,095 20,095 — — 6,063 6,063 — — 5,098 5,098 — — 5,938 5,938	Total 5,363 40,493 76,944
					122,800
					6,563 13,418 83,960
					103,941
					3,582 15,079 66,305
					84,966
					9,320 12,138 70,439
					91,897

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FURTHER INFORMATION ON THE TARGET GROUP

APPENDIX IV

Pledge of assets

As at December 31, 2014, 2015 and 2016 and March 31, 2017, the Target Group did not have any pledge of assets.

Employees

As at December 31, 2014, 2015 and 2016 and March 31, 2017, the Target Group had 632, 509, 466 and 460 employees, respectively. Salaries of employees were maintained at a competitive level and the Target Group continued to review remuneration packages of employees with reference to general market condition and individual performance. Remuneration packages primarily comprised salaries, bonuses, employment benefits and share-based awards.

Future Plans

The Target Group is continuing to refine its post completion business plan for the remainder of 2017 and beyond. The Target Group plans to take a measured and prudent approach in understanding the assets and funding capital expenditures for development, maintenance and optimization through cash flows generated by existing operations.

In 2017, the business plans to develop core areas and estimates it will drill 8.7 net wells, complete its capital maintenance program on key assets and optimize current operations. In 2018, the business will continue to develop core areas and estimates it will drill 8.0 net wells, complete its capital maintenance program on key assets, including operated plant turnarounds and asset integrity spending and optimizing current operations.

II REGULATORY OVERVIEW

Pricing & Marketing

Oil

In Canada, producers of oil are entitled to negotiate sales contracts directly with oil purchasers, which results in the market determining the price of oil. Worldwide supply and demand factors primarily determine oil prices; however, regional market and transportation issues also influence prices. The specific price depends in part on oil quality, prices of competing fuels, distance to market, availability of transportation, value of refined products, the supply/demand balance and contractual terms of sale. Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such export has been obtained from the National Energy Board of Canada (the ‘‘NEB’’). Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the NEB. The NEB underwent a consultation process to update the regulations governing the issuance of export licences. The updating process was necessary to meet the criteria set out in the federal Jobs, Growth and Long-term Prosperity Act (Canada) (the ‘‘Prosperity

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FURTHER INFORMATION ON THE TARGET GROUP

APPENDIX IV

Act’’) which received Royal Assent on June 29, 2012. The Regulations Amending the National Energy Board Act Part VI (Oil and Gas) Regulations came into effect on July 31, 2015 and provides the requirements for obtaining long-term licences.

Natural Gas

Canada’s natural gas market has been deregulated since 1985. Supply and demand determine the price of natural gas and price is calculated at the sale point, being the wellhead, the outlet of a gas processing plant, on a gas transmission system, at a storage facility, at the inlet to a utility system or at the point of receipt by the consumer. Accordingly, the price for natural gas is dependent upon such producer’s own arrangements (whether long or short term contracts and the specific point of sale). As natural gas is also traded on trading platforms such as the Natural Gas Exchange, Intercontinental Exchange or the New York Mercantile Exchange in the United States, spot and future prices can also be influenced by supply and demand fundamentals on these platforms. Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts continue to meet certain other criteria prescribed by the NEB and the Government of Canada. Natural gas (other than propane, butane and ethane) exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 m[3] per day) must be made pursuant to an NEB order. Natural gas export contracts of a longer duration or that deal with larger quantities of natural gas requires an exporter to obtain an export licence from the NEB.

The North American Free Trade Agreement

The North American Free Trade Agreement (‘‘NAFTA’’) among the governments of Canada, the United States and Mexico came into force on January 1, 1994. In the context of energy resources, Canada continues to remain free to determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to the total supply of goods of the party maintaining the restriction as compared to the proportion prevailing in the most recent 36 month period; (ii) impose an export price higher than the domestic price (subject to an exception with respect to certain measures which only restrict the volume of exports); and (iii) disrupt normal channels of supply.

All three signatory countries are prohibited from imposing a minimum or maximum export price requirement in any circumstance where any other form of quantitative restriction is prohibited. The signatory countries are also prohibited from imposing a minimum or maximum import price requirement except as permitted in enforcement of countervailing and anti-dumping orders and undertakings. NAFTA requires energy regulators to ensure the orderly and equitable implementation of any regulatory changes and to ensure that the application of those changes will cause minimal disruption to contractual arrangements and avoid undue interference with pricing, marketing and distribution arrangements, all of which are important for Canadian oil and natural gas exports. NAFTA contemplates the reduction of Mexican restrictive trade practices in the

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energy sector and prohibits discriminatory border restrictions and export taxes. The new administration in the United States has indicated an intention to seek renegotiation of NAFTA, the impact of which on the oil and gas industry is uncertain.

Royalties and Incentives

General

In addition to federal regulation, each province has legislation and regulations that govern royalties, production rates and other matters. The royalty regime in a given province is a significant factor in the profitability of crude oil, natural gas liquids, sulphur and natural gas production. Royalties payable on production from lands where the Crown does not hold the mineral rights are determined by negotiation between the mineral freehold owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties. Royalties from production on Crown lands are determined by governmental regulation and are generally calculated as a percentage of the value of gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery and the type or quality of the petroleum product produced. Other royalties and royalty-like interests are carved out of the working interest owner’s interest, from time to time, through non-public transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests or net carried interests.

Occasionally the governments of the western Canadian provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays or royalty tax credits and are generally introduced when commodity prices are low to encourage exploration and development activity by improving earnings and cash flow within the industry.

The Canadian federal government has signalled that it will inter alia phase out subsidies for the oil and gas industry, which include only allowing the use of the Canadian Exploration Expenses tax deduction in cases of successful exploration, implementing stringent reviews for pipelines and establishing a pan-Canadian framework for combating climate change. These changes could affect earnings of companies operating in the oil and natural gas industry.

Land Tenure

The respective provincial governments predominantly own the rights to crude oil and natural gas located in the western provinces. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences, and permits for varying terms, and on conditions set forth in provincial legislation including requirements to perform specific work or make payments. Private ownership of oil and natural gas also exists in such provinces and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.

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Each of the provinces of Alberta, British Columbia, and Saskatchewan have implemented legislation providing for the reversion to the Crown of mineral rights to deep, non-productive geological formations at the conclusion of the primary term of a lease or licence. The Government of British Columbia expanded its policy of deep rights reversion for leases issued after March 29, 2007 to provide for the reversion of both shallow and deep formations that cannot be shown to be capable of production at the end of the primary term.

Alberta also has a policy of ‘‘shallow rights reversion’’ which provides for the reversion to the Crown of mineral rights to shallow, non-productive geological formations for all leases and licences issued after January 1, 2009 at the conclusion of the primary term of the lease or licence.

Production and Operation Regulations

The oil and natural gas industry in Canada is highly regulated and subject to significant control by regulators. Regulatory approval is required for, among other things, the drilling of oil and natural gas wells, construction and operation of wells, pipelines and facilities, the storage, injection and disposal of substances and the abandonment and reclamation of wells, pipelines and facilities. In order to conduct oil and gas operations and remain in good standing with the applicable regulator, producers must comply with applicable legislation, regulations, orders, directives and other directions (all of which are subject to governmental oversight, review and revision, from time to time). Compliance with such legislation, regulations, orders, directives or other directions can be costly and a breach of the same may result in fines or other sanctions.

Environmental Regulation

The oil and natural gas industry is currently subject to environmental regulation under a variety of Canadian federal, provincial and municipal laws and regulations, all of which is subject to review and revision from time to time. Such legislation provides for, among other things, restrictions and prohibitions on the spill, release or emission of various substances produced in association with certain oil and gas industry operations, such as sulphur dioxide and nitrous oxide. The regulatory regimes set out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of wells, pipelines and facilities. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licences and authorizations, civil liability and the imposition of material fines and penalties. In addition to these specific, known requirements, future changes to environmental legislation, including anticipated legislation for air pollution and greenhouse gas (‘‘GHG’’) emissions, may impose further requirements on operators and other companies in the oil and natural gas industry.

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Climate Change Regulation

Federal

Climate change regulation at both the federal and provincial level has the potential to significantly affect the regulatory environment of the oil and natural gas industry in Canada. Such regulations, surveyed below, impose certain costs and risks on the industry.

On April 26, 2007, the Government of Canada released ‘‘Turning the Corner: An Action Plan to Reduce Greenhouse Gases and Air Pollution’’ (the ‘‘Action Plan’’) which set forth a plan for regulations to address both GHGs and air pollution. An update to the Action Plan, ‘‘Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions’’ was released on March 10, 2008 (the ‘‘Updated Action Plan’’). The Updated Action Plan outlines emissions intensity-based targets, for application to regulated sectors on a facility-specific basis, sector-wide basis or company-by-company basis. Although the intention was for draft regulations aimed at implementing the Updated Action Plan to become binding on January 1, 2010, the only regulations being implemented are in the transportation and electricity sectors.

As a signatory to the United Nations Framework Convention on Climate Change (the ‘‘UNFCCC’’) and a participant to the Copenhagen Accord (a non-binding agreement created by the UNFCCC), the Government of Canada announced on January 29, 2010 that it will seek a 17% reduction in GHG emissions from 2005 levels by 2020; however, the GHG emission reduction targets are not binding. In May 2015, Canada submitted its Intended Nationally Determined Contribution (‘‘INDC’’) to the UNFCCC. INDCs were communicated prior to the 2015 United Nations Climate Change Conference, held in Paris, France, which led to the Paris Agreement that came into force November 4, 2016 (the ‘‘Paris Agreement’’). Among other items, the Paris Agreement constitutes the actions and targets that individual countries will undertake to help keep global temperatures from rising more than 2° Celsius and to pursue efforts to limit below 1.5° Celsius. The Government of Canada ratified the Paris Agreement on December 12, 2016, and pursuant to the agreement, Canada’s INDC became its Nationally Determined Contributions (‘‘NDC’’). As a result, the Government of Canada replaced its INDC of a 17% reduction target established in the Copenhagen Accord with an NDC of 30% reduction below 2005 levels by 2030.

On June 29, 2016, the North American Climate, Clean Energy and Environment Partnership was announced among Canada, Mexico and the United States, which announcement included an action plan for achieving a competitive, low-carbon and sustainable North American economy. The plan includes setting targets for clean power generation, committing to implement the Paris Agreement, setting out specific commitments to address certain short-lived climate pollutants, and the promotion of clean and efficient transportation.

Additionally, on December 9, 2016, the Government of Canada formally announced the Pan-Canadian Framework on Clean Growth and Climate Change. As a result, the federal government will implement a Canada- wide carbon pricing scheme beginning in

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This may be implemented through either a cap and trade system or a carbon tax regime at the option of each province or territory. The federal government will impose a price on carbon of C$10 per tonne on any province or territory which fails to implement its own system by 2018. This amount will increase by C$10 annually until it reaches C$50 per tonne in 2022 at which time the program will be reviewed.

In general, there is some uncertainty with regard to the impacts of federal or provincial climate change and environmental laws and regulations, as it is currently not possible to predict the extent of future requirements. Any new laws and regulations, or additional requirements to existing laws and regulations, could have a material effect on the Target Group.

III RISK FACTORS

The Directors consider the following risks and other factors to be material in respect of the Target Group for the Shareholders and potential investors of the Target Group. However, the risks listed do not purport to comprise all those risks associated with the Target Group and are not set out in any particular order of priority. Additional risks and uncertainties not currently known to the Directors or that the Directors currently deem to be immaterial may also have an adverse effect on the Target Group’s business.

Risks relating to the Acquisition

The Company may not be able to successfully acquire the Target Group as closing of the Acquisition is subject to the satisfaction or waiver of a number of conditions, including receipt of federal regulatory approvals, approval by the shareholders of the Company, receipt of all permissions and approvals required from the Hong Kong Stock Exchange and other customary closing conditions. While it is not a condition precedent in the Purchase Agreement, the Company will also need to secure third party bank financing as a condition to fund the purchase price for the Target Group.

The Company cannot assure that all of these conditions to closing will be met.

Risk factors relating to the Target Group

Exploration, Development and Production Risks

Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The longterm commercial success of the Target Group depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, the Target Group existing reserves, and the production from them, will decline over time as the Target Group produces from such reserves. A future increase in the Target Group reserves will depend on both the ability of the Target Group to explore and develop its existing properties and its ability to select and acquire suitable producing properties or prospects. There is no assurance that the Target Group will be able continue to find satisfactory properties to acquire or participate in. Moreover,

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management of the Target Group may determine that current markets, terms of acquisition, participation or pricing conditions make potential acquisitions or participation uneconomic. There is also no assurance that the Target Group will discover or acquire further commercial quantities of oil and natural gas.

Future oil and natural gas exploration may involve unprofitable efforts from dry wells, as well as from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, completing (including hydraulic fracturing), operating and other costs. Completion of a well does not ensure a profit on the investment or recovery of drilling, completion and operating costs.

Drilling hazards, environmental damage and various field operating conditions could greatly increase the cost of operations and adversely affect the production from successful wells. Field operating conditions include, but are not limited to, delays in obtaining governmental approvals or consents, shut-ins of wells resulting from extreme weather conditions, insufficient storage or transportation capacity or geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, it is not possible to eliminate production delays and declines from normal field operating conditions, which can negatively affect revenue and cash flow levels to varying degrees.

Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including, but not limited to, fire, explosion, blowouts, oil and gas releases, spills and other environmental hazards. These typical risks and hazards could result in substantial damage to oil and natural gas wells, production facilities, other property, the environment and personal injury. Particularly, the Target Group may explore for and produce sour natural gas in certain areas. An unintentional leak of sour natural gas could result in personal injury, loss of life or damage to property and may necessitate an evacuation of populated areas, all of which could result in liability to the Target Group.

Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing formations. Losses resulting from the occurrence of any of these risks may have a material adverse effect on the Target Group’s business, financial condition, results of operations and prospects.

As is standard industry practice, the Target Group is not fully insured against all risks, nor are all risks insurable. Although the Target Group maintains liability insurance in an amount that it considers consistent with industry practice, liabilities associated with certain risks could exceed policy limits or not be covered. In either event, the Target Group could incur significant costs.

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APPENDIX IV

Weakness in the Oil and Gas Industry

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 Target Group reserves, rendering certain reserves uneconomic. In addition, lower commodity prices have restricted, and may continue to restrict, the Target Group cash flow resulting in a reduced capital expenditure budget. Consequently, the Target Group may not be able to replace its production with additional reserves and both the Target Group’s production and reserves could be reduced on a year over year basis.

Prices, Markets and Marketing

Numerous factors beyond the Target Group’s control do, and will continue to, affect the marketability and price of oil and natural gas acquired, produced, or discovered by the Target Group. The Target Group’s ability to market its oil and natural gas may depend upon its ability to acquire capacity on pipelines that deliver natural gas to commercial markets or contract for the delivery of crude oil by rail. Deliverability uncertainties related to the distance the Target Group’s reserves are from pipelines, railway lines, processing and storage facilities; operational problems affecting pipelines, railway lines and facilities; and government regulation relating to prices, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and many other aspects of the oil and natural gas business may also affect the Target Group.

Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond the control of the Target Group. These factors include economic and political conditions in the United States, Canada, Europe, China and emerging markets, the actions of OPEC, governmental regulation, political stability in the Middle East, Northern Africa and elsewhere, the foreign supply and demand of oil and natural gas, risks of supply disruption, the price of foreign imports and the availability of alternative fuel sources. Prices for oil and natural gas are also subject to the availability of foreign markets and the Target Group’s ability to access such markets. Oil prices are expected to remain volatile as a result of global excess supply due

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to the increased growth of shale oil production in the United States, the decline in global demand for exported crude oil commodities, OPEC’s decisions pertaining to the oil production of OPEC member countries, and non-OPEC member countries’ decisions on production levels, among other factors. A material decline in prices could result in a reduction of the Target Group’s net production revenue. The economics of producing from some wells may change because of lower prices, which could result in reduced production of oil or natural gas and a reduction in the volumes and the value of the Target Group’s reserves. The Target Group might also elect not to produce from certain wells at lower prices.

All these factors could result in a material decrease in the Target Group’s expected net production revenue and a reduction in its oil and natural gas production, development and exploration activities. Any substantial and extended decline in the price of oil and natural gas would have an adverse effect on the Target Group’s carrying value of its reserves, borrowing capacity, revenues, profitability and cash flows from operations and may have a material adverse effect on the Target Group’s business, financial condition, results of operations and prospects.

Oil and natural gas prices are expected to remain volatile for the near future because of market uncertainties over the supply and the demand of these commodities due to the current state of the world economies, OPEC actions, political uncertainties, sanctions imposed on certain oil producing nations by other countries and ongoing credit and liquidity concerns. Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisitions and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for, and project the return on, acquisitions and development and exploitation projects.

Alternatives to and Changing Demand for Petroleum Products

Full conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas and technological advances in fuel economy and energy generation devices could reduce the demand for oil, natural gas and liquid hydrocarbons. The Target Group cannot predict the impact of changing demand for oil and natural gas products, and any major changes may have a material adverse effect on the Target Group’s business, financial condition, results of operations and cash flows.

Reserve Estimates

There are numerous uncertainties inherent in estimating quantities of oil, natural gas and natural gas liquids reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth in this document are estimates only. Generally, estimates of economically recoverable oil and natural gas reserves and the future net cash flows from such estimated reserves are based upon a number of variable factors and assumptions, such as:

. historical production from the properties;

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APPENDIX IV

. production rates;
. ultimate reserve recovery;
. timing and amount of capital expenditures;
. marketability of oil and natural gas;
. royalty rates; and
. the assumed effects of regulation by governmental agencies and future operating costs (all of which may vary materially from actual results).

For those reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times may vary. The Target Group’s actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates and such variations could be material.

The estimation of proved reserves that may be developed and produced in the future is often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Recovery factors and drainage areas are often estimated by experience and analogy to similar producing pools. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history and production practices will result in variations in the estimated reserves. Such variations could be material.

In accordance with applicable securities laws, the Target Group’s independent reserves evaluator has used forecast prices and costs in estimating the reserves and future net cash flows as summarized herein. Actual future net cash flows will be affected by other factors, such as actual production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs.

Actual production and cash flows derived from the Target Group’s oil and natural gas reserves will vary from the estimates contained in the reserve evaluation, and such variations could be material. The reserve evaluation is based in part on the assumed success of activities the Target Group intends to undertake in future years. The reserves and estimated cash flows to be derived therefrom and contained in the reserve evaluation will be reduced to the extent that such activities do not achieve the level of success assumed in the reserve evaluation. The reserve evaluation is effective as of a specific effective date and, except as may be specifically stated, has not been updated and therefore does not reflect changes in the Target Group’s reserves since that date.

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Reliance on Key Personnel

The Target Group’s success depends in large measure on certain key personnel. The loss of the services of such key personnel may have a material adverse effect on the Target Group’s business, financial condition, results of operations and prospects. The contributions of the existing management team to the immediate and near term operations of the Target Group are likely to be of central importance. In addition, the competition for qualified personnel in the oil and natural gas industry is strong and there can be no assurance that the Target Group will be able to continue to attract and retain all personnel necessary for the development and operation of its business. Investors must rely upon the ability, expertise, judgment, discretion, integrity and good faith of the management of the Target Group.

Political Uncertainty

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. During the recent presidential campaign a number of election promises were made and the new American administration has begun taking steps to implement certain of these promises. Included in the actions that the administration has discussed are the renegotiation of the terms of the North American Free Trade Agreement, withdrawal of the United States from the Trans-Pacific Partnership, imposition of a tax on the importation of goods into the United States, reduction of regulation and taxation in the United States, and introduction of laws to reduce immigration and restrict access into the United States for citizens of certain countries. It is presently unclear exactly what actions the new administration in the United States will implement, and if implemented, how these actions may impact Canada and in particular the oil and gas industry. Any actions taken by the new United States administration may have a negative impact on the Canadian economy and on the businesses, financial conditions, results of operations and the valuation of Canadian oil and gas companies, including the Target Group.

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 taken steps to implement such withdrawal. Some European countries have also experienced the rise of anti-establishment political parties and public protests held against open-door immigration policies, trade and globalization. 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 Target Group’s ability to market its products internationally, increase costs for goods and services required for the Target Group’s operations, reduce access to skilled labour and negatively impact the Target Group’s business, operations, and financial conditions.

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Competition

The petroleum industry is competitive in all of its phases. The Target Group competes with numerous other entities in the exploration, development, production and marketing of oil and natural gas. The Target Group’s competitors include oil and natural gas companies that have substantially greater financial resources, staff and facilities than those of the Target Group. Some of these companies not only explore for, develop and produce oil and natural gas, but also carry on refining operations and market oil and natural gas on an international basis. As a result of these complementary activities, some of these competitors may have greater and more diverse competitive resources to draw on than the Target Group. The Target Group’s ability to increase its reserves in the future will depend not only on its ability to explore and develop its present properties, but also on its ability to select and acquire other suitable producing properties or prospects for exploratory drilling. Competitive factors in the distribution and marketing of oil and natural gas include price, process, and reliability of delivery and storage.

Foreign exchange risk

IV MATERIAL ADVERSE CHANGE

The Directors are not aware as at the Latest Practicable Date of any material adverse change having occurred since the effective date of the Competent Person’s Report.

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APPENDIX V

D e G o l y e r a n d M a c N a u g h t o n

5001 Spring Valley Road Suite 800 East Dallas, Texas 75244

This is a digital representation of a DeGolyer and MacNaughton report.

Each file contained herein is intended to be a manifestation of certain data in the subject report and as such is subject to the definitions, qualifications, explanations, conclusions, and other conditions thereof. The information and data contained in each file may be subject to misinterpretation; therefore, the signed and bound copy of this report should be considered the only authoritative source of such information.

==> picture [126 x 98] intentionally omitted <==

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APPENDIX V COMPETENT PERSON’S REPORT AND VALUATION REPORT

D e G o l y e r a n d M a c N a u g h t o n

5001 Spring Valley Road Suite 800 East Dallas, Texas 75244

COMPETENT PERSONS REPORT as of MARCH 31, 2017

CERTAIN PROPERTIES

in

ALBERTA, BRITISH COLUMBIA, and SASKATCHEWAN

owned by CQ ENERGY CANADA RESOURCES PARTNERSHIP prepared for MIE HOLDINGS CORPORATION

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APPENDIX V

D e G o l y e r a n d M a c N a u g h t o n

5001 Spring Valley Road Suite 800 East Dallas, Texas 75244

July 28, 2017

MIE Holdings Corporation Suite 1501, Block 6 Grand Place 5 Huizhong Road, Chaoyang District Beijing 100101 China

Ladies and Gentlemen:

Pursuant to your request, we have prepared estimates, as of March 31, 2017, of the proved and probable oil, condensate, gas, and natural gas liquids (NGL) reserves and estimates of the value of the proved and proved-plus-probable reserves of certain properties in which CQ Energy Canada Resources Partnership (CQ Energy) has represented that it owns an interest. The properties are located in Alberta, British Columbia, and Saskatchewan, Canada.

Estimates of proved and probable reserves have been prepared using reserves definitions established by Canadian National Instrument 51-101 (NI 51-101). The NI 51-101 standard is a referenced standard in published guidance notes of The Stock Exchange of Hong Kong Limited (SEHK). These reserves definitions are discussed in detail under the Definition of Reserves heading of this report.

Reserves estimated in this report are expressed as gross, company gross, and net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after March 31, 2017. Company gross reserves are defined as that portion of the gross reserves attributable to the working interests owned by CQ Energy after deducting working interests owned by others. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by CQ Energy after deducting royalty and all interests owned by others.

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APPENDIX V COMPETENT PERSON’S REPORT AND VALUATION REPORT

DeGolyer and MacNaughton

This report presents values that were estimated for net proved and proved-plus-probable reserves using prices and costs provided by CQ Energy. A detailed explanation of the future price and cost assumptions is included under the Valuation of Reserves section of this report, and referred to herein as the Forecast Price Case. This report also presents values that were estimated for net proved and proved-plus-probable reserves based on eight sensitivity cases. All values in this report are expressed in Canadian dollars (CDN$).

Values shown in this report are expressed in terms of future gross revenue, future net revenue, and net present value. Future gross revenue is that revenue which will accrue to the evaluated interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting royalty, operating expenses, capital costs, and abandonment and reclamation costs from the future gross revenue. Operating expenses include field operating expenses, transportation expenses, and an allocation of overhead that directly relates to production activities. Capital costs include items such as surface facilities and pipelines, drilling, well completions, gathering systems, and compressors. Net present value is defined as future net revenue discounted at a specified arbitrary rate compounded monthly over the expected period of realization. Net present value should not be construed as fair market value because no consideration was given to additional factors that influence the prices at which properties are bought and sold. Net present values at discount rates of 5, 8, 10, 12, and 15 percent are included in this report.

Estimates of reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves and revenue estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Executive Summary

CQ Energy has represented that it owns interests in 134 fields in Alberta, British Columbia, and Saskatchewan, Canada. A map of the properties is shown on Figure 1. We have evaluated 78 of the 134 fields. The remaining 56 fields, which represent less than 5 percent of CQ Energy’s net present value, were evaluated by CQ Energy. Of the 78 fields evaluated by us, 62 fields are currently producing. There are 6 non-producing fields and 10 shut-in fields, the reserves for which have been

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APPENDIX V COMPETENT PERSON’S REPORT AND VALUATION REPORT

DeGolyer and MacNaughton

estimated herein to be zero. The following table details the average working interest, lease expiration date, and production status for each of the 15 major fields, which represent approximately 70 percent of the reserves of CQ Energy.

oximately 70 percent of the reserves of CQ Energy.	oximately 70 percent of the reserves of CQ Energy.	oximately 70 percent of the reserves of CQ Energy.	oximately 70 percent of the reserves of CQ Energy.
Average Working Interest and Production Status – Selected Fields
Field Alderson Benjamin Burnt Timber Carrot Creek Ferrier Gilby Glacier Hanlan Unit Laprise Group MHCU1 Panther Stolberg Unit Turner Valley Voyager Wildcat Hills Unit	Working Interest (percent) 71.5 76.3 100.0 79.0 93.1 69.9 65.7 57.0 99.3 40.9 100.0 65.5 87.3 45.8 100.0	Lease Expiration Date	Production Status
		Not Applicable Not Applicable Not Applicable Not Applicable Not Applicable Not Applicable Not Applicable Not Applicable Not Applicable Not Applicable Not Applicable Not Applicable Not Applicable Not Applicable Not Applicable	Producing Producing Non-Producing Producing Producing Producing Producing Producing Producing Producing Producing Producing Producing Producing Producing

==> picture [274 x 282] intentionally omitted <==

Figure 1 Property Index Map – Canada

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COMPETENT PERSON’S REPORT AND VALUATION REPORT

APPENDIX V

DeGolyer and MacNaughton

The estimated net proved and probable reserves of the properties evaluated, as of March 31, 2017, for the Forecast Price Case described herein are summarized as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe):

	Net Reserves	Net Reserves
Oil and Condensate (Mbbl)	NGL (Mbbl)	Sales Gas (MMcf)	Oil Equivalent (Mboe)
11,214 672 4,575	3,073 138 722	689,856 95,442 290,909	129,263 16,717 53,782
16,461 7,170 23,631	3,933 1,669 5,602	1,076,207 543,407 1,619,614	199,762 99,407 299,169

Notes:

Probable reserves are presented as required by the Canadian National Instrument 51-101 and are not equivalent to proved reserves.
The proved-plus-probable volumes are an arithmetic sum of multiple estimates of reserves, which statistical principles indicate may be misleading as to volumes that may actually be recovered. Attention should be given to the estimates of individual classes of reserves and the probability of recovery, as explained under the Definition of Reserves heading of this report.
All of the oil volumes estimated in this report are light or medium oil.
Gas is converted to oil equivalent using a factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.

The estimated future net revenue and net present value of the future net revenue at various discount rates attributable to CQ Energy’s net interests in the proved and proved-plus-probable reserves of the properties evaluated, as of March 31, 2017, for the Forecast Price Case described herein are summarized as follows, expressed in millions of Canadian dollars (MM CDN$):

Future Net Revenue Net Present Value at 5 Percent Net Present Value at 8 Percent Net Present Value at 10 Percent Net Present Value at 12 Percent Net Present Value at 15 Percent		Forecast Price Case	Forecast Price Case	Forecast Price Case
	Proved Developed Producing (MM CDN$) 1,865 1,314 1,114 1,012 928 826	Proved Developed Non-Producing (MM CDN$) 232 169 143 130 119 105	Proved Undeveloped (MM CDN$) 667 323 204 144 96 42	Total Proved (MM CDN$) 2,764 1,806 1,461 1,286 1,143 973	Proved Plus Probable (MM CDN$)
					4,910 2,807 2,147 1,833 1,585 1,301

Notes:

Values for probable reserves are presented as required by the Canadian National Instrument 51-101 and are not equivalent to values for proved reserves.
Future Canadian income tax expenses were not taken into account in the preparation of these estimates.

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Introduction

DeGolyer and MacNaughton is a Delaware Corporation with offices at 5001 Spring Valley Road, Suite 800 East, Dallas, Texas 75244, U.S.A. The firm has been providing petroleum consulting services throughout the world since 1936. The firm’s professional engineers, geologists, geophysicists, petrophysicists, and economists are engaged in the independent evaluation of oil and gas properties, evaluation of hydrocarbon and other mineral prospects, basin evaluations, comprehensive field studies, equity studies, and studies of supply and economics related to the energy industry. Except for the provision of professional services on a fee basis, DeGolyer and MacNaughton has no commercial arrangement with any other person or company involved in the interests which are the subject of this report.

This evaluation has been supervised by Mr. Gregory K. Graves. Mr. Graves is a Senior Vice President with DeGolyer and MacNaughton, manager of the firm’s North America Division, a Registered Professional Engineer in the State of Texas, and a member of the International Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. He has in excess of 33 years of experience in oil and gas reservoir studies and evaluations.

Information used in the preparation of this report was obtained from CQ Energy. In the preparation of this report we have relied upon information furnished by CQ Energy with respect to the property interests to be evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sales of production, lease expiration dates, and various other information and data that were accepted as represented. Although we have not had independent verification, the information used in this report appears reasonable. Existing production data, reports from third parties, and photographic evidence of all fields included in this report were considered adequate because the fields are in established producing venues.

As far as we are aware, there are no special factors which would affect the production business of CQ Energy that would require additional information for the proper evaluation of these fields. This report has been prepared within the context of our understanding of the effects of host country petroleum legislation, taxation, and other regulations that currently apply to these assets.

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Reserves estimated herein are, by definition, commercial. Economic limits are based on prices and costs provided by CQ Energy. A detailed explanation of the prices and costs is provided under the Valuation of Reserves heading of this report.

Definition of Reserves

Petroleum reserves included in this report are categorized by degree of proof as proved or probable. Only proved and probable reserves have been evaluated for this report. No possible reserves have been evaluated for this report. For purposes of this report, reserves are those quantities of oil or gas anticipated to be economically recoverable from known accumulations. The definitions of reserves shown below serve as the basis for the estimates contained herein. The definitions are in accordance with those prepared for the Canadian National Instrument 51-101 as presented in the Canadian Oil and Gas Evaluation Handbook (COGEH) Second Edition September 1, 2007, Volume 1: Reserves Definitions and Evaluation Practices and Procedures , Section 5. The petroleum reserves are categorized in accordance with Sections 5.4.1, 5.4.2, and 5.4.3 of COGEH shown below. Section 5 of the COGEH contains the complete and official explanation of reserves definitions utilized herein.

Reserves Categories – 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.

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

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.

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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 + probable reserves.

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 + probable + possible reserves.

Development and Production Status – Each of the reserves categories (proved, probable, and possible) may be divided into developed and undeveloped categories.

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.

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.

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.

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 categorization (proved, probable, possible) to which they are assigned.

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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.

Levels of Certainty for Reported Reserves – The qualitative certainty levels contained in the definitions in Section 5.4.1 [ Reserves Categories above ] are applicable to individual Reserves Entities, which refers to the lowest level at which reserves calculations are performed, and to Reported Reserves, which refers to the highest level sum of individual entity estimates for which reserves estimates are presented. Reported Reserves should target the following levels of certainty under a specific set of economic conditions:

at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves;
at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved + probable reserves;
at least a 10 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved + probable + possible reserves.

A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

Field Discussions

The 15 major fields of the CQ Energy properties are located in northeastern British Columbia and across Alberta within the Western Canada Sedimentary Basin. The basin covers an area of 1,400,000 square kilometers with the thickest

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and deepest sediments along the highly disturbed foothills belt of the Rocky Mountains thinning toward the east and north. The development of the basin is generally associated with two different tectonic settings. First, the deposition of the Paleozoic to Jurassic platformal succession on the passive margin of North America dominated by carbonates rocks. These deposits were then overlain by the midJurassic to Paleocene foreland basin succession consisting of clastic rocks formed during the active margin orogenic formation of the Canadian Cordillera. The basin comprises a number of discrete petroleum systems.

Reservoir Geology

The middle Jurassic to Paleocene sections contain multiple productive formations. Those of interest in major properties are: the Late Cretaceous-age Belly River, Milk River, Medicine Hat, Cardium, and Viking Formations; the early Cretaceous-age Notikewin and Wilrich Formations and Mannville Group; and the Middle Jurassic-age Rock Creek Formation. These deposits are generally clastics with the trapping mechanisms a combination of structure and stratigraphy.

The Paleozoic to Middle Jurassic sections contain the following productive zones of interest in the major properties: the Late Triassic-age Baldonnel and Charlie Lake Formations; the Early Triassic-age Montney Formation; the Mississippian-age Rundle Group; and the Middle to Late Devonian-age Wabamun and Beaverhill Lake Formations. These deposits are mostly carbonates with some interspersed clastics. The trapping mechanisms are a combination of structure and stratigraphy.

Production Performance

As of May 31, 2016, 110 of the 134 fields in which CQ Energy has represented that it owns an interest were on production. The cumulative production as of May 31, 2016, is estimated to be approximately 656 million barrels (MMbbl) of oil, 17,512 billion cubic feet (Bcf) of gas, and 2,933 MMbbl of water. The production rate is at an average of approximately 19 Mbbl of oil per day and 604 MMcf of gas per day as of May 31, 2016.

The historical oil and gas production since inception, as well as the forecast for all fields, is illustrated on Figures 2 and 3, respectively.

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==> picture [343 x 250] intentionally omitted <==

Figure 2

CQ Energy Total Company Oil Profile

==> picture [322 x 244] intentionally omitted <==

Figure 3 CQ Energy Total Company Gas Profile

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Facilities Infrastructure

All the fields evaluated herein are in established fields in Canada; therefore, a facility infrastructure description was deemed unnecessary for the purpose of this report.

Alberta

Alderson Field

CQ Energy has represented that it owns a working interest of approximately 71.5 percent in the Alderson field of southwest Alberta, in Townships 14 to 16, Ranges 9 to 11W4. There are currently 950 producing gas wells on CQ Energy’s acreage. The primary productive zones are the Milk River, Medicine Hat, and Second White Specks.

Milk River Formation

The Milk River Formation is Upper Cretaceous in age, is overlain by the Belly River Formation, and overlies the First White Specks shale. The Milk River Formation forms a northeastern-tapering clastic wedge that extends across southern Alberta and southwestern Saskatchewan. The character of the formation changes from mostly shallow marine shoreline and coastal deposition in the southwest to deeper marine shelf deposits in the northeast.

Medicine Hat Formation

The Medicine Hat Formation of the Colorado Group is Upper Cretaceous in age, and is overlain by the First White Specks shale. The formation is underlain by the Colorado Shale. The Medicine Hat Formation consists of interbedded marine silts and shales with occasional sandstone beds. The primary reservoir consists of a coarsening-upward, north/south-trending marine sandstone that undergoes a lateral facies change to a marine shale to the east. Gas is trapped stratigraphically by the lateral pinchout of the sand facies.

Reserves and Production Forecast

Gas production in the Alderson field has historically come from the Medicine Hat and Milk River Formations. The field has been developed for more than 40 years and has produced a total of 410.1 Bcf of gas as of May 2016. Currently, the field is producing at a combined rate of 23,608 Mcf of gas per day. Proved and probable producing reserves were assigned to all producing wells based on

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decline-curve analysis. Proved and probable undeveloped reserves were assigned to 400 drilling locations based on analogy to surrounding wells. CQ Energy has represented that it plans to drill 100 wells per year starting in 2018.

Benjamin Field

CQ Energy has represented that it owns a working interest of approximately 76.3 percent in the Benjamin field of southern Alberta, in Townships 28 to 29, Ranges 7 to 8 W5M. There are currently 15 producing gas wells on CQ Energy’s acreage. The primary productive zone is the Rundle Group.

The field is located within a belt of overlapping stacked thrust sheets and detached folds that form the eastern margin of the North American Cordillera. The evolution of the Cordillera created a prospective structural fairway known as the Rocky Mountain Foreland Thrust and Fold Belt. This prominent feature is continuous throughout western Canada. Within this complex area, a series of uplifted stacked thrust wedges are folded and consist of rolled over anticlinal structures bounded by thrust faults. Sedimentary packages later detached from the more stable section of the Paleozoic sediments by a lower detachment floor thrust.

Mount Head Formation

The Mount Head Formation is the uppermost member of the Mississippianage Rundle Group. It overlies the Turner Valley Formation and is overlain by the Nordegg Formation. The Mount Head Formation consists of a fine-grained to microcrystalline dolomite containing zones of pinpoint vugs often filled with opaque calcite. Trapping is structural as the reservoirs are found in anticlines.

Turner Valley Formation

The Turner Valley Formation is a middle member of the Mississippian-age Rundle Group and is overlain by the Mount Head Formation. Underlying the Turner Valley Formation is the Elkton Formation. The Turner Valley Formation consists of medium to coarse crystalline crinoidal limestone. The Turner Valley is dolomitized over much of southwestern Alberta. Trapping is structural.

Reserves and Production Forecast

There are currently 15 gas wells producing at a combined rate of 10.8 MMcf per day from the Rundle Group. Proved and probable producing reserves were assigned using decline-curve analysis. Well 11-13-029-08W5 was considered uneconomic to produce; therefore, no reserves were assigned to this well.

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CQ Energy has proposed the drilling of six new wells to target Rundle Group gas, including three in the Benjamin proper area and three in the Mockingbird area. Proved and probable undeveloped reserves were assigned based on analogy to offsetting wells, with consideration of material balance and volumetric gas in place.

Burnt Timber Field

CQ Energy has represented that it owns a working interest of approximately 100 percent in the Burnt Timber area of southwest Alberta, in Townships 29 to 32, Ranges 8 to 9 W5M. There are currently 10 re-activation candidates on CQ Energy’s acreage. The primary productive zones are the Rundle Group and Wabamun Formation.

Rundle Group

The Rundle Group is Mississippian in age and is overlain by the Nordegg Formation and overlies the Banff Formation. In this area, the Rundle Group consists of the Turner Valley, Elkton, Shunda, and Pekisko Formations. The Turner Valley Formation consists of medium to coarse crystalline crinoidal limestone. The Elkton Formation is composed of high-energy shelf dolomite and lime wackestone, grainstone, and packstone. The Shunda Formation consists of interbedded shale, marls, and limestones. The Lowermost Pekisko Formation consists of shelf grainstones deposited in high-energy environments. Trapping in this area is structural.

Wabamun Formation

The Wabamun Formation is Late Devonian in age and is overlain by the Banff Formation and overlies the Graminia Formation. The Wabamun Formation consists of dolomitic limestones and calcareous dolomites with appreciable interbedded anhydrite.

Reserves and Production Forecast

The Burnt Timber field was shut-in during October 2015 at a rate of 3 MMcf of gas per day. A total of 10 wells (13 events) are forecast to be re-activated in June 2017. Proved and probable non-producing reserves were assigned to all wells based on decline-curve analysis. Well 05-07-031-09W5 is forecast to produce at an uneconomic rate; therefore, no reserves were assigned to this well. CQ Energy anticipates the required infrastructure will be in place in May 2017. The total reactivation cost of CDN$1,800,000 was allocated to the individual wells.

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Carrot Creek Field

CQ Energy has represented that it owns various working interests in the Carrot Creek field of central Alberta, Townships 50 to 54, Ranges 12 to 16 W5M. There are currently 17 producing oil wells, 88 producing gas wells, and several shut-in wells on CQ Energy’s acreage. This area produces oil and gas from the Upper Cretaceous Edmonton, Belly River, Cardium, Second White Specks, and Viking Formations; the Glauconitic and Ellerslie Formations of the Mannville Group; the Lower Cretaceous Bluesky and Gething Formations, and the Jurassic Rock Creek and Nordegg Formations.

Cardium Formation

The Upper Cretaceous-age Cardium Formation is a member of the Colorado Group and is overlain by the Colorado shale. In this area, it overlies the Blackstone Formation. The Cardium sandstone occurs as a shallow marine sand deposited during a rapid clastic influx from the west. These sands were deposited as a shoreface sequence. Trapping is stratigraphic due to pinchout of the bar sands.

Viking Formation

The Viking Formation is Lower Cretaceous in age. It is overlain by the Base Fish Scales Formation and overlies the Joli Fou shale. In this area, the Viking Formation consists of stacked marine shoreface bars that were deposited during coarsening-upward segments of a regional shelf to shoreface sequence. Trapping is stratigraphic.

Notikewin Formation

The Notikewin Formation is the uppermost member of the Spirit River Group and is Lower Cretaceous in age. In this area, the Notikewin Formation is overlain by the Upper Mannville and underlain by the Falher Member of the Spirit River Group. The Notikewin Formation formed as a prograding beach sequence interrupted by tight fluvial channel sequences, which then sourced the sediment for the next shoreline trend.

Gething Formation

The Gething Formation is Lower Cretaceous in age and unconformably overlies the Jurassic-age Fernie Group. In this area, the Gething Formation is overlain by an Ostracod channel. The Gething Formation was deposited by fluvial stacked channel sands consisting of lithic sandstones interbedded with silts, shales, and coals deposited in a continental-to-marginal marine facies. The interval consists mainly of silty shales and thin coarsening-upward silty sands. There are occasional

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thick, cleaner sand channels near the base of the interval. Trapping is due to the stratigraphic pinchout of the reservoir-quality sands.

Rock Creek Formation

The Rock Creek Formation is Middle Jurassic in age. It is overlain by the Fernie shale and underlain by the Poker Chip shale. The Rock Creek Formation in this area can be divided into upper, middle, and lower zones. The Upper and Middle Rock Creek zones are interpreted as regressive, progradational siliciclasitic bar complexes. The Lower Rock Creek zone is interpreted as a transgressive siliciclasitic bar complex. The Rock Creek Formation is interpreted as having been deposited in a nearshore marine sedimentary environment.

Reserves and Production Forecast

The Carrot Creek field was developed with vertical and horizontal gas wells targeting the Second White Specks, Cardium, Viking, Notikewin, Bluesky, Ostracod, Ellerslie, and Rock Creek Formations. Combined production is currently 17.0 MMcf per day with an oil-gas ratio of 3.3 barrels per MMcf as of May 2016. In addition, there are also vertical and horizontal oil wells producing from the Second White Specks, Cardium, Viking, and Ostracod Formations at a total rate of 118.5 barrels of oil per day with a gas-oil ratio of 8.422 Mcf per barrel. Proved and probable producing reserves were assigned to the producing wells based on decline-curve analysis.

A NGL yield of 37 barrels per MMcf of gas was incorporated in the evaluation based on data provided by CQ Energy.

CQ Energy has represented that it plans to workover or re-complete eight zones in the Bluesky, Cardium, Gething, Second White Specks, and Viking Formations. Proved and probable non-producing reserves were assigned to six zones while probable non-producing reserves were assigned to two zones. All of the reserves were estimated based on volumetric estimation or analogy to surrounding wells.

Sixteen drilling locations were identified by CQ Energy. These locations are forecast to be placed on production in 2017, 2018, and 2019. Proved and probable undeveloped reserves were assigned to one Notikewin location, three Rock Creek locations, and seven Gething locations, while probable undeveloped reserves were assigned to the remaining three Notikewin and two Gething locations. Reserves for all locations were estimated based on volumetric calculations and analogy to

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surrounding wells. However, three Rock Creek locations and one Gething location were determined to be uneconomic; therefore, proved undeveloped reserves for these locations are estimated to be zero.

Ferrier Field

CQ Energy has represented that it owns an average working interest of approximately 93.1 percent in the Ferrier field of southwest Alberta, in Townships 39 to 42, Ranges 7 to 9 W5M. There are currently 93 producing oil wells, 51 producing gas wells, and several shut-in or abandoned wells on CQ Energy’s acreage. Of these, there are 8 producing oil wells in Belly River Unit 1 and 85 producing oil wells and 19 producing gas wells in Cardium Unit 3.

Belly River Formation

The Upper Cretaceous-age Belly River Formation comprises the sediments between the Bearpaw Formation and the dark shales of the Colorado Group. The Belly River consists of predominantly interbedded mudstones and very fine-grained sandstones with lesser but prominent coarser sandstone beds. The sands are diachronus in nature and are often deposited as shoreface sands prograding into the basin from the southwest to northeast.

Cardium Formation

The Upper Cretaceous-age Cardium Formation is a member of the Colorado Group and is overlain by the Colorado Shale. In this area, the Cardium Formation overlies the Blackstone Formation. The Cardium sandstone occurs as a shallow marine sand deposited during a rapid clastic influx from the west. These sands were deposited as a shoreface sequence. Trapping is stratigraphic due to pinchout of the bar sands.

Viking Formation

The Viking Formation is Lower Cretaceous in age. It is overlain by the Base Fish Scales Formation and overlies the Joli Fou Shale. In this area, the Viking Formation consists of stacked marine shoreface bars that were deposited during coarsening-upward segments of a regional shelf-to-shoreface sequence. Trapping is stratigraphic.

Mannville Group

The Mannville Group is Lower Cretaceous in age and is overlain by the Joli Fou Formation and underlain by the Fernie Group. In this area, the Mannville Group consists of the Glauconitic, Ostracod, and Ellerslie Formations. The

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Glauconitic Formation, the lowermost member of the Upper Mannville Group, was deposited in a transgressive shallow marine environment. The Ostracod Formation is the topmost member of the Lower Mannville Group, and consists of a thin diachronous unit of calcareous mudstone with interbedded limestone deposited in marine bays, brackish-water lagoons, and freshwater lakes. The lowermost member of the Lower Mannville Group is the Ellerslie Formation, which consists of a complex fluvial system of stacked continental to marginal marine sediments.

Rock Creek Formation

The Rock Creek Formation is Middle Jurassic in age and is overlain by the Fernie Shale and underlain by the Poker Chip Shale. The Rock Creek Formation in this area can be divided into upper and lower zones. The Upper Rock Creek zone is interpreted as a regressive, progradational siliciclasitic bar complex. The Lower Rock Creek zone is interpreted as a transgressive siliciclastic bar complex. The Rock Creek Formation consists of sediments deposited in a nearshore marine sedimentary environment.

Reserves and Production Forecast

The Ferrier field was brought on production in March 1965. Existing wells have produced a total of 520.1 Bcf of gas and 46.0 MMbbl of oil as of May 2016. The field produces from a variety of formations including the Belly River, Cardium, Mannville, Rock Creek, and Viking Formations. The field is currently producing at a combined rate of 9.6 MMcf of gas per day and 1.3 Mbbl of oil per day. Proved and probable producing reserves were assigned to all producing wells based on declinecurve analysis.

There have been 10 Cardium locations, 7 Basal Belly River locations, and 3 workovers targeting the Basal Belly River Oil Formation included in the development plan provided by CQ Energy. These wells and locations are forecast to be placed on production throughout 2017 and 2018. Proved and probable undeveloped reserves were assigned to seven Cardium locations and five Basal Belly River locations, while probable undeveloped reserves were assigned to the remaining five locations. Probable non-producing reserves were assigned to the three workovers. All reserves were assigned based on volumetric calculation and analogy to surrounding wells.

Gilby Field

CQ Energy has represented that it owns an average working interest of approximately 69.9 percent in the Gilby field of southwest Alberta in Townships 40

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to 42, Ranges 3 to 5 W5M. There are currently 10 producing oil wells, 115 producing gas wells, and several shut-in wells on CQ Energy’s acreage. This area produces oil and gas from the Upper Cretaceous Edmonton, Belly River, Cardium, Second White Specks, and Viking Formations; the Glauconitic and Ellerslie Formations of the Mannville Group; and the Mississippian Rundle Group.

Glauconitic Formation

The Lower Cretaceous-age Glauconitic Sandstone is the lowermost member of the Upper Mannville Group. In this area, the Glauconitic Formation is overlain by the Clearwater Shale and overlies the Ostracod Formation. The Glauconitic sands in this area were deposited as marginal marine shoreface sands to marine sandstones often deposited as southwest-to-northeast trending bars. These sands were deposited as nearshore sandbars.

Reserves and Production Forecast

The Gilby field was brought on production in December 1961 and has produced a total of 724.1 Bcf of gas and 3.4 MMbbl of oil as of May 2016. The field produces from several formations including the Mannville, Edmonton, Jurassic, and Rundle Formations. The field is currently producing at a combined rate of 24.0 MMcf of gas per day and 47.6 barrels of oil per day. Proved and probable producing reserves were assigned to all producing wells based on decline-curve analysis or volumetric calculations.

Proved and probable non-producing reserves were assigned to wells 100/09-15-041-03W5 and 100/14-02-042-05W5/2. Both wells were temporarily shut-in and are forecast to resume production in mid-2017. Re-activation capital, provided by CQ Energy, was included in this evaluation.

Well 03/06-21-041-03W5 is forecast to resume production in September 2017, pending minor workovers. Proved and probable non-producing reserves were assigned to this well based on decline-curve analysis.

Probable non-producing reserves were assigned to wells 16-16-041-03W5, 06-27-041-03W5, and 01-29-041-03W5. These wells are forecast to be re-completed in the Edmonton Formation, tied-in, and brought on production in mid-2019.

A total of 15 Glauconite gas wells were placed on production in late 2014 and early 2015, with initial production rates between 1,330 and 2,600 Mcf of gas per day. Based on performance of these new wells, 14 horizontal drilling wells were identified

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by CQ Energy to further develop the Glauconite Formation. Proved and probable undeveloped reserves were assigned to these wells based on volumetric calculations.

Glacier Field

CQ Energy has represented that it owns various working interests in the Glacier area of west-central Alberta, in Townships 75 to 78, Ranges 9 to 13 W6M. There are currently 7 producing oil wells, 55 producing gas wells, 6 shut-in oil wells, and 10 shut-in gas wells on CQ Energy’s acreage. This area produces oil and gas from the Upper Cretaceous Doe Creek Formation; the Lower Cretaceous Paddy, Cadotte, Bluesky, Gething, and Nikanassin Formations; the Middle Triassic Charlie Lake and Halfway Formations; and the Lower Triassic Doig and Montney Formations.

Montney Formation

The Montney Formation is Lower Triassic in age. It is overlain by the Doig Formation and overlies the Belloy Formation. The Montney Formation is generally a stacked transgressive sand shale sequence in which the sands occasionally develop excellent porosity. The shales of the Montney Formation, over most of British Columbia and Alberta, were deposited in relatively deep water, in a mid- to distal-shelf and slope setting as part of an overall turbidite sequence. In this area, the Montney Formation was deposited as a shallow sequence of progradational pulses of shoreface sandstones. The principle lithology is silty sandstone with the best sands having slightly lower shale content and better permeability. Overall, permeability is one of the major controlling factors in the development of the reservoirs.

Reserves and Production Forecast

The Glacier field was brought on production in March 1985 and has produced approximately 175 Bcf of gas and 997 Mbbl of oil as of May 2016. The field produces gas primarily from the Cadomin, Baldonnel, Halfway, Doig, Gething, and Montney Formations and oil from the Boundary Formation. The field is currently producing at a combined rate of 15.3 MMcf of gas per day and 99 barrels of oil per day. Proved and probable producing reserves were assigned to all producing wells based on decline-curve analysis.

Incremental reserves were added to seven wells based on a proposed completion plan by CQ Energy.

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CQ Energy has represented that it plans to place three of the suspended wells back on production. Based on this representation, proved and probable non-producing reserves were assigned to these wells.

The production of wells 100/06-19-076-11w6 and 100/08-23-076-12w6 have been restricted due to pipeline constraints; however, CQ Energy has represented that is expects to place these wells back on production with full capacity. Based on this representation, incremental reserves were added as proved and probable nonproducing reserves.

A total of 99 locations have been identified by CQ Energy in order to further develop the Glacier field. For the purposes of this report, 20 location wells were booked to the Lower Montney Formation, 29 location wells were booked to the Middle Montney Formation, and 50 location wells were booked to the Upper Montney Formation. Locations near existing producing wells were assigned proved and probable undeveloped reserves while the remaining location wells were assigned probable undeveloped reserves. The reserves were estimated using type curves generated from offsetting producing wells in the Montney Formation. Different facilities were proposed for processing of Glacier gas, in order to maximize the recovery of liquid hydrocarbons. As specified by CQ Energy, liquid yields of 2.0, 28.3, and 11 barrels per MMcf were applied to the upper, middle, and lower Montney locations respectively. These locations are forecast to be placed on production according to the development plan provided by CQ Energy.

Hanlan Unit Field

CQ Energy has represented that it owns a working interest of approximately 57 percent in the Hanlan Unit area of west-central Alberta, in Townships 46 to 47, Ranges 17 to 18 W5M. There are currently three producing gas wells and several shut-in or abandoned wells on CQ Energy’s acreage. This area produces gas from the Beaverhill Lake and Nisku Formations.

Beaverhill Lake Formation

The Beaverhill Lake Formation is Middle to Late Devonian in age. It conformably overlies the Elkpoint group and is overlain by the Woodbend shales. The Beaverhill Lake Formation consists of cyclical beds of limey shales and argillaceous micrites.

Gas in the Hanlan Unit has historically produced from the Beaverhill Lake Formation. The Hanlan Unit field has been developed for more than 30 years and

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has produced a total of 1,346 Bcf of gas as of May 2016. There are currently three gas wells producing a total of 27.7 MMcf per day. Proved and probable producing reserves were assigned to these wells based on decline-curve analysis verified by material balance.

Reserves and Production Forecast

Wells 07-02 and 06-21-047-17W5 are forecast to be worked over with production resuming from the Beaverhill Lake Formation in the first half of 2017. Proved and probable non-producing reserves were assigned to these wells based on decline-curve analysis. A workover was performed on well 05-15-047-17W5; however, this workover was unsuccessful. No reserves were assigned as there are no further plans for this well.

Well 100/11-25-047-18W5/0 was placed on production in March 1983. This well produced a total of 122.9 Bcf of gas before being abandoned in September 1997, when it was producing at a rate of 18,691 Mcf of gas per day. A substitute well is forecast to be drilled at the same location in an attempt to resume production in the area. An additional location was identified at 14-27-046-17W5. These infill wells were identified to accelerate reserves and were selected based on pay thickness and proximity to structural highs. Proved and probable undeveloped reserves were assigned to both wells based on material balance and pool decline.

MHCU1 Field

CQ Energy has represented that it owns an average working interest of approximately 40.9 percent in the MHCU1 area of southeast Alberta, in Townships 14 to 16, Ranges 4 to 5 W4M. There are currently 1,358 producing gas wells on CQ Energy’s acreage. The primary productive zones are the Belly River, Milk River, Colony, Medicine Hat, and Second White Specks.

Milk River Formation

The Milk River Formation is Upper Cretaceous in age. It is overlain by the Belly River Formation and overlies the First White Specks Shale. The Milk River Formation forms a northeastern-tapering clastic wedge that extends across southern Alberta and southwestern Saskatchewan. The character of the formation shifts from mostly shallow marine shoreline and coastal deposition in the southwest to deeper marine shelf deposits in the northeast.

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Medicine Hat Formation

The Medicine Hat Formation of the Colorado Group is Upper Cretaceous in age. It is overlain by the First White Specks Shale and underlain by the Colorado Shale. The Medicine Hat Formation consists of interbedded marine silts and shales with occasional sandstone beds. The primary reservoir consists of a coarseningupward, north/south-trending marine sandstone that undergoes a lateral facies shift to a marine shale to the east. Gas is trapped stratigraphically by the lateral pinchout of the sand facies.

Reserves and Production Forecast

Gas in the MHCU1 field has historically produced from the Medicine Hat and Milk River Formations. The field has been developed for more than 50 years and has produced a total of 457.6 Bcf of gas as of May 2016. The field is currently producing at a combined rate of 23.1 MMcf of gas per day. Proved and probable producing reserves were assigned to all producing wells based on decline-curve analysis. Proved and probable undeveloped reserves were assigned to 100 drilling locations based on analogy to surrounding wells.

Panther Field

CQ Energy has represented that it owns a 100-percent working interest in the Panther area of southwest Alberta in Townships 29 to 31, Ranges 10 to 11 W5M. There are currently 23 producing gas wells and 1 shut-in gas well on CQ Energy’s acreage. The primary productive zone is the Rundle Group.

The field is located within a belt of overlapping stacked thrust sheets and detached folds that form the eastern margin of the North American Cordillera. The evolution of the Cordillera created a prospective structural fairway known as the Rocky Mountain Foreland Thrust and Fold Belt. This prominent feature is continuous throughout western Canada. Within this complex area, a series of uplifted stacked thrust wedges are folded and consist of rolled-over anticlinal structures bounded by thrust faults. Sedimentary packages later detached from the more stable section of the Paleozoic sediments by a lower detachment floor thrust.

Mount Head Formation

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Turner Valley Formation

The Turner Valley Formation, a middle member of the Mississippian-age Rundle Group, is overlain by the Mount Head Formation. Underlying the Turner Valley is the Elkton Formation. The Turner Valley Formation consists of medium to coarse crystalline crinoidal limestone. The Turner Valley is dolomitized over much of southwestern Alberta, and trapping is structural.

Reserves and Production Forecast

The Panther field was brought on production in August 1989 and has produced approximately 276 Bcf of gas as of December 2016. As of May 2016, there were 23 gas wells producing at a combined rate of 45 MMcf of gas per day. Proved and probable producing reserves were assigned to all wells based on decline-curve analysis.

CQ Energy has proposed the drilling of six new wells and three re-completions in the Rundle Formation. Probable undeveloped reserves were assigned to the drilling locations based on analogy to offsetting wells. Proved and probable non-producing reserves were assigned to the recompletions based on analogy to offsetting wells.

CQ Energy plans to flow all gas in the Panther field from the Caroline plant to the CQ Energy Wildcat Hills plant by the third quarter of 2017, resulting in no processing fees. The total proved developed and total proved-plus-probable nonproducing reserves assume a gradual variable operating cost reduction to CDN$0.20 per Mcf.

Stolberg Unit Field

CQ Energy has represented that it owns a working interest of approximately 65.5 percent in the Rundle Unit in the Stolberg Unit field of southwest Alberta in Townships 41 to 42, Ranges 14 to 15 W5M. There are 18 producing gas wells in the Stolberg Unit field.

Rundle Group

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marls, and limestones. The Lowermost Pekisko Formation consists of shelf grainstones deposited in high-energy environments. Trapping in this area is structural.

Reserves and Production Forecast

The Stolberg Unit field was brought on production in October 1974 and has produced approximately 297.5 Bcf of gas as of May 2016. There are currently 18 gas wells producing at a combined rate of 19.4 MMcf of gas per day. Due to the age of production from the Stolberg Unit field, the wells have been grouped based on age and completion technique. These groups are as follows: vertical wells drilled before 1981, horizontal wells drilled before 2001, and horizontal wells drilled after 2001. Proved and probable producing reserves were assigned to each group based on decline-curve analysis.

Turner Valley Field

CQ Energy has represented that it owns a working interest of approximately 87.3 percent in the Turner Valley field of southwest Alberta, in Townships 27 to 28 and Ranges 5 to 7 W5M. There are currently 26 producing gas wells on CQ Energy’s acreage. The primary productive zones are the Viking and Rundle Formations.

The field is located within a belt of overlapping stacked thrust sheets and detached folds that form the eastern margin of the North American Cordillera. The evolution of the Cordillera created a prospective structural fairway known as the Rocky Mountain Foreland Thrust and Fold Belt. This prominent feature is continuous throughout western Canada. Within this complex area, a series of uplifted stacked thrust wedges are folded and consist of rolled-over anticlinal structures bounded by thrust faults. Sedimentary packages later detached from the more stable section of the Paleozoic sediments by a lower detachment floor thrust.

Viking Formation

The Viking Formation is Lower Cretaceous in age. It is overlain by the Base Fish Scales Formation and overlies the Blairmore Formation. In this area, the Viking Formation consists of stacked marine shoreface bars that were deposited during coarsening-upward segments of a regional shelf-to-shoreface sequence. These sands are divided into the Viking A, B, C, D, and E zones. Trapping in this area is a combination of structure and stratigraphy.

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Reserves and Production Forecast

There are currently 26 producing gas wells producing at a rate of 24 MMcf per day from the Viking and Rundle Formations. Proved and probable producing reserves were assigned to 25 producing wells using decline-curve analysis. There is currently one well producing at an uneconomic rate; therefore, no remaining reserves were assigned. The NGL yield of 2.6 barrels per MMcf of gas was incorporated for the wells in this evaluation as per lease operating statements provided by CQ Energy.

CQ Energy also plans to re-complete the horizontal Rundle gas well 13-17-028-06W5 using multiple stimulation techniques. The re-completion is forecast to be completed in September 2017. Incremental probable undeveloped reserves were assigned to this well.

Voyager Field

CQ Energy has represented that it owns a working interest of approximately 45.8 percent in the Voyager field of southern Alberta in Townships 46 to 48, Ranges 18 to 19 W5M. There are currently 15 producing gas wells on CQ Energy’s acreage.

Wilrich Formation

The Wilrich Formation is Lower Cretaceous in age. It is the lowermost member of the Spirit River Group and is bounded by the overlying Falher and the underlying Bluesky Formations. It consists of dark grey shale with thin interbeds of silt and sand deposited in an open marine environment.

Rundle Group

Reserves and Production Forecast

The Voyager field has been on production since June 1998 and has produced approximately 67.5 Bcf of gas and 3.2 Mbbl of oil as of May 2016. The field is

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currently producing from 15 wells at a combined rate of 18.2 MMcf of gas per day. Proved and probable producing reserves were assigned to 11 wells based on declinecurve analysis. CQ Energy drilled well 12-11-047-19W5 in the fourth quarter of 2014 to target the Wilrich Formation. This well was placed on production in January 2015. Proved and probable producing reserves were assigned to this well based on volumetric calculations and analogy to surrounding wells. CQ Energy drilled well 7-15-047-19W5 in the third quarter of 2013 to target the Wilrich Formation. This well was placed on production in July 2014. Proved and probable producing reserves were assigned to this well based on volumetric calculations and analogy to surrounding wells. The well 13-20-047-19 was drilled in the third quarter of 2013 and placed on production in September 2013. Proved and probable reserves were assigned to this well based on analogy to surrounding wells.

CQ Energy drilled well 6-30-046-18W5 in the fourth quarter of 2015 to target the Wilrich Formation. This well was placed on production in September 2016. Proved and probable producing reserves were assigned based on type-curve analysis of offsetting producing wells.

CQ Energy has identified 13 gas locations: 9 to target the Wilrich Formation and 4 to target the Turner Valley Formation. Proved and probable undeveloped reserves were assigned based on type-curve analysis of offsetting producing wells for their respective formations.

Wildcat Hills Unit Field

CQ Energy has represented that it owns a working interest of approximately 100 percent in the Wildcat Hills Unit of southwest Alberta. There are currently 19 producing gas wells and one injection well on CQ Energy’s acreage. The primary productive zone is the Rundle Formation.

Reserves and Production Forecast

The Wildcat Hills Unit is currently producing 13 MMcf per day from 19 wells in the Rundle Formation. Proved and probable producing reserves were assigned using decline-curve analysis. A condensate yield of 4.5 barrels per MMcf of gas was incorporated in this evaluation as per lease operating statements provided by CQ Energy.

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British Columbia

Laprise Group Field

CQ Energy has represented that it owns a working interest between 18 to 100 percent in approximately 4,555 acres of land in the Laprise Group field of northeastern British Columbia. There are currently 42 gas wells, 8 suspended gas wells, 1 suspended oil well, and 5 abandoned gas wells on CQ Energy’s acreage.

Eight wells have been completed in the Baldonnel and Upper Charlie Lake B carbonate sequence in the Laprise East area. One well was completed in both the Baldonnel and Upper Charlie Lake A Formations. The earliest wells were placed on production in February 1979.

The reservoirs developed in the Laprise Main area include the Baldonnel and the Upper Charlie Lake A and D. These are generally found to be carbonate-rich sediments with some clastic siltstones and shale.

Reserves and Production Forecast

Laprise Creek

A total of 11 wells are currently producing at a rate of 4,712 Mcf per day in Laprise Creek. Proved and probable producing gas reserves were assigned to these wells based on decline-curve analysis.

CQ Energy has indicated that it plans to re-activate well 202/a-007-e/094-h05/0 in March 2017. Proved and probable non-producing reserves were assigned to this well based on analogy to similar wells in the area.

Laprise East

A total of nine wells were evaluated for proved and probable gas reserves. First gas production was reported in February 1979 with the completion of wells 200/c072-E/094-H-05-0, 200dc-093-E/094-H-05/0, and 200/b-088-F/094-H-05/0 in the Baldonnel and Upper Charlie Lake B Formations. Since discovery, gas has been further developed in six additional wells in the same zones. The field has been on decline since 1992, and is currently producing at a rate of 2,925 Mcf of gas per day.

CQ Energy has indicated that it plans to perform workovers in June 2017 on wells 200/c-012-L/094-14-05/0 and 200/d-071-E/094-H-05/0 in order to bring production back to 1,000 and 283 Mcf per day, respectively. Proved producing

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reserves were assigned based on the current condition of the wells and decline-curve analysis, while proved and probable non-producing reserves were assigned based on decline-curve analysis and expected incremental rates.

Laprise Main

A total of 25 wells were evaluated for proved and probable gas reserves. An additional two wells were not assigned any reserves as they were suspended as of the effective date of this report. Production began in November 1960 with the completion of wells 200/d-068-E/094-H-05/0 and 200/c-056-E/094-H-05/0 in the commingled Baldonnel and Upper Charlie Lake A Formations. Since discovery, gas has been further developed in the same formations. The field production has been declining since 1975 and is currently producing at a rate of 6,972 Mcf of gas per day.

The production rate for well 200/a-022-E/094-H-05/0 decreased due to a hole in the tubing. Proved producing reserves were assigned based on the current condition of the well and decline-curve analysis. CQ Energy has represented that it plans to change the tubing on July 1, 2017. Proved and probable non-producing reserves were assigned based on decline-curve analysis and expected incremental rates after the tubing is changed.

CQ Energy has represented that it plans to re-activate wells 200/c-012-I/094G-08, 200/c-056-E/094-H-05, 200/c-069-E/094-H05, 200/c-078-E/094-H-05, 200/b-073A/094-G-08/0, 200/c-026-E-094-H-05/0, and 200/c-055-E/094-H-05/2 in April 2017. Proved and probable non-producing reserves were assigned to these wells based on decline-curve analysis.

Estimation of Reserves

Estimates of reserves were prepared by the use of standard geological and engineering methods generally accepted by the petroleum industry. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

Based on the current stage of field development, production performance, the development plans provided by CQ Energy, and the analyses of areas offsetting existing wells with test or production data, reserves were categorized as proved or probable.

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When applicable, the volumetric method was used to estimate the original oil in place (OOIP) or original gas in place (OGIP). Structure maps were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material-balance and other engineering methods were used to estimate OOIP or OGIP.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material-balance and other engineering methods were used to estimate recovery factors. In such cases, an analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production.

In certain cases, when the previously named methods could not be used, reserves were estimated by analogy with similar wells or reservoirs for which more complete data were available.

The reserves estimates presented herein were generally based on consideration of monthly production data through May 2016. Where applicable, the estimated cumulative production, as of March 31, 2017, was deducted from the gross ultimate recovery to estimate gross reserves.

Gas quantities estimated herein are reported as gross gas and sales gas. Wet gas is defined as indigenous gas in the reservoir to be produced as of March 31, 2017. Solution gas is defined as dissolved gas in wellbore or reservoir fluids which will remain in solution until the pressure or temperature conditions change, at which time it may break out of solution to become free gas. Separator gas is the gas remaining after field separation but prior to gas processing and shrinkage for fuel use. Sales gas is defined as the total gas to be produced from the reservoirs,

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measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing, including removal of nonhydrocarbon gas to meet pipeline specifications. Gross and company gross gas quantities include wet gas, solution gas, and separator gas. Net gas reserves are reported as sales gas. Net gas quantities are expressed at a temperature base of 60 degrees Fahrenheit and at a pressure base of 14.65 pounds per square inch absolute.

Oil and condensate reserves estimated herein are those to be recovered by field, platform, and onshore separation. NGL reserves reported herein are those to be recovered by plant processing. NGL reserves were estimated using yields for propane, butane, and ethane provided by CQ Energy. For the purposes of this report, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity.

Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no crude oil present in the reservoir. Associated gas includes both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying crude oil zone. Solution gas is gas dissolved in crude oil at initial reservoir conditions. Gas quantities estimated herein are nonassociated and associated gas.

The estimated gross, company gross, and net proved and probable reserves, as of March 31, 2017, for the Forecast Price Case described herein of the properties evaluated are summarized as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe):

			Forecast Pr	ice Case
Gross Re	serves	Company Gros	s Reserves		Net R	eserves
Oil and Condensate (Mbbl)	Gas (MMcf)	Oil and Condensate (Mbbl)	Gas (MMcf)	Oil and Condensate (Mbbl)	NGL (Mbbl)	Sales Gas (MMcf)
81,308 1,013 6,861	1,202,041 131,035 492,090	12,588 856 5,322	779,616 109,255 316,728	11,214 672 4,575	3,073 138 722	689,856 95,442 290,909
88,496 20,642 109,138	1,825,166 919,577 2,744,743	18,766 8,738 27,504	1,205,599 617,204 1,822,803	16,461 7,170 23,631	3,933 1,669 5,602	1,076,207 543,407 1,619,614

Notes:

Probable reserves are presented as required by the Canadian National Instrument 51-101 and are not equivalent to proved reserves.
The proved-plus-probable volumes are an arithmetic sum of multiple estimates of reserves, which statistical principles indicate may be misleading as to volumes that may actually be recovered. Attention should be given to the estimates of individual classes of reserves and the probability of recovery, as explained under the Definition of Reserves heading of this report.
All of the oil volumes estimated in this report are light or medium oil.
Gas is converted to oil equivalent using a factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.

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Risk Factors

Prices for oil, condensate, NGL, and gas fluctuate widely. Among the factors that can or could cause these price fluctuations are:

domestic and worldwide supplies of oil, NGL, and gas;
the actions of other oil-exporting nations, including the Organization of Petroleum Exporting Countries;
domestic and international drilling activity;
the price and quantity of imported and exported oil, NGL, and gas;
the level of consumer demand;
weather conditions and changes in weather patterns;
the availability, proximity, and capacity of appropriate transportation facilities, gathering, processing, and compression facilities, and refining facilities;
the price and availability of, and demand for, competing energy sources, including alternative energy sources;
the nature and extent of governmental regulation, including environmental regulation, regulation of derivatives transactions and hedging activities, tax laws and regulations, and laws and regulations with respect to the import and export of oil, gas, and related commodities;
• the level and effect of trading in commodity futures markets, including trading by commodity price speculators and others; and
the effect of worldwide energy conservation measures and alternative fuel requirements.

Drilling oil and gas wells, including development wells, involves numerous risks, including the risk that the operator may not encounter commercially productive oil and gas reserves.

Specifically, there is uncertainty as to the future cost or timing of drilling, completing, and operating wells, drilling operations may be curtailed, delayed, or canceled, and the cost of such operations may increase and/or the results of operations and cash flows from such operations may be impacted, as a result of a variety of factors, including:

unexpected drilling conditions;
title problems;
pressure or irregularities in formations;

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equipment failures or accidents;
adverse weather conditions, such as winter storms, flooding and hurricanes, and changes in weather patterns;
compliance with, or changes in, environmental, health, and safety laws and regulations relating to air emissions, hydraulic fracturing, access to and use of water, disposal of produced water, drilling fluids and other waste, laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of oil and gas, and other laws and regulations, such as tax laws and regulations;
the availability and timely issuance of required federal, state, tribal, and other permits and licenses, which may be affected by (among other things) government shutdowns or other suspensions of, or delays in, government services;
the availability of, costs associated with, and terms of contractual arrangements for properties, including mineral licenses and leases, pipelines, rail cars, oil hauling trucks, and qualified drivers, facilities, and equipment necessary to gather, process, compress, transport, and market oil, gas, and related commodities; and
the costs of, or shortages or delays in the availability of, drilling rigs, hydraulic fracturing services, pressure pumping equipment and supplies, tubular materials, water, sand, disposal facilities, qualified personnel and other necessary facilities, equipment, materials, supplies, and services.

Valuation of Reserves

This report has been prepared using future price and cost assumptions specified by CQ Energy. In this report, estimates of values for net proved and proved-plus-probable reserves were based on projections of estimated future production and revenue prepared for each asset with no risk adjustment applied to the probable reserves. Probable reserves involve substantially higher risks than proved reserves. Revenue values for proved-plus-probable reserves have not been adjusted to account for such risks; this adjustment would be necessary in order to make proved-plus-probable reserves values comparable with values for proved reserves.

The following assumptions were used for estimating future prices and costs for the Forecast Price Case:

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Oil, Condensate, and NGL Prices

Oil and condensate price differentials for each property were provided by CQ Energy. NGL price differentials by component for each property were provided by CQ Energy. The prices were calculated using these differentials to prices as scheduled in the following table, expressed in Canadian dollars per barrel (CDN$/bbl) and escalated annually at 2 percent thereafter.

Gas Prices

Gas price differentials for each property were provided by CQ Energy. The prices were calculated using these differentials to the prices as scheduled in the following table, expressed in Canadian dollars per million British thermal units (CDN$/MMBtu) and escalated annually at 2 percent thereafter. British thermal unit factors were provided by CQ Energy and used to convert prices from CDN$/MMBtu to Canadian dollars per thousand cubic feet (CDN$/Mcf).

Date 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029	Oil (CDN$/bbl)	Condensate (CDN$/bbl)	Gas (CDN$/MMBtu) 3.36 3.21 3.28 3.45 3.61 3.87 3.99 4.11 4.23 4.36 4.48 4.61	Ethane (CDN$/bbl)	Propane (CDN$/bbl)	Butane (CDN$/bbl)
				10.14 10.46 10.64 10.89 11.71 12.53 13.18 13.44 13.71 13.99 14.27 14.55	23.65 24.41 24.83 25.41 27.33 29.24 30.75 31.37 31.99 32.63 33.29 33.95	45.28 48.83 49.66 50.82 54.66 58.48 61.50 62.73 63.99 65.27 66.57 67.90

Other Revenue

CQ Energy has represented that it owns interests in processing plants that process third-party gas for which it receives revenue. Future revenue attributable to CQ Energy’s interest in the processing plants was estimated based on lease operating statements provided by CQ Energy. CQ Energy has also represented that it receives revenue from the sale of

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sulphur produced as a by-product of certain of CQ Energy’s gas volumes.

Operating Expenses and Capital Costs

Operating expenses and capital costs, provided by CQ Energy and based on current expenses, were escalated annually at 2 percent beginning in 2018. The table below summarizes the 2017 gross operating expenses for the 15 major fields in Canadian dollars per well per month (CDN$/well/month), thousands of Canadian dollars per year (M CDN$/year), Canadian dollars per thousand cubic feet (CDN$/Mcf), and Canadian dollars per barrel (CDN$/bbl):

	2017 Gross Operating Expenses – Selected Fields	2017 Gross Operating Expenses – Selected Fields	2017 Gross Operating Expenses – Selected Fields
Field	Fixed Well (CDN$/well/month)	Fixed Field (M CDN$/year)	Gas Variable (CDN$/Mcf) Oil Variable (CDN$/bbl)
Alderson Benjamin Burnt Timber Carrot Creek Ferrier Gilby Glacier Hanlan Unit Laprise Group MHCU1 Panther Stolberg Unit Turner Valley Voyager Wildcat Hills Unit	282 2,503 7,632 1,695 3,180 1,791 3,019 28,813 4,198 204 1,648 5,362 1,598 8,649 4,007	1,290 2,114 2,274 1,753 10,339 3,138 3,373 4,517 2,396 1,778 4,916 1,682 4,420 1,971 2,110	0.19 0 0.30 0 1.89 0 0.60 10.05 0.95 5.01 0.39 5.84 0.59 18.67 0.32 0 1.05 0 0.13 0 0.75 0 0.04 0 0.23 0 0.16 0 0.04 0

Abandonment and Reclamation Costs

Abandonment and reclamation costs were estimated for each property based on data provided by CQ Energy. These costs were projected to occur 5 years after the last year of economic production of each property with estimated remaining reserves. For properties for which remaining reserves were estimated to be zero, abandonment occurs 2 years from the effective date of this report. The well abandonment and reclamation liability does not include credit for any salvage value. Facility and pipeline abandonment and reclamation costs have not been

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included in this report. Abandonment and reclamation costs were escalated annually at 2 percent beginning in 2018.

Royalties

All properties evaluated herein are in Canada and are subject to various applicable Canadian royalties. A detailed discussion on these royalty regimes is included in the appendix to this report.

Income Taxes

Future income taxes have not been taken into account in the preparation of these estimates.

The estimated future revenue, costs, and net present value of the future net revenue at various discount rates to be derived from the production and sale of the net proved and proved-plus-probable reserves of the properties evaluated, as of March 31, 2017, for the Forecast Price Case described herein are summarized as follows, expressed in millions of Canadian dollars (MM CDN$):

Future Gross Revenue Other Revenue Royalty Operating Expenses Capital Costs Abandonment and Reclamation Costs Future Net Revenue Net Present Value at 5 Percent Net Present Value at 8 Percent Net Present Value at 10 Percent Net Present Value at 12 Percent Net Present Value at 15 Percent		Forecast Price Case	Forecast Price Case	Forecast Price Case
	Proved Developed Producing (MM CDN$)	Proved Developed Non-Producing (MM CDN$)	Proved Undeveloped (MM CDN$)	Total Proved (MM CDN$)	Proved Plus Probable (MM CDN$)
	4,622 217 424 1,932 0 619 1,865 1,314 1,114 1,012 928 826	567 4 68 228 33 10 232 169 143 130 119 105	1,916 0 143 436 629 41 667 323 204 144 96 42	7,106 221 635 2,596 662 670 2,764 1,806 1,461 1,286 1,143 973	11,259 217 1,093 3,667 1,054 752 4,910 2,807 2,147 1,833 1,585 1,301

Notes:

Values for probable reserves are presented as required by the Canadian National Instrument 51-101 and are not equivalent to values for proved reserves.
Future Canadian income tax expenses were not taken into account in the preparation of these estimates.

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Sensitivities

In addition to the Forecast Price Case, eight sensitivity cases were evaluated for this report. The following assumptions were used for each case:

Oil Premium of 15 Percent Case

For the Oil Premium of 15 Percent Case, the oil forecast prices used in the Forecast Price Case were increased by 15 percent. All other assumptions were the same as those used in the Forecast Price Case.

Oil Discount of 15 Percent Case

For the Oil Discount of 15 Percent Case, the oil forecast prices used in the Forecast Price Case were decreased by 15 percent. All other assumptions were the same as those used in the Forecast Price Case.

Gas Premium of 15 Percent Case

For the Gas Premium of 15 Percent Case, the gas forecast prices used in the Forecast Price Case were increased by 15 percent. All other assumptions were the same as those used in the Forecast Price Case.

Gas Discount of 15 Percent Case

For the Gas Discount of 15 Percent Case, the gas forecast prices used in the Forecast Price Case were decreased by 15 percent. All other assumptions were the same as those used in the Forecast Price Case.

OPEX +10% Case

For the OPEX +10% Case, operating expenses were increased 10 percent from those used in the Forecast Price Case. All other assumptions were the same as those used in the Forecast Price Case.

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OPEX -10% Case

For the OPEX -10% Case, operating expenses were decreased 10 percent from those used in the Forecast Price Case. All other assumptions were the same as those used in the Forecast Price Case.

CAPEX +10% Case

For the CAPEX +10% Case, capital costs were increased 10 percent from those used in the Forecast Price Case. All other assumptions were the same as those used in the Forecast Price Case.

CAPEX -10% Case

For the CAPEX -10% Case, capital costs were decreased 10 percent from those used in the Forecast Price Case. All other assumptions were the same as those used in the Forecast Price Case.

The estimated net present value of the future net revenue at a discount rate of 10 percent to be derived from the production and sale of the net proved and proved-plus-probable reserves of the properties evaluated for each of the sensitivity cases described herein, as of March 31, 2017, are summarized as follows, expressed in millions of Canadian dollars (MM CDN$):

Oil Premium of 15 Percent Oil Discount of 15 Percent Gas Premium of 15 Percent Gas Discount of 15 Percent OPEX +10% OPEX -10% CAPEX +10% CAPEX -10%	Net Present Value at 10 Percent	Net Present Value at 10 Percent
	Total Proved (MM CDN$) 1,354 1,220 1,621 953 1,182 1,388 1,221 1,349	Proved Plus Probable (MM CDN$)
		1,921 1,745 2,297 1,374 1,704 1,961 1,740 1,929

Notes:

Values for probable reserves are presented as required by the Canadian National Instrument 51-101 and are not equivalent to values for proved reserves.
Future Canadian income tax expenses were not taken into account in the preparation of these estimates.

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APPENDIX V COMPETENT PERSON’S REPORT AND VALUATION REPORT

DeGolyer and MacNaughton

Low Case

The Low Case combines the future price and cost assumptions of the Oil Discount of 15 Percent Case, the OPEX +10% Case, and the CAPEX +10% Case. All other assumptions are the same as the Forecast Price Case.

High Case

The High Case combines the future price and cost assumptions of the Oil Premium of 15 Percent Case, the OPEX -10% Case, and the CAPEX -10% Case. All other assumptions are the same as the Forecast Price Case.

The estimated net present value of the future net revenue at various discount rates to be derived from the production and sale of the net proved-plus-probable reserves for the Low Case and the High Case, as of March 31, 2017, are summarized as follows, expressed in millions of Canadian dollars (MM CDN$):

Net Present Value of Proved-Plus-Probable Reserves

Low Case High Case	Net Present Value at 5 Percent (MM CDN$) 2,382 3,241	Net Present Value at 8 Percent (MM CDN$) Net Present Value at 10 Percent (MM CDN$) Net Present Value at 12 Percent (MM CDN$) Net Present Value at 15 Percent (MM CDN$)
		1,803 1,527 1,309 1,059 2,500 2,148 1,870 1,551

Notes:

Values for probable reserves are presented as required by the Canadian National Instrument 51-101 and are not equivalent to values for proved reserves.
Future Canadian income tax expenses were not taken into account in the preparation of these estimates.

Summary and Conclusions

CQ Energy has represented that it owns interests in 134 fields in Alberta, British Columbia, and Saskatchewan, Canada. In this report, 78 of the 134 fields have been evaluated, and the remaining 56, which represent less than 5 percent of CQ Energy’s net present value, were evaluated by CQ Energy. The estimated net proved and probable reserves of the properties evaluated, as of March 31, 2017, for the Forecast Price Case described herein are summarized as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe):

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COMPETENT PERSON’S REPORT AND VALUATION REPORT

APPENDIX V

DeGolyer and MacNaughton

	Net Reserves	Net Reserves
Oil and Condensate (Mbbl)	NGL (Mbbl)	Sales Gas (MMcf)	Oil Equivalent (Mboe)
11,214 672 4,575	3,073 138 722	689,856 95,442 290,909	129,263 16,717 53,782
16,461 7,170 23,631	3,933 1,669 5,602	1,076,207 543,407 1,619,614	199,762 99,407 299,169

Notes:

Probable reserves are presented as required by the Canadian National Instrument 51-101 and are not equivalent to proved reserves.
The proved-plus-probable volumes are an arithmetic sum of multiple estimates of reserves, which statistical principles indicate may be misleading as to volumes that may actually be recovered. Attention should be given to the estimates of individual classes of reserves and the probability of recovery, as explained under the Definition of Reserves heading of this report.
All of the oil volumes estimated in this report are light or medium oil.
Gas is converted to oil equivalent using a factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.

Future Net Revenue Net Present Value at 5 Percent Net Present Value at 8 Percent Net Present Value at 10 Percent Net Present Value at 12 Percent Net Present Value at 15 Percent		Forecast Price Case	Forecast Price Case	Forecast Price Case
	Proved Developed Producing (MM CDN$) 1,865 1,314 1,114 1,012 928 826	Proved Developed Non-Producing (MM CDN$) 232 169 143 130 119 105	Proved Undeveloped (MM CDN$) 667 323 204 144 96 42	Total Proved (MM CDN$) 2,764 1,806 1,461 1,286 1,143 973	Proved Plus Probable (MM CDN$)
					4,910 2,807 2,147 1,833 1,585 1,301

Notes:

Values for probable reserves are presented as required by the Canadian National Instrument 51-101 and are not equivalent to values for proved reserves.
Future Canadian income tax expenses were not taken into account in the preparation of these estimates.

– V﹣41 –

APPENDIX V COMPETENT PERSON’S REPORT AND VALUATION REPORT

==> picture [533 x 688] intentionally omitted <==

– V﹣42 –

APPENDIX V COMPETENT PERSON’S REPORT AND VALUATION REPORT

==> picture [533 x 688] intentionally omitted <==

– V﹣43 –

COMPETENT PERSON’S REPORT AND VALUATION REPORT

APPENDIX V

DeGolyer and MacNaughton

Page Executive Summary .............................................................................................. 2 Introduction ........................................................................................................... 5 Definition of Reserves .......................................................................................... 6 Field Discussions ................................................................................................... 8 Reservoir Geology .................................................................................................. 9 Production Performance ........................................................................................ 9 Facilities Infrastructure ...................................................................................... 11 Alberta .................................................................................................................. 11 Alderson Field ................................................................................................... 11 Milk River Formation .................................................................................... 11 Medicine Hat Formation ............................................................................... 11 Reserves and Production Forecast ................................................................ 11 Benjamin Field ................................................................................................. 12 Mount Head Formation ................................................................................. 12 Turner Valley Formation .............................................................................. 12 Reserves and Production Forecast ................................................................ 12 Burnt Timber Field .......................................................................................... 13 Rundle Group ................................................................................................ 13 Wabamun Formation .................................................................................... 13 Reserves and Production Forecast ................................................................ 13 Carrot Creek Field ............................................................................................ 14 Cardium Formation ....................................................................................... 14 Viking Formation .......................................................................................... 14 Notikewin Formation .................................................................................... 14 Gething Formation ........................................................................................ 14 Rock Creek Formation .................................................................................. 15 Reserves and Production Forecast ................................................................ 15 Ferrier Field ..................................................................................................... 16 Belly River Formation ................................................................................... 16 Cardium Formation ....................................................................................... 16 Viking Formation .......................................................................................... 16 Mannville Group ........................................................................................... 16 Rock Creek Formation .................................................................................. 17 Reserves and Production Forecast ................................................................ 17 Gilby Field ........................................................................................................ 17 Glauconitic Formation................................................................................... 18 Reserves and Production Forecast ................................................................ 18 Glacier Field ..................................................................................................... 19 Montney Formation ....................................................................................... 19 Reserves and Production Forecast ................................................................ 19 Hanlan Unit Field ............................................................................................ 20

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COMPETENT PERSON’S REPORT AND VALUATION REPORT

APPENDIX V

DeGolyer and MacNaughton

TABLE of CONTENTS – ( Continued )

Page Beaverhill Lake Formation ........................................................................... 20 Reserves and Production Forecast ................................................................ 21 MHCU1 Field ................................................................................................... 21 Milk River Formation .................................................................................... 21 Medicine Hat Formation ............................................................................... 22 Reserves and Production Forecast ................................................................ 22 Panther Field .................................................................................................... 22 Mount Head Formation ................................................................................. 22 Turner Valley Formation .............................................................................. 23 Reserves and Production Forecast ................................................................ 23 Stolberg Unit Field ........................................................................................... 23 Rundle Group ................................................................................................ 23 Reserves and Production Forecast ................................................................ 24 Turner Valley Field .......................................................................................... 24 Viking Formation .......................................................................................... 24 Reserves and Production Forecast ................................................................ 25 Voyager Field .................................................................................................... 25 Wilrich Formation ......................................................................................... 25 Rundle Group ................................................................................................ 25 Reserves and Production Forecast ................................................................ 25 Wildcat Hills Unit Field ................................................................................... 26 Reserves and Production Forecast ................................................................ 26 British Columbia .................................................................................................. 27 Laprise Group Field ......................................................................................... 27 Reserves and Production Forecast ................................................................... 27 Laprise Creek ................................................................................................ 27 Laprise East .................................................................................................. 27 Laprise Main ................................................................................................. 28 Estimation of Reserves ....................................................................................... 28 Risk Factors ......................................................................................................... 31 Valuation of Reserves ......................................................................................... 32 Sensitivities .......................................................................................................... 36 Oil Premium of 15 Percent Case .......................................................................... 36 Oil Discount of 15 Percent Case .......................................................................... 36 Gas Premium of 15 Percent Case ........................................................................ 36 Gas Discount of 15 Percent Case ......................................................................... 36 OPEX +10% Case ................................................................................................. 36 OPEX -10% Case .................................................................................................. 37 CAPEX +10% Case ............................................................................................... 37 CAPEX -10% Case................................................................................................ 37 Low Case .............................................................................................................. 38 High Case ............................................................................................................. 38 Summary and Conclusions ................................................................................ 38 Professional Qualifications .................................................................................. 40 Certificate of Qualification

– V﹣45 –

COMPETENT PERSON’S REPORT AND VALUATION REPORT

APPENDIX V

DeGolyer and MacNaughton

TABLE of CONTENTS – ( Continued )

Tables

Table 1 – Projections of Estimated Annual Production and Revenue, Proved Developed Producing Reserves Table 2 – Projections of Estimated Annual Production and Revenue, Proved Developed Non-Producing Reserves Table 3 – Projections of Estimated Annual Production and Revenue, Proved Undeveloped Reserves Table 4 – Projections of Estimated Annual Production and Revenue, Total Proved Reserves Table 5 – Projections of Estimated Annual Production and Revenue, Proved-plus-Probable Reserves

Appendix

– V﹣46 –

COMPETENT PERSON’S REPORT AND VALUATION REPORT

APPENDIX V

TABLE 1 PROJECTIONS of ESTIMATED ANNUAL PRODUCTION and REVENUE from PROVED DEVELOPED PRODUCING RESERVES as of MARCH 31, 2017 of the

==> picture [56 x 44] intentionally omitted <==

ALBERTA, BRITISH COLUMBIA, and SASKATCHEWAN PROPERTIES owned by CQ ENERGY CANADA RESOURCES PARTNERSHIP

FORECAST PRICE CASE

Year	Gross Pro	duction	Company Gross	Production		Net Productio	n		Average Prices
	Oil and Cond (Mbbl)	Gas (MMcf)	Oil and Cond (Mbbl)	Gas (MMcf)	Oil and Cond (Mbbl)	NGL (Mbbl)	Sales Gas (MMcf)	Oil and Cond (CDN$/bbl)	NGL (CDN$/bbl)	Gas (CDN$/Mcf)
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Sub Rem Total	4,626 5,463 4,886 4,437 4,049 3,730 3,451 3,211 2,963 2,769 2,598 2,437 2,268 2,123 1,984 50,994 30,314 81,308	108,867 126,086 110,250 97,351 86,257 76,805 67,762 60,571 54,160 48,402 43,561 39,124 34,782 30,941 27,595 1,012,514 189,527 1,202,041	897 1,026 895 797 713 645 585 536 487 444 408 374 343 316 289 8,755 3,833 12,588	69,199 80,956 71,244 63,234 56,289 50,267 44,421 39,788 35,631 31,859 28,643 25,733 22,751 20,079 17,777 657,871 121,745 779,616	821 924 810 717 635 571 518 472 431 391 378 345 316 289 266 7,884 3,330 11,214	288 328 277 238 207 184 164 146 129 114 120 108 95 83 72 2,553 520 3,073	60,574 71,278 62,837 55,745 49,716 44,407 39,348 35,341 31,730 28,443 25,479 22,859 20,181 17,775 15,747 581,460 108,396 689,856	65.55 67.54 68.72 70.39 75.60 80.93 85.13 86.94 88.50 90.54 92.16 94.12 95.92 98.10 100.00	20.18 21.76 22.03 22.52 24.61 26.64 28.25 28.77 29.64 30.10 30.77 31.13 32.48 32.53 33.70	3.24 3.09 3.16 3.32 3.48 3.73 3.85 3.96 4.08 4.21 4.33 4.46 4.55 4.64 4.75

Year	Future Company Gross Revenue (MM CDN$)	Other Revenue (MM CDN$)	Royalty (MM CDN$)	Revenue After Royalty (MM CDN$)		Expenditures	Expenditures	Before	Income Tax
					Operating Expenses (MM CDN$)	Capital Costs (MM CDN$)	Abandonment & Reclamation Costs (MM CDN$)	Future Net Revenue (MM CDN$)	Net Present Value 10 Percent (MM CDN$)
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Sub Rem Total	306 347 310 287 269 258 237 219 202 187 173 161 146 133 121	23 26 23 20 17 15 13 11 10 8 7 6 6 5 4	25 29 25 24 23 23 22 20 18 17 14 13 12 11 10	281 318 285 263 246 234 216 199 184 170 160 148 134 122 111	139 164 149 136 125 114 103 94 87 79 73 67 61 54 49	0 0 0 0 0 0 0 0 0 0 0 0 0 0 0	0 1 46 2 0 36 6 19 6 6 12 30 6 8 11	165 179 113 145 138 99 119 97 100 92 81 56 73 64 56	159 160 90 107 92 60 66 48 46 38 30 19 23 18 14
	3,357 1,265 4,622	194 23 217	288 136 424	3,070 1,129 4,199	1,496 436 1,932	0 0 0	191 428 619	1,577 288 1,865	971 41 1,012

Net Present Value (MM CDN$) at	Net Present Value (MM CDN$) at
5 Percent 8 Percent 12 Percent 15 Percent	Before Income Taxes 1,314 1,114 928 826

These data accompany the report of DeGolyer and MacNaughton and are subject to its specific conditions.

– V﹣47 –

COMPETENT PERSON’S REPORT AND VALUATION REPORT

APPENDIX V

TABLE 2

PROJECTIONS of ESTIMATED ANNUAL PRODUCTION and REVENUE from PROVED DEVELOPED NON-PRODUCING RESERVES as of

==> picture [56 x 44] intentionally omitted <==

MARCH 31, 2017

of the

ALBERTA, BRITISH COLUMBIA, and SASKATCHEWAN PROPERTIES owned by CQ ENERGY CANADA RESOURCES PARTNERSHIP

FORECAST PRICE CASE

Year	Gross Pro	duction	Company Gross	Production		Net Producti	on		Average Prices
	Oil and Cond (Mbbl)	Gas (MMcf)	Oil and Cond (Mbbl)	Gas (MMcf)	Oil and Cond (Mbbl)	NGL (Mbbl)	Sales Gas (MMcf)	Oil and Cond (CDN$/bbl)	NGL (CDN$/bbl)	Gas (CDN$/Mcf)
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Sub Rem Total	134 178 133 93 71 58 48 42 36 31 26 24 19 16 14 923 90 1,013	7,085 12,759 18,557 16,124 12,758 10,644 8,792 7,354 6,277 5,389 4,459 3,179 2,354 2,053 1,847 119,631 11,404 131,035	119 152 113 78 58 47 40 34 29 26 22 19 16 14 13 782 74 856	5,707 9,659 15,173 13,320 10,678 8,949 7,385 6,230 5,329 4,583 3,774 2,736 2,025 1,790 1,616 98,954 10,301 109,255	95 120 89 60 47 36 30 26 23 20 18 15 14 11 9 613 59 672	11 15 18 15 14 11 8 7 5 6 4 2 2 3 3 124 14 138	4,976 8,488 13,312 11,604 9,317 7,759 6,392 5,395 4,630 3,999 3,290 2,392 1,781 1,572 1,418 86,325 9,117 95,442	63.98 66.97 67.79 67.06 74.07 79.36 84.01 84.21 88.89 85.82 93.46 88.46 94.77 91.66 91.36	20.18 21.76 22.03 22.52 24.61 26.64 28.25 28.77 29.64 30.10 30.77 31.13 32.48 32.53 33.70	3.35 3.19 3.01 3.18 3.35 3.64 3.79 3.94 4.09 4.24 4.43 4.74 5.06 5.16 5.24

Year	Future Company Gross Revenue (MM CDN$)	Other Revenue (MM CDN$)	Royalty (MM CDN$)	Revenue After Royalty (MM CDN$)		Expenditures	Expenditures	Before	Income Tax
					Operating Expenses (MM CDN$)	Capital Costs (MM CDN$)	Abandonment & Reclamation Costs (MM CDN$)	Future Net Revenue (MM CDN$)	Net Present Value 10 Percent (MM CDN$)
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Sub Rem Total	30 47 61 55 46 42 36 31 28 25 22 17 14 13 11	0 0 1 1 0 0 0 0 0 0 0 0 0 0 0	4 6 7 6 5 5 4 4 3 3 3 2 2 2 1	26 41 54 48 41 37 31 28 25 22 19 15 12 11 10	8 13 25 22 19 16 14 12 11 10 9 7 5 4 4	9 9 9 5 1 0 0 0 0 0 0 0 0 0 0	0 0 0 0 0 (0) (0) (0) (0) 0 1 1 0 0 1	9 20 21 22 21 20 18 16 14 12 10 8 7 6 5	8 17 17 16 14 12 10 8 6 5 4 3 2 2 1
	477 90 567	3 1 4	58 10 68	419 80 499	180 48 228	33 0 33	2 8 10	207 25 232	126 4 130

Net Present Value (MM CDN$) at	Net Present Value (MM CDN$) at
5 Percent 8 Percent 12 Percent 15 Percent	Before Income Taxes
	169 143 119 105

These data accompany the report of DeGolyer and MacNaughton and are subject to its specific conditions.

– V﹣48 –

COMPETENT PERSON’S REPORT AND VALUATION REPORT

APPENDIX V

TABLE 3

PROJECTIONS of ESTIMATED ANNUAL PRODUCTION and REVENUE from PROVED UNDEVELOPED RESERVES as of

==> picture [56 x 43] intentionally omitted <==

MARCH 31, 2017

of the

ALBERTA, BRITISH COLUMBIA, and SASKATCHEWAN PROPERTIES owned by

CQ ENERGY CANADA RESOURCES PARTNERSHIP

FORECAST PRICE CASE

Year	Gross Pro	duction	Company Gross	Production		Net Producti	on		Average Prices
	Oil and Cond (Mbbl)	Gas (MMcf)	Oil and Cond (Mbbl)	Gas (MMcf)	Oil and Cond (Mbbl)	NGL (Mbbl)	Sales Gas (MMcf)	Oil and Cond (CDN$/bbl)	NGL (CDN$/bbl)	Gas (CDN$/Mcf)
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Sub Rem Total	136 456 550 737 692 572 412 333 282 242 211 186 164 146 130 5,249 1,612 6,861	581 10,408 24,548 57,155 62,266 50,222 39,217 33,449 30,632 25,049 21,235 18,366 15,420 13,400 11,830 413,778 78,312 492,090	137 449 510 621 573 479 344 277 233 200 174 154 137 122 108 4,516 806 5,322	560 7,911 16,200 40,497 40,237 31,899 25,119 21,086 18,303 15,271 13,061 11,354 9,604 8,391 7,434 266,929 49,799 316,728	121 411 451 555 506 399 273 222 189 164 144 128 113 103 92 3,871 704 4,575	10 84 95 87 71 53 41 32 28 23 22 19 17 15 14 611 111 722	530 7,480 15,201 37,921 37,998 29,650 22,911 18,985 15,589 13,566 11,650 10,109 8,611 7,588 6,779 244,568 46,341 290,909	63.98 66.97 67.79 67.06 74.07 79.36 84.01 84.21 88.89 85.82 93.46 88.46 94.77 91.66 91.36	20.18 21.76 22.03 22.52 24.61 26.64 28.25 28.77 29.64 30.10 30.77 31.13 32.48 32.53 33.70	3.35 3.19 3.01 3.18 3.35 3.64 3.79 3.94 4.09 4.24 4.43 4.74 5.06 5.16 5.24

Year	Future Company Gross Revenue (MM CDN$)	Other Revenue (MM CDN$)	Royalty (MM CDN$)	Revenue After Royalty (MM CDN$)		Expenditures	Expenditures	Before	Income Tax
					Operating Expenses (MM CDN$)	Capital Costs (MM CDN$)	Abandonment & Reclamation Costs (MM CDN$)	Future Net Revenue (MM CDN$)	Net Present Value 10 Percent (MM CDN$)
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Sub Rem Total	12 61 94 195 202 173 138 118 104 90 80 71 62 56 50	0 0 0 0 0 0 0 0 0 0 0 0 0 0 0	1 3 5 9 10 12 12 11 9 8 7 7 6 5 4	10 58 88 186 192 161 126 107 95 82 72 64 56 51 46	1 8 15 35 38 33 27 23 21 19 18 17 15 14 14	59 214 179 117 41 7 5 7 0 0 0 0 0 0 0	0 0 0 0 0 (0) 0 0 (0) 0 (5) 0 5 0 0	(50) (165) (106) 35 114 121 95 77 74 63 59 48 36 36 32	(48) (146) (87) 24 76 74 53 39 34 26 22 16 11 10 8
	1,505 411 1,916	0 0 0	110 33 144	1,396 378 1,773	297 140 436	629 0 629	0 41 41	470 196 667	113 31 144

Net Present Value (MM CDN$) at	Net Present Value (MM CDN$) at
5 Percent 8 Percent 12 Percent 15 Percent	Before Income Taxes
	323 204 96 42

These data accompany the report of DeGolyer and MacNaughton and are subject to its specific conditions.

– V﹣49 –

COMPETENT PERSON’S REPORT AND VALUATION REPORT

APPENDIX V

TABLE 4

PROJECTIONS of ESTIMATED ANNUAL PRODUCTION and REVENUE from TOTAL PROVED RESERVES as of MARCH 31, 2017 of the ALBERTA, BRITISH COLUMBIA, and SASKATCHEWAN PROPERTIES owned by CQ ENERGY CANADA RESOURCES PARTNERSHIP

==> picture [56 x 44] intentionally omitted <==

FORECAST PRICE CASE

Year	Gross Pro	duction	Company Gross	Production		Net Productio	n		Average Prices
	Oil and Cond (Mbbl)	Gas (MMcf)	Oil and Cond (Mbbl)	Gas (MMcf)	Oil and Cond (Mbbl)	NGL (Mbbl)	Sales Gas (MMcf)	Oil and Cond (CDN$/bbl)	NGL (CDN$/bbl)	Gas (CDN$/Mcf)
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Sub Rem Total	4,896 6,097 5,569 5,267 4,812 4,360 3,911 3,586 3,281 3,042 2,835 2,647 2,451 2,285 2,128 57,167 31,329 88,496	116,533 149,253 153,355 170,630 161,281 137,671 115,771 101,374 91,069 78,840 69,255 60,669 52,556 46,394 41,272 1,545,923 279,243 1,825,166	1,153 1,627 1,518 1,496 1,344 1,171 969 847 749 670 604 547 496 452 410 14,053 4,713 18,766	75,466 98,526 102,618 117,051 107,204 91,115 76,926 67,104 59,263 51,713 45,478 39,823 34,380 30,259 26,827 1,023,754 181,845 1,205,599	1,037 1,455 1,350 1,332 1,188 1,006 821 720 643 575 540 488 443 403 367 12,368 4,093 16,461	309 427 390 340 292 248 213 185 162 143 146 129 114 101 89 3,288 645 3,933	66,080 87,246 91,350 105,270 97,031 81,816 68,651 59,721 51,949 46,008 40,419 35,360 30,573 26,935 23,944 912,353 163,854 1,076,207	65.75 68.05 69.37 70.42 75.84 81.21 85.36 87.04 88.80 90.48 92.31 93.98 95.68 97.67 99.72	20.01 21.22 21.63 22.27 24.36 26.56 27.87 28.34 28.88 29.63 30.25 31.38 32.42 33.14 33.57	3.25 3.12 3.16 3.41 3.58 3.82 3.94 4.06 4.17 4.30 4.43 4.58 4.69 4.79 4.89

Year	Future Company Gross Revenue (MM CDN$)	Other Revenue (MM CDN$)	Royalty (MM CDN$)	Revenue After Royalty (MM CDN$)		Expenditures	Expenditures	Before	Income Tax
					Operating Expenses (MM CDN$)	Capital Costs (MM CDN$)	Abandonment & Reclamation Costs (MM CDN$)	Future Net Revenue (MM CDN$)	Net Present Value 10 Percent (MM CDN$)
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Sub Rem Total	347 454 465 537 517 472 411 369 335 302 274 249 222 201 183	23 27 24 20 18 15 13 11 10 8 7 6 6 5 4	30 38 37 40 39 40 38 35 31 28 24 22 20 18 16	317 416 427 498 479 432 373 334 304 274 251 227 203 183 167	148 185 189 193 181 163 144 130 119 109 100 91 81 73 67	68 223 188 122 42 7 5 7 0 0 0 0 0 0 0	0 1 46 2 0 36 6 19 6 7 8 31 12 9 11	124 34 28 202 273 241 232 190 189 167 150 112 115 106 93	120 31 21 147 182 146 128 95 86 69 57 38 36 30 24
	5,340 1,766 7,106	198 23 221	455 180 635	4,885 1,587 6,471	1,972 624 2,596	662 0 662	192 478 670	2,255 509 2,764	1,210 76 1,286

Net Present Value (MM CDN$) at	Net Present Value (MM CDN$) at
5 Percent 8 Percent 12 Percent 15 Percent	Before Income Taxes
	1,806 1,461 1,143 973

These data accompany the report of DeGolyer and MacNaughton and are subject to its specific conditions.

– V﹣50 –

COMPETENT PERSON’S REPORT AND VALUATION REPORT

APPENDIX V

TABLE 5 PROJECTIONS of ESTIMATED ANNUAL PRODUCTION and REVENUE from PROVED-PLUS-PROBABLE RESERVES as of MARCH 31, 2017 of the

==> picture [56 x 44] intentionally omitted <==

ALBERTA, BRITISH COLUMBIA, and SASKATCHEWAN PROPERTIES owned by

CQ ENERGY CANADA RESOURCES PARTNERSHIP

FORECAST PRICE CASE

Year	Gross Pro	duction	Company Gross	Production		Net Productio	n		Average Prices
	Oil and Cond (Mbbl)	Gas (MMcf)	Oil and Cond (Mbbl)	Gas (MMcf)	Oil and Cond (Mbbl)	NGL (Mbbl)	Sales Gas (MMcf)	Oil and Cond (CDN$/bbl)	NGL (CDN$/bbl)	Gas (CDN$/Mcf)
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Sub Rem Total	5,139 6,745 6,249 6,211 5,830 5,204 4,668 4,282 3,949 3,664 3,411 3,210 3,014 2,839 2,678 67,093 42,045 109,138	123,028 162,616 177,285 211,321 221,850 192,724 164,887 147,646 132,707 117,138 103,687 93,625 84,294 76,428 68,985 2,078,221 666,522 2,744,743	1,254 1,937 1,868 2,025 1,887 1,605 1,345 1,186 1,059 958 874 804 739 684 634 18,859 8,645 27,504	79,628 107,342 119,034 146,380 147,658 129,743 111,479 99,224 88,062 77,994 69,027 62,337 56,034 50,673 45,694 1,390,309 432,494 1,822,803	1,118 1,730 1,645 1,793 1,664 1,360 1,116 987 887 802 764 701 643 592 549 16,351 7,280 23,631	329 481 467 426 374 318 275 247 222 200 207 189 171 155 141 4,202 1,400 5,602	69,640 94,962 106,203 132,352 134,501 116,496 98,928 87,786 77,666 68,796 61,051 55,018 49,407 44,644 40,264 1,237,714 381,900 1,619,614	65.75 68.05 69.37 70.42 75.84 81.21 85.36 87.04 88.80 90.48 92.31 93.98 95.68 97.67 99.72	20.01 21.22 21.63 22.27 24.36 26.56 27.87 28.34 28.88 29.63 30.25 31.38 32.42 33.14 33.57	3.25 3.12 3.16 3.41 3.58 3.82 3.94 4.06 4.17 4.30 4.43 4.58 4.69 4.79 4.89

Year	Future Company Gross Revenue (MM CDN$)	Other Revenue (MM CDN$)	Royalty (MM CDN$)	Revenue After Royalty (MM CDN$)		Expenditures	Expenditures	Before	Income Tax
					Operating Expenses (MM CDN$)	Capital Costs (MM CDN$)	Abandonment & Reclamation Costs (MM CDN$)	Future Net Revenue (MM CDN$)	Net Present Value 10 Percent (MM CDN$)
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 Sub Rem Total	367 504 545 682 713 663 587 536 489 448 410 382 352 327 303	22 26 23 20 17 15 13 11 10 8 7 6 5 5 4	33 42 44 51 53 57 57 53 49 45 38 36 34 32 30	335 462 501 631 660 606 530 483 441 403 372 346 319 295 273	151 193 202 212 211 200 181 165 152 140 128 120 112 105 98	82 258 359 236 91 7 12 7 0 0 0 0 0 0 0	0 1 45 1 0 33 5 17 6 5 4 6 5 9 33	124 36 (82) 201 376 380 346 305 292 266 248 227 207 185 147	120 32 (69) 144 250 231 191 153 133 110 93 78 64 52 38
	7,310 3,949 11,259	192 25 217	653 440 1,093	6,657 3,509 10,166	2,370 1,297 3,667	1,054 0 1,054	168 584 752	3,257 1,653 4,910	1,621 212 1,833

Net Present Value (MM CDN$) at	Net Present Value (MM CDN$) at
5 Percent 8 Percent 12 Percent 15 Percent	Before Income Taxes 2,807 2,147 1,585 1,301

These data accompany the report of DeGolyer and MacNaughton and are subject to its specific conditions.

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COMPETENT PERSON’S REPORT AND VALUATION REPORT

APPENDIX V

ALBERTA ROYALTIES

In January 2016 the Alberta government announced that it would be implementing a revised royalty regime called” Modernized Royalty Framework” (MRF). The MRF will take effect on January 01, 2017.

The MRF will apply to crude oil, liquid and natural gas wells spud on or after January 1, 2017, and to non-project crude bitumen wells spud on or after January 1, 2017 (since royalties for these wells are calculated based on crown royalty volume determined under crude oil formulas). It will also apply to wells spud between July 13, 2016 and December 31, 2016 which are approved for early opt into MRF. The wells spud before July 13, 2016, and the wells spud during the early election period (July 13, 2016 to December 31, 2016) that did not elect to opt in early to the MRF, or did not meet the criteria will continue to operate under the previous royalty framework (ARF) until December 31, 2026. The MRF will not impact royalties on production from an approved Oil Sands Royalty Project, under the Oil Sands Royalty Regulation, 2009 .

Under the MRF, the flat royalty rate of 5% will be applied until the cumulative revenue from all hydrocarbon products generated by a well equals C. The C is expressed as a dollar amount, and is known as the drilling and completion cost allowance, and represents completed well costs. It is a calculated value based on vertical depth (TVD), lateral length (TLL) and the amount of proppant placed (TPP). The calculation of C* is the same for all wells, regardless of what hydrocarbon the well produces. Cumulative revenue from a well will be tracked by multiplying production volumes of the various hydrocarbons by their respective commodity par prices, as published by Alberta Energy.

Once the revenue from all hydrocarbon products generated by a well equals C*, the royalty rate will be calculated based on the MRF which are price sensitive and product specific. The actual royalty rate is the sum of a price component (PC) and a quantity adjustment component (QC). The PC is a function of the Par Prices determined by Alberta Energy for the various hydrocarbon streams and is independent of production rate. This PC is capped at 40 percent for crude oil, pentane plus, condensate, bitumen from non-project wells, natural gas (methane) and ethane, while propane, and butane are capped at 36 percent. The QC will apply when monthly production from the well is below the maturity threshold. The maturity threshold for oil equivalent is 194 cubic metres (m3) per month (40 barrels of oil equivalent per day), while for gas it is 345.5 thousand cubic metres (e3m3) per month (9.7 thousand cubic feet (mcf) per month). The equivalent value is the sum of all products from a well, and not individual

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APPENDIX V COMPETENT PERSON’S REPORT AND VALUATION REPORT

streams. The conversion ratio between m3 liquids to e3m3 of gas is 1.7811. If cumulative production is below this point, the quantity adjustment specified in the formulas reduces the royalty rate charged to a well, down to a minimum rate of five percent.

Under the MRF, wells re-entered on or after January 1, 2017 will be subject to the new royalty. In general, re-entered wells will receive an incremental drilling and completion cost allowance (C). The incremental C is calculated as a proxy for a well’s re-entry costs. The incremental activity will be awarded an incremental C, which will be added to any remaining C balance and applied to the production from all the legs from the re-entered date forward. The remaining C balance may equal zero if the well’s cumulative revenue had exceeded its C prior to re-entry or if the well was spud prior to January 1, 2017.

All wells spud prior to January 1, 2017 (not including the wells which are approved for early opt in to MRF) on Crown land, will pay royalties calculated using the ARF until December 31, 2026.

The complete ARF and the MRF can be found at http://www.energy.gov.ab.ca/About_Us/Royalty.asp.

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COMPETENT PERSON’S REPORT AND VALUATION REPORT

APPENDIX V

BRITISH COLUMBIA OIL ROYALTY

The royalty payable on crude oil produced in British Columbia is a function of rate and whether it is classified as "new" or "old" oil. "New" oil has been defined as oil which is produced from a well whose spacing unit lies wholly outside the outlines of an existing oil pool at November 1, 1975. Incremental oil in an existing pool which will be recovered by waterflooding or upgrading an existing waterflood is also classified as "new" oil. Royalty rates vary from 0 to about 40 percent on "old" oil and from 0 to about 30 percent on "new" oil. The following table shows the categories and royalty formulae that apply to British Columbia production.

Category “Old” oil at rates < 600 BOPM “Old” oil at rates > 600 BOPM “New” oil at rates < 1000 BOPM “New” oil at rates > 1000 BOPM	Royalty Formula R = ~~_P_2~~ 5000 R = 72 + 0.4 (P - 600) R = _P_2 6667 R = 150 + 0.3 (P - 1000)

Where: R = Royalty in barrels P = Monthly oil production in barrels

There is a three-year, royalty-free incentive period for oil production in the discovery well of a new pool. Incremental oil from an approved tertiary recovery pilot is also exempt from payment of royalty. Production from an approved tertiary project other than a pilot will be subject to a royalty rate determined by the Lieutenant Governor-in-Council.

The introduction of Third Tier oil, which is oil from pools discovered after June 1, 1998. The royalty rates for Third Tier oil will be 20 percent lower than the rates for the New oil category at all rates of production.

- British Columbia Natural Gas and Natural Gas By Products Royalties

Effective June 1, 1988, the calculation of Crown royalties on natural gas and natural gas by-products was modified as part of the ongoing policy of deregulating the petroleum industry in British Columbia. This is intended to simplify administrative procedures for both government and industry, without significantly changing the overall royalties collected by the province under the previous regime. The royalty rates for natural gas are determined by formulae and are a function of the natural

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APPENDIX V COMPETENT PERSON’S REPORT AND VALUATION REPORT

gas category classification, the market selling price, and a royalty allowance. The royalty rates for liquids and sulphur are held constant at 20 percent and 16 2/3 percent, respectively. Liquids are defined as being ethane, propane, butane, condensate, or any mixture thereof.

For royalty purposes, there are two categories of natural gas: (1) non-associated (or natural gas-cap gas) and (2) conservation gas (or solution gas). There are different equations and minimum royalty rates for each of these categories as shown below:

Non-Associated Gas (Minimum 15%):

==> picture [176 x 24] intentionally omitted <==

Conservation Gas (Minimum 8%):

==> picture [178 x 23] intentionally omitted <==

Where: P = The greater of actual field price and the posted minimum

price

Note: Royalty calculations become price sensitive when the price exceeds $50.00 per E3 M3.

The following two new categories for non-

conservation gas have been introduced:

New wells on Existing Lands - non-conservation gas from wells spudded after May 31, 1998 on land for which there are existing oil and gas rights as of May 31, 1998. Minimum royalty is 12 percent, maximum 27 percent. The royalty formula is:

Royalty Rate in % = [12 x Select Price + 40 (Reference Price - Select Price)]

Reference Price

New wells on New Lands - non-conservation gas from wells for which oil and gas rights are issued after May 31, 1998, and before January 1, 2002, and which are completed within 5 years of the date rights are issued. Minimum royalty is 9 percent, maximum 27 percent. The royalty formula is:

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COMPETENT PERSON’S REPORT AND VALUATION REPORT

APPENDIX V

Royalty Rate in % = [9 x Select Price + 40 (Reference Price - Select Price)]

Reference Price

The actual field price (Acquisition Order Price) is determined by taking the price received at one of five end points of sale from Westcoast facilities and subtracting the applicable tolls to bring the price back to the point of entrance into the Westcoast facilities. The provincial royalties are paid based on this price, however, royalties are subsequently reduced by the Producer Cost-of-Service Allowance (PCOSA) and may also be further reduced by a Gas Cost Allowance (GCA), if applicable. Gas cost allowance is necessary if processing facilities (gas plants) are not owned by Westcoast (i.e., producer owned). The PCOSA is a postage stamp dollar per unit allowance received to compensate the producer for transporting the royalty share of natural gas from wellhead to the point of entry at a Westcoast trunk line. In the case of non-associated gas wells, it is specifically for gathering and field compression and is calculated based on the well location and H2S content of the natural gas. In the case of solution gas recovery (conservation gas) there is a constant dollar per unit allowance for all areas and any H2S content. The tables section of this report details how PCOSA is allocated. The GCA calculation is very similar to the Jumping Pound calculations used in Alberta. It is a utility type calculation that allows for capital depreciation, a return-on-rate base and operating cost deductions.

Producer Cost of Service in $/10[3] M[3] of Raw Natural Gas

Area"D" (H2S<=1%) (H2S>=1%) (H2S>=1%) Gas gathering and dehydration 5.00 11.00 Field compression 8.00 9.00 Gas conservation 16.00 16.00	___All Other Areas
	(H2S<=1%) 4.00 5.00 5.00 5.00 16.00 16.00

The designation of area "D" is as follows: From a commencement point of Latitude 54°00', and Longitude 120°00', northwest along the Rocky Mountain watershed to Latitude 55°35', east to Longitude 121°00', south to Latitude 55°25', east to Longitude 120°00' and south to the commencement point.

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COMPETENT PERSON’S REPORT AND VALUATION REPORT

APPENDIX V

SASKATCHEWAN GAS CROWN ROYALTY AND FREEHOLD PRODUCTION TAX CLASSIFICATION

For Crown royalty and freehold production purposes, natural gas in Saskatchewan is considered either “non-associated gas” or “associated gas”. The royalty and production tax classifications (“fourth tier gas”, “third tier gas”, “new gas” or “old gas”) of gas production for each of the natural gas types is described below:

NON-ASSOCIATED GAS means gas produced from gas wells.

Fourth Tier Gas - gas produced from a gas well with a finished drilling date on or after October 1, 2002.

Third Tier Gas - gas produced from a gas well with a finished drilling date on or after February 9, 1998 and before October 1, 2002.

New Gas - gas produced from a gas well with a finished drilling date before February 9, 1998 and with a first production date on or after October 1, 1976 (with some exceptions related to re-entered wells, unit wells and gas reclassified from “old gas” to “new gas”.)
Old Gas - gas produced from a gas well other than gas classified as “fourth tier gas”, “third tier gas”, or “new gas”.

ASSOCIATED GAS means gas produced from oil wells.

Fourth Tier Gas - gas that is gathered for use or sale and is produced from an oil well:

with a finished drilling date on or after October 1, 2002; or
with a finished drilling date before October 1, 2002 where the gas-oil-ratio (GOR) for the well for the month exceeds 3,500 cubic meters of gas per cubic meter of oil and is not “third tier gas” or “new gas”.
Third Tier Gas - gas produced from an oil well with a finished drilling date on or after February 9, 1998 and before October 1, 2002 that received special approval, prior to October 1, 2002, to produce oil and gas concurrently without gas-oil ratio penalties.
New Gas - gas produced from an oil well with finished drilling date before February 9, 1998 that received special approval, prior to October 1, 2002, to produce oil and gas concurrently without gas-oil ratio penalties.

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APPENDIX V COMPETENT PERSON’S REPORT AND VALUATION REPORT

Note: Gas produced from an oil well

received special approval, after October 1, 2002, to produce oil and gas concurrently without gasoil ration penalties, will only be subject to royalty/tax if it meets the criteria established for the “fourth tier gas” associated gas type.

SASKATCHEWAN GAS CROWN ROYALTY AND FREEHOLD PRODUCTION TAX FORMULAS

Monthly Gas Production (10 m3) NON-ASSOCIATED GAS		Monthly Gas Production (10 m3)	Crown Royalty Rate (%)	Freehold Production Tax Rate (%)

Fourth Tier Gas 0-25.0 25.1-136.2 Over 115.4			0 0 (Cg x MGP) –Dg Crown Royalty Rate (%)-PTF g       −MGP X K g g Crown Royalty Rate (%)-PTF g
Third Tier Gas, 0-115.4 New Gas and Over 115.4 Old Gas			(Cg x MGP) –SRC Crown Royalty Rate (%)-PTF g       −MGP X K g g -SRC Crown Royalty Rate (%)-PTF g

ASSOCIATED GAS

Fourth Tier Gas	0-64.7		0	0
	Over 64.7	   K g	   −MGP X g	Crown Royalty Rate (%)-PTF g
Third Tier Gas
New Gas and	Same as the	formulas for	“Third Tier Gas”, “New Gas”, and “Old Gas” shown
Old Gas	above for NON-ASSOCIATED GAS.

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APPENDIX V COMPETENT PERSON’S REPORT AND VALUATION REPORT

Where:

“Cg”, “Dg”, “Kg” and ”Xg” are factors determined monthly by the department for each royalty/tax classification in accordance with price sensitive policies and equations described in the next section.
MGP = Monthly Gas Production. The MOP is the total amount of gas produced from an oil well or gas well in a month measured in thousand cubic meters, rounded to the nearest tenth.
PTFg = Production Tax Factor. The PTFg is an amount established by regulation at a level of 6.9 for “old gas”, 10.0 for “new gas” and “third tier gas” and 12.5 for “fourth tier gas”.
SRC = Saskatchewan Resources Credit. The SRC is an amount established by regulation at a level of 1.0 for “old gas” and “new gas” and 2.5 for “third tier gas”.

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APPENDIX V COMPETENT PERSON’S REPORT AND VALUATION REPORT

SASKATCHEWAN GAS CROWN ROYALTY AND FREEHOLD PRODUCTION TAX PRICE SENSITIVE POLICES

Crown royalty and freehold production

tax rates are adjusted monthly by changing the “Cg”, “Dg”, “Kg” and “Xg” factors. These factors are determined by the department on a monthly basis in accordance with the price sensitive policies outlined below. The policies apply before the application of the Saskatchewan Resources Credit (SRC), where applicable.

The “Cg”, “Dg”, “Kg” and “Xg” factors are

determined based on the following revenue sharing polices which apply at a reference well production rate of 250 thousand cubic meters of gas per month:

CROWN ROYALTY PRICE SENSITIVE POLICY

(a) Base fieldgate gas prices, which establish the lower limits of the price sensitive structure, are as follows:

$50 per thousand cubic meters for “fourth tier gas” and “third tier gas”; and $35 per thousand cubic meters for “new gas” and “old gas”.

A provincial average fieldgate gas price (PGP) is estimated and set by the minister for each month. For months in which the PGP is less than or equal to the base fieldgate prices mentioned in (a), “base” royalty rates apply. The “base” royalty rates, which represent the minimum royalty rates at the reference well production rate, are:

5% for “fourth tier gas”; 15% for “third tier gas” or “new gas”; 20.0% for “old gas”.

(b) When the PGP set for any month is above the base price, the royalty rate at the reference well production rate is calculated by applying the “base” royalty rate to the “base” price and adding a “marginal” royalty rate applied to the portion of the PGP that is above the “base” price. The “marginal” royalty rates are:

30% for “fourth tier gas”; 35% for “third tier gas” and “new gas”; and 45% for “old gas”;

(c) The resulting equations that are derived from the price sensitive policy and are used to determine the “Kg”, “Xg”, “Cg” and “Dg” factors are shown below. These equations are incorporated into the regulations.

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COMPETENT PERSON’S REPORT AND VALUATION REPORT

APPENDIX V

Non-Associated

==> picture [435 x 213] intentionally omitted <==

Associated Gas

==> picture [426 x 60] intentionally omitted <==

Third Tier Gas Same as the formulas for “Third Tier Gas” shown above for non-associated gas

New Gas Same as the formulas for “New Gas” shown above for non-associated gas

Where:

GP = Gas Prices. The GP is equal to the greater of the provincial average fieldgate gas price (PGP) and the “base” fieldgate gas price. The “base” fieldgate prices are $35 per thousand cubic meters for “old gas” and “new gas” and $ 50 per thousand cubic meters for “third tier gas” and “fourth tier gas”. The GP is expressed in dollars per thousand cubic meters rounded to the nearest cent and is estimated and set by the minister each month.

Note: “Cg” is rounded to the nearest tenth thousandth, “Dg” and “Kg” are rounded to the nearest hundredth and “Xg” is rounded to the nearest whole number.

(d) The minimum Crown royalty rate is zero.

– V﹣61 –

APPENDIX V COMPETENT PERSON’S REPORT AND VALUATION REPORT

FREEHOLD PRODUCTION TAX PRICE SENSITIVE POLICY

(a) Freehold production tax rates are determined by subtracting the applicable Production Tax Factor (PTFg), for the particular classification of gas, from the Crown royalty rate applicable to the classification of gas. The PTFg is currently set at the following levels:
6.9 for “old gas”;
10.0 for “new gas” and “third tier gas”; and

12.5 for “fourth tier gas”

(b) The minimum freehold production tax rate is zero.

ASSOCIATED GAS ADMINISTRATION

The “fourth tier gas” royalty/tax classification for “associate gas” applies only to gas that is gathered for use or sale and which is produced:

from an oil well drilled on or after October 1, 2002; or
from an oil well drilled before October 1, 2002 where:
a) the GOR for the well for the month in question exceeds 3500 m3 of gas per m3 of oil. Note: The “fourth tier gas” royalty/tax structure does apply to gas produced in any month from an oil well which the GOR for the well is less than or equal to 3500; and
b) the gas production does not already have an assigned “new gas” or “third tier gas” royalty/tax classification. (For example, an oil well approved for concurrent production prior to October 1, 2002 would already have a “third tier gas” or “new gas” royalty/tax classification assigned to the gas produced form the oil well).

Note: The “fourth tier gas” royalty formula applicable to associated gas is designed to that royalties only become payable when the gas production volume exceeds 64.7103 m3 per month.

Gas produced from oil wells that receive approval for concurrent production on or after October 1, 2002 will no longer be assigned a “new gas” or “third tier gas” royalty/tax classification. Instead, the gas production will only be subject to the “fourth tier gas” royalty/tax classification, and only in cases where it meets the requirements for the “fourth tier gas” classification specified in points “1” or “2” noted above. Gas produced from oil

– V﹣62 –

APPENDIX V COMPETENT PERSON’S REPORT AND VALUATION REPORT

wells, for which the minister had issued an order before October 1, 2002 for oil and gas to be produced concurrently, will continue to be subject to the previously assigned “new gas” or “third tier gas” royalty/tax classification.

The well-head value applicable to the royalty/tax share associated gas production is based on either the Operator Average Gas Price (OGP) or the Provincial Average Gas Price (PGP), depending on the operator or special operators election.

– V﹣63 –

COMPETENT PERSON’S REPORT AND VALUATION REPORT

APPENDIX V

SASKATCHEWAN OIL CROWN ROYALTY AND FREEHOLD PRODUCTION TAX CLASSIFICATION

For Crown royalty and freehold production tax purposes, crude oil in Saskatchewan is considered either “heavy oil”, “southwest designated oil” or “non-heavy oil other than southwest designated oil”. The conventional royalty and production tax classifications (“fourth tier oil”. “third tier oil”, “new oil” or “old oil”) of oil production for each for the three crude oil types is described below:

HEAVY OIL Means oil production within the townships north of Townships 21 Ranges 5 through 29, West of the Third Meridian, except oil produced for the Viking zone or from any other zone deposited more recently than the Viking zone.

Fourth Tier Oil - conventional oil produced from an oil well or gas well with a finished drilling date on or after October 1, 2002; or incremental oil due to a new or expanded waterflood project with a commencement date on or after October 1, 2002.

Third Tier Oil - conventional oil produced form a vertical oil well or gas well with a finished drilling date on or after January 1, 1994 and before October 1, 2002; or incremental waterflood oil due to a new or expanded waterflood project with a commencement date on or after January 1, 1994 and before October 1, 2002.

New Oil - conventional oil that is not classified as “third tier oil” or “fourth tier oil”.

SOUTHWEST DESIGNATED OIL Means non-heavy oil produced from within the southwest area of the province (Township1 through 21 in Ranges 1 through 30, West of the Third Meridian) as a result of new exploration or development activity on or after February 9, 1998.

Fourth Tier Oil - conventional oil produced from an oil well or gas well with a finished drilling date on or after October 1, 2002; or incremental oil due to a new or expanded waterflood project with a commencement date on or after October 1, 2002.
Third Tier Oil - conventional oil produced form a vertical oil well or gas well with a finished drilling date on or after February 9, 1998 and before October 1, 2002; or incremental waterflood oil due to a new or expanded waterflood project with a commencement date on or after February 9, 1998 and before October 1, 2002.
New Oil - conventional oil produced from a horizontal oil well with a finished drilling date on or after February 9, 1998 and before October 1, 2002.

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COMPETENT PERSON’S REPORT AND VALUATION REPORT

APPENDIX V

NON-HEAVY OIL OTHER THAN SOUTHWEST DESIGNATED OIL Is oil that is not “heavy

oil” or “southwest designated oil”. (Note: In the southwest area, oil production as a result of exploration or development activity before February 9, 1998 is considered non-heavy oil.)

Fourth Tier Oil - conventional oil production from an oil well or gas well with finished drilling date on or after October 1, 2002; or incremental oil due to a new expanded waterflood project with a commencement date on or after October 1, 2002.

Third Tier Oil - conventional oil produced from vertical oil well or gas with a finished drilling date on or after January 1, 1994 and before October 1, 2002; or incremental waterflood oil due to a new or expanded waterflood project with a commencement date on or after January 1, 1994 and before October 1, 2002.
New Oil - conventional oil produced from a vertical well or gas well completed after 1973 with a finished drilling date before 1994 (with some exceptions related to “old oil” to “new oil” reclassifications); conventional oil produced form a horizontal oil well with a finished drilling date on or after April 1, 1991 and before October 1, 2002;or incremental waterflood oil due to a new or expanded waterflood project with a commencement date on or after January 1, 1974 and before 1994.
Old Oil - conventional oil that is not classified as “fourth tier oil”, “third tier oil” or “new oil”.

– V﹣65 –

APPENDIX V COMPETENT PERSON’S REPORT AND VALUATION REPORT

SASKATCHEWAN OIL CROWN ROYALTY AND FREEHOLD PRODUCTION TAX FORMULAS

Monthly Crown Freehold Oil Production Royalty Rate Production Tax Rate (m3) (%) (%)

Fourth Tier Oil

0-25.0 0 0

==> picture [331 x 42] intentionally omitted <==

Third Tier Oil New Oil and Old Oil

==> picture [331 x 40] intentionally omitted <==

Where:

“C”, “D”, “K” and ”X” are factors determined by the department on a monthly basis for each royalty/tax classification in accordance with the price sensitive polices and equations described in the next section.
- MOP = Monthly Oil Production. The MOP is the total amount of oil produced from an oil well or gas well in a month measured in cubic meters, rounded to the nearest tenth.
PTF = Production Tax Factor. The PTF is an amount established by regulation at a level of 6.9 for “old oil”, 10.0 for “new oil” and “third tier oil” and 12.5 for “fourth tier oil”.
SRC = Saskatchewan Resources Credit. The SRC is an amount established by regulation at a level of:
2.5 percentage points:
- for all convention oil produced from vertical oil wells drilled on or after February 9, 1998 and before October 1, 2002; and
- for incremental oil produced from the new or expanded portion of waterfloods implementes on or after February 9, 1998 and before October 1, 2002; and
1.0 percentage point for all other “old oil”, ”new oil” or “third tier oil”.

– V﹣66 –

APPENDIX V COMPETENT PERSON’S REPORT AND VALUATION REPORT

Before the SRC deduction, where applicable, the minimum Crown royalty rate is 1%. After the SRC deduction; the minimum Crown royalty rate is zero.

– V﹣67 –

COMPETENT PERSON’S REPORT AND VALUATION REPORT

APPENDIX V

SASKATCHEWAN OIL CROWN ROYALTY AND FREEHOLD PRODUCTION TAX PRICE SENSITIVE POLICES

Crown royalty and freehold production tax rates are adjusted monthly by changing the “C”, “D”, “K” and “X” factors. These factors are determined by the department on a monthly basis in accordance with the price sensitive policies outlined below. The policies apply before the application of the Saskatchewan Resources Credit (SRC), where applicable.

The “C”, “D”, “K” and “X” factors are based on

the following revenue sharing policies which apply at a reference well production rate of 100 cubic meters of oil per month for “old oil”, “new oil” and “third tier oil” and 250 cubic meters per month for “fourth tier oil”.

CROWN ROYALTY PRICE SENSITIVE POLICY

(a) Base oil prices, which established the lower limits of the price sensitive structure, are as follows:
$100 per cubic meter for “fourth tier oil” and “third tier oil”; and $50 per cubic meter for “new oil” and “old oil”.
(b) A provincial average well-head price is estimated and set by the minister of the department for each month for heavy oil (HOP), southwest oil (SOP) and nonheavy oil (NOP). (Note: Non-heavy oil includes all oil other than heavy oil) The “base” royalty rates, which represent the minimum royalty rates at the reference well production rate are:

5.0% for all “fourth tier oil”;

10.0% for heavy oil that is “third tier oil” or “new oil”;

15.0% for non-heavy oil other that southwest designated oil that is “third tier oil” or “new oil”; and 20.0% for “old oil”.

(c) When the HOP, SOP or NOP is above the respective base oil price, the royalty rate at the reference well production rate is calculated by applying the “base” royalty rate to the “base” price and adding the “marginal” royalty rates applied to the portion of the HOP, SOP or NOP that is above the respective base oil price. The “marginal” royalty rates are:

– V﹣68 –

APPENDIX V COMPETENT PERSON’S REPORT AND VALUATION REPORT

30% for all “four tier oil”;

25% for heavy oil that is “third tier oil” or “new oil”;

35% for southwest designated oil that is “third tier oil” or “new oil”; 35% for non-heavy oil other than southwest designated oil that is “third tier oil” or “new oil”; and 45% for “old oil”.

(d) The resulting equations used to determine the “C”, ”D”, “K” and “X” factors are shown below.

K Heavy Oil Fourth Tier Oil 7.14+35.71 x       − HOP 3 / 100 $ m HOP Third Tier Oil 13.0+19.5 x       − HOP 3 / 100 $ m HOP New Oil 13.0+19.5 x       − HOP 3 / 100 $ m HOP Southwest Designated Oil Fourth Tier Oil 7.14+35.71 x           − SOP 3 / 100 $ m SOP Third Tier Oil 16.25+29.25 x           − SOP 3 / 100 $ m SOP New Oil 16.25+29.25 x           − SOP 3 / 100 $ m SOP	X Kx75    Kx23.08 Kx23.08 Kx75    Kx23.08 Kx23.08	C D    247.48 K       9.90 K N/A N/A N/A N/A    247.48 K       9.90 K N/A N/A N/A N/A

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COMPETENT PERSON’S REPORT AND VALUATION REPORT

APPENDIX V

K X C D

Non-Heavy Oil other than Southwest Designated Oil

==> picture [410 x 170] intentionally omitted <==

Where:

HOP = Heavy Oil Price. The HOP is the provincial average heavy oil price, expressed in dollars per cubic meter rounded to the nearest dollar, as estimated and set by the minister for each month. The minimum HOP used in the “K” factor formulas is $50 per cubic meter for “new oil” and $100 per cubic meter for “third tier oil” and “fourth tier oil”.
SOP = Southwest Designated Oil Price. The SOP average southwest area oil price, expressed in dollars per cubic meter rounded to the nearest dollar, as estimated and set by the minister for each month. The minimum SOP used is the “K” factor formula is $50 per cubic meter for “new oil” and $ 100 per cubic meter for “third tier oil” and “fourth tier oil”.
NOP = Non-Heavy Oil Price. The NOP is the provincial average non-heavy oil price, expressed in dollars per cubic meter rounded to the nearest dollar, as estimated and set by the minister for each month. The minimum NOP used in the “K” factor formulas for $50 per cubic meter for “old oil” and “new oil” and $100 per cubic meter for “third tier oil” and “fourth tier oil”.
Note: “C” is rounded to the nearest tenth thousandth, “D” and “K” are rounded to the nearest hundredth and “X” is rounded to the nearest whole number.

– V﹣70 –

APPENDIX V COMPETENT PERSON’S REPORT AND VALUATION REPORT

FREEHOLD PRODUCTION TAX PRICE SENSITIVE POLICY

(a) Freehold production tax rates are determined by subtracting the applicable Production Tax Factor (PTF) from the Crown royalty rate applicable to that classification of oil. The PTF is currently set at the following levels:

6.9 for “old oil”; 10.0 for “new oil” and “third tier oil”; and 12.5 for “fourth tier oil”

(b) The minimum freehold production tax rate is zero.

SASKATCHEWAN OIL HOLIDAYS AND INCENTIVE VOLUMES

Effective January 1, 1994, the previous royalty holiday provisions have been cancelled and replaced with new maximum royalties applicable to incentive volumes of 2 000 M3 for new stepout vertical development oil wells, and 4 000 M3 for wells commencing after February 8, 1998 in the Vandersley/Kerrobert and Lloydminster 8 000 M3 for new vertical exploratory oil wells, 12 000 M3 for deep vertical development oil wells and 25 000 M3 for deep vertical exploratory oil wells. All new vertical oil wells will revert to a third tier royalty after production of the applicable incentive volumes.

Horizontal oil wells will receive an incentive volume of 12 000 M3 at a maximum 10 percent royalty for short horizontal section and re-entry wells while all other non-deep horizontal oil wells will receive an incentive volume of 12 000 M3 at a maximum of 5 percent royalty. Deep horizontal development and exploratory wells will receive an incentive volume of 25 000 M3 at a maximum 5 percent royalty. All new horizontal wells will revert to new crown royalty after production of the applicable volumes.

– V﹣71 –

GENERAL INFORMATION

APPENDIX VI

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 belief 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 omission 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 of 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 Divisions 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 as 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 of	underlying	interest in the
Director	corporation	interest	shares interested	corporation
Mr. Zhang	Our Company	Interest of controlled	1,521,295,234	51.77%
Ruilin		corporation (Note 2)
		Interest of controlled	88,521,234	3.01%
		corporation (Note 3)
		Beneficial owner (Note 4)	7,987,000 (L)	0.27%
Mr. Zhao	Our Company	Interest of controlled	1,521,295,234	51.77%
Jiangwei		corporation (Note 2)
		Interest of controlled	88,521,234	3.01%
		corporation (Note 3)
		Beneficial owner (Note 4)	10,187,000 (L)	0.35%

– VI-1 –

GENERAL INFORMATION

APPENDIX VI

			Number of
			shares (including
			options to be	Approximate
			exercised)/	percentage of
Name of	Name of	Capacity/Nature of	underlying	interest in the
Director	corporation	interest	shares interested	corporation
Mr. Zhang	Far East	Interest of controlled	8,999	9.99%
Ruilin	Energy	corporation (Note 2)
	Limited
	(‘‘FEEL’’)
Mr. Zhao	FEEL	Interest of controlled	9,000	10%
Jiangwei		corporation (Note 2)
Mr. Mei	Our Company	Beneficial owner	1,267,933(L)	0.04%
Jianping
Mr. Jeffrey	Our Company	Beneficial owner	1,811,333 (L)	0.06%
Willard
Miller

Notes:

The letter ‘‘L’’ denotes the person’s long position in the shares of the Company. The letter ‘‘S’’ denotes the person’s short position in the shares of the Company.
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 1,521,295,234 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 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) 2,300,000 shares owned by Mr. Zhao himself.

– VI-2 –

GENERAL INFORMATION

APPENDIX VI

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.

Save as disclosed above, none of the Directors had, as at the Latest Practicable Date, any interests or short positions in the shares, underlying shares and debentures of the Company and the shares and debentures of its associated corporations (within the meaning of Part XV of the SFO) which were required (a) to be notified to the Company and the Stock Exchange pursuant to Divisions 7 and 8 of Part XV of the SFO (including interests or short positions which any such Director or chief executive was taken or deemed to have under such provisions of the SFO); or (b) pursuant to section 352 of the SFO, to be entered in the register referred to therein; or (c) pursuant to the Model Code for Securities Transactions by Directors of Listed Issuers, to be notified to the Company and the Stock Exchange.

– VI-3 –

GENERAL INFORMATION

APPENDIX VI

(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 or short position in the Shares and underlying Shares of the Company which would fall to be disclosed to the Company under the provisions of Divisions 2 and 3 of Part XV of the SFO, or, who were, directly or indirectly, interested in 10% or more of the nominal value of any class of shares capital carrying rights to vote in all circumstances at general meetings of any other member of the Enlarged Group, the details of which are set out below:

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

			Approximately
			percentage of
		Number of	interest in the
Name of shareholder	Nature of interest	Shares held	Company
Ms. Zhao Jiangbo	Interest of controlled	1,521,295,234 (L)	51.77%
	corporation (Note 2)	88,521,234 (S)	3.01%
FEEL	Interest of controlled	1,521,295,234 (L)	51.77%
	corporation (Note 2)	88,521,234 (S)	3.01%
Mr. Ho Chi Sing	Interest of controlled	1,521,295,234 (L)	51.77%
	corporation (Note 3)	88,521,234 (S)	3.01%
Celestial Energy Limited	Interest of controlled	1,521,295,234 (L)	51.77%
(‘‘Celestial’’)	corporation (Note 3)	88,521,234 (S)	3.01%

Notes:

The letter ‘‘L’’ denotes the person’s long position in the shares of the Company. The letter ‘‘S’’ denotes the person’s short position in the shares of the Company.
FEEL is held by Ms. Zhao Jiangbo (‘‘Mrs. Zhang’’), Mr. Zhang and 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 Actingin-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.

– VI-4 –

GENERAL INFORMATION

APPENDIX VI

The long interests which FEEL, Mr. Zhang and Mr. Zhao have in the 1,521,295,234 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 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) the 2,300,000 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.

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.

Saved as disclosed above, as at the Latest Practicable Date, so far as was known to the Directors and the chief executive of the Company, there were no persons or entities (other than a Director and the chief executive of the Company) who had an interest or short position in the Shares or the underlying Shares of the Company which would fall to be disclosed to the Company under the provisions of Divisions 2 and 3 of Part XV of the SFO, or, who were, directly or indirectly, interested in 10% or more of the nominal value of any class of share capital carrying rights to vote in all circumstances at general meetings of any other member of the Enlarged Group.

3. COMPETING INTERESTS

As at the Latest Practicable Date, none of the Directors and their respective associates had any interest in a business, apart from the business of the Company, which competes or may 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.

– VI-5 –

GENERAL INFORMATION

APPENDIX VI

4. DIRECTORS’ INTEREST IN CONTRACT OR ARRANGEMENT

Directors’ interests in contracts and continued connected transactions

During the year ended December 31, 2016, the Group had the following transactions with Ms. Zhao Jiangbo (‘‘Mrs. Zhang’’) and Jilin Guotai Petroleum Development Company, Songyuan Guotai Petroleum Technology Service Company and their subsidiaries (‘‘Jilin Guotai’’), which are connected persons of the Company under the Listing Rules:

(A) Lease of vehicles by Mrs. Zhang to the Company
(B) Provision of oilfield services by Jilin Guotai to the Company

Category I — Continuing Connected Transactions Exempt from Independent Shareholder’s Approval

(A) Lease of vehicles by Mrs. Zhang to us

Mrs. Zhang is the spouse of Mr. Zhang Ruilin, and is therefore a connected person of our Company. Since 2008, Mrs. Zhang has been regularly leasing a substantial number of vehicles to us.

On December 31, 2012, we entered into a renewed framework vehicle rental agreement with Mrs. Zhang (the ‘‘Vehicle Rental Agreement’’), pursuant to which Mrs. Zhang agreed to rent to us a number of vehicles for the purpose of the day-today business operations of our Group, subject to the entering into of individual contracts as agreed between Mrs. Zhang and us pursuant to the Vehicle Rental Agreement.

No individual vehicle rental contract has been entered into with Mrs. Zhang under above Vehicle Rental Agreement during FY2016.

Category II — Non-exempt Continuing Connected Transactions

(B) Provision of oilfield services by Jilin Guotai to the Company

Jilin Guotai is owned by Mrs. Zhang and Mr. Zhao Jiangwei, and is therefore a connected person of the Company.

On November 23, 2010, we entered into a framework oilfield service agreement with Jilin Guotai (the ‘‘Oilfield Service Agreement’’), pursuant to which Jilin Guotai agreed to provide to us various oilfield services including well maintenance services, well logging services, oil tanker transportation services, oilfield construction related works and other oil operations related services, subject to the entering into of individual contracts as agreed between Jilin Guotai and us pursuant to the Oilfield Service Agreement. The service fees will be based on normal commercial terms and negotiated on arm’s length basis between the parties, and shall be no less favourable than those offered by independent third parties to our Group.

– VI-6 –

GENERAL INFORMATION

APPENDIX VI

On December 31, 2012, we entered into the Renewed Oilfield Services Agreement with Jilin Guotai for a term of three years ending December 31, 2015.

On December 31, 2015, we entered into the Renewed Oilfield Services Agreement with Jilin Guotai for a term of three years ending December 31, 2018. The proposed annual caps for the transactions under the Renewed Oilfield Services Agreement are RMB99.0 million, RMB96.0 million and RMB82.0 million for the three years ending December 31, 2018, respectively.

As listed below, the aggregate annual transaction amount of each continuing connected transaction for the year ended December 31, 2016 has not exceeded the respective proposed annual cap in the Renewed Oilfield Services Agreement as set out in the announcement published by the Company on December 31, 2015.

Directors’ interests in the assets of the Enlarged Group

As at the Latest Practicable Date, none of the Directors had any direct or indirect interest in the 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, any member of the Enlarged Group since December 31, 2016, the date to which the latest published audited consolidated financial statements of the Company were made up.

5. SERVICE CONTRACTS OF THE DIRECTORS

In November 20, 2009, Zhang Ruilin and Zhao Jiangwei, each an executive Director, each entered into a service contract with each of the Company and MI Energy Corporation (‘‘MI Energy’’), a wholly-owned subsidiary of the Company, which is renewable yearly unless terminated (i) with twelve months’ notice by either party, or (ii) by the Company or MI Energy (as applicable) upon certain events such as the Director having committed serious or persistent breaches of the service contract. Should the Company or MI Energy (as applicable) 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.

– VI-7 –

GENERAL INFORMATION

APPENDIX VI

6. EXPERTS AND CONSENTS

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

Name Qualification

DeGolyer and MacNaughton Independent technical adviser and competent person PricewaterhouseCoopers Certified Public Accountants, Hong Kong PricewaterhouseCoopers LLP Chartered Professional Accountants, Canada

DeGolyer and MacNaughton, PricewaterhouseCoopers and PricewaterhouseCoopers LLP are referred to as the ‘‘Experts’’ hereinafter.

The Competent Person’s Report from DeGolyer and MacNaughton was given on May 31, 2017 for incorporation in this circular.

The reports from each of PricewaterhouseCoopers and PricewaterhouseCoopers LLP were given on September 7, 2017 for incorporation in this circular.

As at the Latest Practicable Date, none of the Experts had any 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, 2016, the date to which the latest published audited accounts of the Group was made up.

All of the Experts have given and have not withdrawn its written consent to the issue of this circular with the inclusion of its letter(s) or report(s) (as the case may be) and reference to its name in the form and context in which they respectively appear.

7. LITIGATION

As at the Latest Practicable Date, so far as the Directors are aware, no members of the Enlarged 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 Enlarged Group as at the Latest Practicable Date.

– VI-8 –

GENERAL INFORMATION

APPENDIX VI

8. 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 Enlarged Group within two years immediately preceding the issue of this circular and are material:

(a) a placing and subscription agreement dated October 16, 2015, and entered into among New Sun International Energy Limited (‘‘New Sun’’), the Company and six institutional and individual investors, pursuant to which (a) New Sun sell to the investors in aggregate 276,300,000 Shares at the price of HK$0.90 per Share, and (b) New Sun subscribe, and the Company issue and allot 276,300,000 Shares at the price of HK$0.90 per Share;
(b) a settlement agreement dated December 11, 2015 and entered into between the Company and the Acap Limited in relation to an outstanding termination fee payable by the Company to Acap Limited amounted to approximately US$6,830,000 is settled by the allotment and issue of 55,718,000 Shares to Acap Limited at the issue price of HK$0.95 per Share;
(c) an agreement for the sale and purchase of sixty per cent of the issued share capital of Palaeontol B.V. dated March 5, 2016, and entered into among the Company, Palaeontol Cooperatief U.A. (a wholly owned subsidiary of the Company) and Reach Energy Berhad, pursuant to which, Palaeontol Cooperatief U.A. sold sixty per cent of the issued share capital of Palaeontol B.V. to Reach Energy Berhad in the he aggregate consideration of US$175,856,539;
(d) a sale and purchase agreement dated April 26, 2016 between the Company and China New Energy Mining Limited relating to the disposal of the entire issued shares capital of Asia Gas & Energy Ltd. and the shareholder’s loan owed by Asia Gas & Energy Ltd. to China New Energy Mining Limited in consideration of US$ 220 million (approximately HK$1,176 million) (subject to adjustment);
(e) 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$43,383,000) (subject to adjustment);
(f) 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$195,782,245);
(g) 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 with interest of 9% per annum to Boston-Power, Inc.;

– VI-9 –

GENERAL INFORMATION

APPENDIX VI

(h) 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$289,222,000);
(i) the PSA dated May 31, 2017;
(j) the Subscription Agreement dated May 31, 2017; and
(k) the Amending Agreement dated June 8, 2017.

9. MISCELLANEOUS

(a) The registered office of the Company is at P.O. Box 309, Ugland House, Grand Cayman KY1–1104, Cayman Islands. The Beijing 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 22, Hopewell Centre, 183 Queen’s Road East, Hong Kong.
(b) The branch share registrar and transfer office of the Company in 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) As at the Latest Practicable Date, the Company had an authorised share capital of US$100,000,000 divided into 100,000,000,000 of US$0.001 each. As at the Latest Practicable Date, 2,938,596,793 ordinary shares were issued and fully paid.
(e) This circular is prepared in both English and Chinese. In the event of inconsistency, the English version shall prevail.

10. 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 audited consolidated accounts of the Group for each of the three financial years ended December 31, 2014, 2015 and 2016;
(c) the Accountant’s Report on the Target Group, the text of which is set out in Appendix II of this circular together with the associated statement of adjustments;

– VI-10 –

GENERAL INFORMATION

APPENDIX VI

(d) the report in relation to unaudited pro forma financial information of the Enlarged Group, the text of which is set out in Appendix III of this circular;
(e) the Competent Person’s Report and Valuation Report prepared by DeGolyer and MacNaughton, the text of which are set out in Appendix V to this circular;
(f) the contracts referred to in the paragraph headed ‘‘Service Contracts of the Directors’’ in this Appendix;
(g) the contracts referred to in the paragraph headed ‘‘Material Contracts’’ in this Appendix;
(h) the written consents referred to in the paragraph headed ‘‘Experts and Consents’’ in this Appendix; and
(i) this circular.

– VI-11 –

NOTICE OF EGM

==> picture [75 x 75] intentionally omitted <==

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 3, Novotel Century Hong Kong, 238 Jaffe Road, Wanchai, Hong Kong on Friday, September 22, 2017 at 9:30 a.m., for the purpose of considering and, if thought fit, passing with or without modification or amendment the following resolutions:

ORDINARY RESOLUTIONS

‘‘THAT:

(a) the Partnership Interest Purchase and Sale Agreement dated May 31, 2017 (the ‘‘PSA’’) entered into between Direct Energy Resources Partnership, A Partner (as defined in the circular of the Company dated September 7, 2017), Canlin Energy Corporation (formerly known as Maple Felix Energy Corporation) and the Company (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 authorisation to any one of the Directors, or any other person authorised 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 PSA 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 PSA or the transactions contemplated thereunder be and are hereby approved, ratified and confirmed.
(a) the Subscription Agreement dated May 31, 2017 (the ‘‘Subscription Agreement’’) entered into between CCGRF Gastown Limited, Maple Marathon Investments Limited, Mercuria Energy Netherlands BV, Canlin Energy Corporation (formerly known as Maple Felix Energy Corporation) and the Company (copy of which is produced to the EGM marked ‘‘B’’ and initialled 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

– EGM-1 –

NOTICE OF EGM

(b) the authorisation to any one of the Directors, or any other person authorised 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 Subscription 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 Subscription 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, September 7, 2017

Notes:

(a) 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 websites of Hong Kong Exchanges and Clearing Limited and the Company in accordance with the Listing Rules.
(b) 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.
(c) 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 adjournment thereof. 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.
(d) 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.
(e) For determining the entitlement to attend and vote at the meeting, the register of members of the Company will be closed from September 19, 2017 to September 22, 2017, 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 September 18, 2017.
(f) Time and dates in this notice are Hong Kong time and dates.

– EGM-2 –

NOTICE OF EGM

As at the date of this notice, the Board comprises (1) the executive Directors namely Mr. Zhang Ruilin, Mr. Zhao Jiangwei; (2) the non-executive Director namely Ms. Xie Na; and (3) the independent non-executive Directors namely Mr. Mei Jianping, Mr. Jeffrey W. Miller and Mr. Guo Yanjun.

– EGM-3 –

AI assistant

MIE Holdings Corporation — Proxy Solicitation & Information Statement 2017

49998_rns_2017-09-06_805e64d9-e0ff-47c2-81f0-e60747753c0c.pdf

MIE HOLDINGS CORPORATION MI 能 源 控 股 有 限 公 司

(I) VERY SUBSTANTIAL ACQUISITION IN RELATION TO THE PROPOSED ACQUISITION OF ALL THE PARTNERSHIP INTERESTS OF CQ ENERGY CANADA PARTNERSHIP AND

(II) MAJOR DISPOSAL IN RELATION TO THE DEEMED DISPOSAL OF 36.4% EQUITY INTEREST IN A WHOLLY-OWNED SUBSIDIARY

DEFINITIONS

DEFINITIONS

DEFINITIONS

‘‘Tangibles’’

MIE HOLDINGS CORPORATION MI 能 源 控 股 有 限 公 司

(Stock Code: 1555)

(I) VERY SUBSTANTIAL ACQUISITION

IN RELATION TO THE PROPOSED ACQUISITION OF ALL THE PARTNERSHIP INTERESTS OF CQ ENERGY CANADA PARTNERSHIP AND

(II) MAJOR DISPOSAL IN RELATION TO THE DEEMED DISPOSAL OF 36.4% EQUITY INTEREST IN A WHOLLY-OWNED SUBSIDIARY

INTRODUCTION

1. THE PSA

1.1. Date

1.2. Parties

1.3. Subject Matter

1.4. Consideration

1.5. Basis of Consideration

Comparable Transactions

1.6. Payment of the Deposit

LETTER FROM THE BOARD

1.7. Conditions Precedent

Purchaser’s Conditions

Vendors’ Conditions

1.8. Closing

1.9. Termination

2. THE SUBSCRIPTION AGREEMENT

2.1 Date

2.2 Parties

2.3 Subject Matter

2.4 Conditions precedent to the Subscription

2.5 Special rights and restrictions attached to the Common Shares and Convertible Preferred Shares

3. INFORMATION ON THE GROUP

4. INFORMATION OF THE VENDORS

5. INFORMATION ON THE SUBSCRIBERS

6. INFORMATION ON THE PURCHASER

6.1 Shareholding Structure of the Purchaser

6.2 Board of Directors of the Purchaser

7. INFORMATION ON THE TARGET GROUP

7.1 Target Company and its subsidiaries

7.2 Information on the production and reserves of the Target Group

7.3 Financial Information of the Target Group

Balance Sheet

Cash flow Statement

7.4 Litigation

8. REASONS FOR AND THE BENEFITS OF THE ACQUISITION

LETTER FROM THE BOARD

9. FINANCIAL EFFECTS OF THE ACQUISITION

10. WAIVER FROM STRICT COMPLIANCE WITH RULE 4.03 OF THE LISTING RULES

11. THE LISTING RULES IMPLICATIONS

LETTER FROM THE BOARD

12. RECOMMENDATIONS

13. ADDITIONAL INFORMATION

A. FINANCIAL INFORMATION OF THE GROUP FOR THE THREE YEARS ENDED DECEMBER 31, 2014, 2015 AND 2016

B. MANAGEMENT DISCUSSION AND ANALYSIS ON THE GROUP

(i) FOR THE YEAR ENDED DECEMBER 31, 2014

BUSINESS REVIEW AND PROSPECTS

Overview

REVIEW ON OPERATIONS BY SEGMENT

. China Operations

(2) Gas Projects (Shanxi Province: Linxing, Sanjiaobei)

. Kazakhstan Operations (Emir-Oil)

. USA Operations (Condor)

. Other Segment

FY2015 Guidance

FINANCIAL RESULTS

Revenue

. China

. Kazakhstan

(a) Crude oil sales

(b) Gas sales

Operating expenses

Rent export tax

Mineral extraction tax (‘‘MET’’)

Export duty

Property tax

MIE Holdings Corporation Proxy Solicitation & Information Statement 2017

MIE HOLDINGS CORPORATION MI 能源控股有限公司

MIE HOLDINGS CORPORATION MI 能源控股有限公司