20-F

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 20-F

[   ] REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2017

OR

[   ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ______ to ______

OR

[   ] SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Date of event requiring this shell company report:

Commission file number: 001-33491

DXI ENERGY INC.
(Exact name of Registrant as specified in its charter)

Province of British Columbia, Canada
(Jurisdiction of incorporation or organization)

520 - 999 Canada Place
Vancouver, British Columbia V6C 3E1
(Address of principal executive offices)

David N. Matheson
520 - 999 Canada Place
Vancouver, British Columbia V6C 3E1
Tel: (604) 638-5050
Facsimile: (604) 638-5051
(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of each exchange on which registered
Common Shares, without par value	OTCQB

Securities registered pursuant to Section 12(g) of the Act: None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

Indicate the number of outstanding shares of each of the Registrant’s classes of capital or common stock as of the close of the period covered by the annual report:
103,606,088 common shares as at December 31, 2017 and April 16, 2018

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes [   ]     No [X]

If this report is an annual or transition report, indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
Yes [   ]      No [X]

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes [X]     No [   ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes [X]     No [   ]

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one)

Large accelerated filer [   ] Accelerated filer [   ] Non-accelerated filer [X]

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP [   ]	International Financial Reporting Standards as issued
Other [   ]	by the International Accounting Standards Board [X]

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow:

Item 17 [   ]      Item 18 [   ]

If this is an annual report, indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [   ]     No [X]

TABLE OF CONTENTS

GENERAL INFORMATION		4
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS		4
CURRENCY AND EXCHANGE RATES		6
ABBREVIATIONS		7
PART I		8
ITEM 1.	IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS.	8
ITEM 2.	OFFER STATISTICS AND EXPECTED TIMETABLE	8
ITEM 3.	KEY INFORMATION	8
ITEM 4.	INFORMATION ON THE COMPANY	18
ITEM 4A.	UNRESOLVED STAFF COMMENTS	32
ITEM 5.	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	32
ITEM 6.	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES.	40
ITEM 7. .	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	49
ITEM 8.	FINANCIAL INFORMATION.	51
ITEM 9.	THE OFFER AND LISTING	52
ITEM 10.	ADDITIONAL INFORMATION	53
ITEM 11.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	70
ITEM 12.	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	72
PART II		73
ITEM 13.	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES	73
ITEM 14.	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS	73
ITEM 15.	CONTROLS AND PROCEDURES	73
ITEM 16.	[RESERVED]	74
ITEM 16A.	AUDIT COMMITTEE FINANCIAL EXPERT	74
ITEM 16B.	CODE OF ETHICS	74
ITEM 16C.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	74
ITEM 16D.	EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES	75
ITEM 16E.	PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PERSONS	75
ITEM 16F.	CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT	75
ITEM 16G.	CORPORATE GOVERNANCE	75
ITEM 16H.	MINE SAFETY DISCLOSURE	75
PART III		76
ITEM 17.	FINANCIAL STATEMENTS	76
ITEM 18.	FINANCIAL STATEMENTS	76
ITEM 19.	EXHIBITS	77
SIGNATURES		79

GENERAL INFORMATION

All references in this annual report on Form 20-F to the terms “we”, “our”, “us”, “the Company” and “DXI Energy” refer to DXI Energy Inc.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This annual report on Form 20-F and the documents incorporated herein by reference contain “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements concern our anticipated results and developments in our operations in future periods, planned exploration and, if warranted, development of our properties, plans related to our business and other matters that may occur in the future. These statements relate to analyses and other information that are based on forecasts of future results, estimates of amounts not yet determinable and assumptions of management.

Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as “expects” or “does not expect”, “is expected”, “anticipates” or “does not anticipate”, “plans”, “estimates” or “intends”, or stating that certain actions, events or results “may”, “could”, “would”, “might” or “will” be taken, occur or be achieved) are not statements of historical fact and may be forward-looking statements. The forward-looking statements contained in this annual report on Form 20-F concern, among other things:

• drilling inventory, drilling plans and timing of drilling, re-completion and tie-in of wells;

• productive capacity of wells, anticipated or expected production rates and anticipated dates of commencement of production;

• drilling, completion and facilities costs;

• results of our various projects;

• ability to lower cost structure in certain of our projects;

• our growth expectations;

• timing of development of undeveloped reserves;

• the performance and characteristics of the Company’s oil and natural gas properties;

• oil and natural gas production levels;

• the quantity of oil and natural gas reserves;

• capital expenditure programs;

• supply and demand for oil and natural gas and commodity prices;

• the impact of federal, provincial, and state governmental regulation on DXI Energy;

• expected levels of royalty rates, operating costs, general administrative costs, costs of services and other costs and expenses;

• expectations regarding our ability to raise capital and to continually add to reserves through acquisitions, exploration and development;

• treatment under governmental regulatory regimes and tax laws; and

• realization of the anticipated benefits of acquisitions and dispositions.

These statements relate to analyses and other information that are based on forecasts of future results, estimates of amounts not yet determinable and assumptions of our management.

4

Forward-looking statements are subject to a variety of known and unknown risks, uncertainties and other factors that could cause actual events or results to differ from those expressed or implied by the forward-looking statements, including, without limitation:

• risks related to the marketability and price of oil and natural gas being affected by factors outside our control;

• risks related to world oil and natural gas prices being quoted in U.S. dollars and our production revenues being adversely affected by an appreciation in the Canadian dollar;

• risks related to our ability to execute projects being dependent on factors outside our control;

• risks related to oil and gas exploration having a high degree of risk and exploration efforts failing;

• risks related to cumulative unsuccessful exploration efforts;

• risks related to oil and natural gas operations involving hazards and operational risks;

• risks related to seasonal factors and unexpected weather;

• risks related to competition in the oil and gas industry;

• risks related to the fact that we do not control all of the assets that are used in the operation of our business;

• risks related to our ability to market oil and natural gas depending on its ability to transport the product to market;

• risks related to high demand for drilling equipment;

• risks related to title to our properties;

• risks related to our ability to continue to meet its oil and gas lease or license obligations;

• risks related to our anticipated substantial capital needs for future oil and gas exploration, development and acquisitions;

• risks related to our cash flow from reserves not being sufficient to fund its ongoing operations;

• risks related to covenants in issued debt restricting the ability to conduct future financings;

• risks related to renewal or refinancing;

• risks related to our being exposed to third party credit risks;

• risks related to our being able to find, acquire, develop and commercially produce oil and natural gas;

• risks related to our properties not producing as projected;

• risks related to our estimated reserves being based upon estimates;

• risks related to future oil and gas revenues not resulting in revenue increases;

• risks related to our managing growth;

• risks related to our being dependent on key personnel;

• risks related to our reliance on strategic relationships;

• risks related to uncertainty regarding realization of planned completion/testing programs;

• risks related to our operations being subject to federal, state, local and other laws, controls and regulations;

• risks related to uncertainty regarding claims of title and right of aboriginal people;

• risks related to environmental laws and regulations;

• risks related to our being a public company;

• risks related to our being a foreign private issuer;

• risks related to our not having paid dividends to date; and

• risks related to our stock price being volatile.

5

This list is not exhaustive of the factors that may affect any of our forward-looking statements. Some of the important risks and uncertainties that could affect forward-looking statements are described further under the section heading “Item 3. Key Information – D. Risk Factors” below. If one or more of these risks or uncertainties materializes, or if underlying assumptions prove incorrect, our actual results may vary materially from those expected, estimated or projected. Forward-looking statements in this document are not a prediction of future events or circumstances, and those future events or circumstances may not occur. Given these uncertainties, users of the information included herein, including investors and prospective investors are cautioned not to place undue reliance on such forward-looking statements. Investors should consult our quarterly and annual filings with Canadian and U.S. securities commissions for additional information on risks and uncertainties relating to forward-looking statements. We do not assume responsibility for the accuracy and completeness of these statements.

Forward-looking statements are based on our beliefs, opinions and expectations at the time they are made, and we do not assume any obligation to update our forward-looking statements if those beliefs, opinions, or expectations, or other circumstances, should change, except as required by applicable law.

We qualify all the forward-looking statements contained in this annual report on Form 20-F by the foregoing cautionary statements.

CURRENCY AND EXCHANGE RATES

Canadian Dollars Per U.S. Dollar

Unless otherwise indicated, all references in this annual report are to Canadian dollars ("$" or "Cdn$"). Certain numbers in this annual report are rounded to the nearest thousands of Canadian dollars.

The following tables set forth the number of Canadian dollars required to buy one United States dollar (US$) based on the average, high and low nominal noon exchange rate as reported by the Bank of Canada for each of the last five fiscal years and each of the last six months. The average rate means the average of the exchange rates on the last day of each month during the period.

	Canadian Dollars Per One U.S. Dollar
	2017	2016	2015	2014	2013
Average for the period	1.2986	1.3248	1.2787	1.1045	1.0299

	March 2018	February 2018	January 2018	December 2017	November 2017	October 2017
High for the period	1.3088	1.2809	1.2535	1.2886	1.2888	1.2893
Low for the period	1.2830	1.2288	1.2293	1.2545	1.2683	1.2472

Exchange rates are based on the Bank of Canada nominal noon exchange rates. The nominal noon exchange rate on April 16, 2018 as reported by the Bank of Canada for the conversion of U.S. dollars into Canadian dollars was US$1.00 = Cdn$1.2579.

6

ABBREVIATIONS

Oil and Natural Gas Liquids		Natural Gas
bbl	barrel	Mcf	thousand cubic feet
bbls	barrels	MCFD	thousand cubic feet per day
BOPD	barrels per day	MMcf	million cubic feet
Mbbls	thousand barrels	MMcf/d	million cubic feet per day
Mmbtu	million British thermal units	Mcfe	Thousand cubic feet of gas equivalent

Other
AECO	Virtual pricing point for all natural gas delivered anywhere within the Province of Alberta on Trans- Canada’s pipeline system known as NOVA and traded under the provisions of the NOVA Inventory Transfer Service. Reported in Cdn$ per gigajoule
BOE	Barrels of oil equivalent. A barrel of oil equivalent is determined by converting a volume of natural gas to barrels using the ratio of 6 Mcf to one barrel.
BOE/D	Barrels of oil equivalent per day.
BCFE	Billion cubic feet equivalent.
MBOE	Thousand barrels of oil equivalent.
NYMEX	New York Mercantile Exchange.
WTI	West Texas Intermediate, the reference price paid in U.S. dollars at Cushing Oklahoma for crude oil of standard grade.

7

PART I

ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS

Not applicable.

ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE

Not applicable.

ITEM 3. KEY INFORMATION

A. Selected Financial Data

Our selected financial data and the information in the following tables for the years ended December 31, 2013 – 2017 was derived from our audited consolidated financial statements. These audited consolidated financial statements have been audited by BDO Canada LLP, Chartered Professional Accountants, for the years ended December 31, 2017, 2016, 2015, 2014, and 2013.

The information in the following table should be read in conjunction with the information appearing under the heading “Item 5. Operating and Financial Review and Prospects” and our audited consolidated financial statements under the heading "Item 18. Financial Statements".

The Company’s annual audited Consolidated Financial Statements have been prepared in accordance with IFRS, as issued by the International Accounting Standards Board (“IASB”) and interpretations of the International Financial Reporting Interpretations Committee (“IFRIC”).

We have not declared any dividends since incorporation and do not anticipate that we will do so in the foreseeable future. Our present policy is to retain all available funds for use in our operations and the expansion of our business.

The following table is a summary of selected audited consolidated financial information of the Company for each of the four most recently completed financial years. The information presented is presented in accordance with IFRS:

(CA$ thousands, except per share data)	Years Ended December 31,
	2017	2016	2015	2014	2013
Net Oil and Gas Revenue after royalties	$2,480	$4,073	$7,096	$7,561	$7,506
Net Loss for the Year	($5,209)	($5,486)	($7,108)	($7,203)	($2,577)
Loss Per Share	($0.08)	($0.13)	($0.19)	($0.20)	($0.10)
Dividends Per Share	Nil	Nil	Nil	Nil	Nil
Weighted Avg. Shares, basic (,000)	61,682	42,095	36,492	35,425	29,783
Weighted Avg. Shares, diluted (,000)	61,682	42,095	36,492	35,425	29,783
Year-end Shares (,000)	103,606	44,808	36,510	36,480	29,783
Working Capital (Deficiency)	($8,167)	($11,075)	($10,295)	($4,480)	($8,908)
Resource properties and equipment	$17,170	$20,182	$25,121	$21,016	$23,667
Long-term Liabilities	$7,121	$9,120	$8,552	$6,448	$6,107
Share Capital	$101,715	$98,111	$97,162	$97,132	$90,274
Retained Earnings (Deficit)	($115,845)	($110,636)	($105,150)	($98,042)	($90,839)
Total Assets	$18,809	$21,260	$27,686	$23,274	$25,499
Net Assets	$2,094	$1,546	$6,568	$10,385	$9,099

Exchange Rate History

See the disclosure under the heading "Currency and Exchange Rates" above.

8

Adoption of New and Amended Accounting Standards

There were no new or amended accounting standards or interpretations that had a significant impact on the Company’s consolidated financial statements during the year ended December 31, 2017.

B. Capitalization and Indebtedness

Not Applicable.

C. Reasons for the Offer and Use of Proceeds

Not Applicable.

D. Risk Factors

An investment in a company engaged in oil and gas exploration involves an unusually high amount of risk, both unknown and known, present and potential, including, but not limited to the risks enumerated below. An investment in our common shares is highly speculative and subject to a number of known and unknown risks. Only those persons who can bear the risk of the entire loss of their investment should purchase our securities. An investor should carefully consider the risks described below and the other information that we file with the Securities and Exchange Commission (“SEC”) and with Canadian securities regulators before investing in our common shares. The risks described below are not the only ones faced. Additional risks that we are not currently aware of or that we currently believe are immaterial may become important factors that affect our business. The risk factors set forth below and elsewhere in this annual report, and the risks discussed in our other filings with the SEC and Canadian securities regulators, may have a significant impact on our business, financial condition and/or results of operations and could cause actual results to differ materially from those projected in any forward-looking statements. See “Cautionary Note Regarding Forward-Looking Statements”.

Our failure to successfully address the risks and uncertainties described below would have a material adverse effect on our business, financial condition and/or results of operations, and the trading price of our common stock may decline and investors may lose all or part of their investment. We cannot assure you that we will successfully address these risks or other unknown risks that may affect our business.

Risks related to commodity price fluctuations

The marketability and price of oil and natural gas are affected by numerous factors outside of our control. Material fluctuations in oil and natural gas prices could adversely affect our net production revenue and oil and natural gas operations.

Prices for oil and natural gas may fluctuate widely 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 that are beyond our control, such as:

• the domestic and foreign supply of and demand for oil and natural gas;

• the price and quantity of imports of crude oil and natural gas;

• overall domestic and global economic conditions;

• political and economic conditions in other oil and natural gas producing countries, including embargoes and continued hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;

• the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

• the level of consumer product demand;

• weather conditions;

• the impact of the U.S. dollar exchange rates on oil and natural gas prices; and

• the price and availability of alternative fuels.

Our ability to market our oil and natural gas depends upon our ability to acquire space on pipelines that deliver such commodities to commercial markets. We are also affected by deliverability uncertainties related to the proximity of our reserves to pipelines and processing and storage facilities and operational problems affecting such pipelines and facilities, as well as extensive governmental regulation relating to price, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and many other aspects of the oil and natural gas business.

9

Both oil and natural gas prices are unstable and are subject to fluctuation. Any material decline in prices could result in a reduction of our net production revenue. The economics of producing from some wells may change as a result of lower prices, which could result in reduced production of oil or natural gas and a reduction in the volumes and net present value of our reserves. We might also elect not to produce from certain wells at lower prices. All of these factors could result in a material decrease in our net production revenue and a reduction in our oil and natural gas acquisition, development and exploration activities.

Because world oil and natural gas prices are quoted in U.S. dollars, our production revenues could be adversely affected by an appreciation of the Canadian dollar.

World oil and natural gas prices are quoted in U.S. dollars, and the price received by Canadian producers, including us, is therefore affected by the Canadian/U.S. dollar exchange rate, which will fluctuate over time and may affect our production revenues. Significant increases in the value of the Canadian dollar would exacerbate potential negative effect and could have a material adverse effect on our financial condition and results of operations. An increase in the exchange rate for the Canadian dollar and future Canadian/U.S. exchange rates could also negatively affect the future value of our reserves as determined by independent petroleum reserve engineers.

Risks related to operating an exploration, development and production company

Our ability to execute projects will depend on certain factors outside of our control. If we are unable to execute projects on time, on budget or at all, we may not be able to effectively market the oil and natural gas that we produce.

We manage a variety of small and large projects in the conduct of our business. Our ability to execute projects and market oil and natural gas will depend upon numerous factors beyond our control, including:

• the availability of adequate financing;

• the availability of processing capacity;

• the availability and proximity of pipeline capacity;

• the availability of storage capacity;

• the supply of and demand for oil and natural gas;

• the availability of alternative fuel sources;

• the effects of inclement weather;

• the availability of drilling and related equipment;

• accidental events;

• currency fluctuations;

• changes in governmental regulations; and

• the availability and productivity of skilled labor.

Because of these factors, we could be unable to execute projects on time, on budget or at all, and may not be able to effectively market the oil and natural gas that we produce.

Oil and gas exploration has a high degree of risk and our exploration efforts may be unsuccessful, which would have a negative effect on our operations.

There is no certainty that the expenditures to be made by us in the exploration of our current projects, or any additional project interests we may acquire, will result in discoveries of recoverable oil and gas in commercial quantities. An exploration project may not result in the discovery of commercially recoverable reserves and the level of recovery of hydrocarbons from a property may not be a commercially recoverable (or viable) reserve that can be legally and economically exploited. If exploration is unsuccessful and no commercially recoverable reserves are defined, we would be required to evaluate and acquire additional projects that would require additional capital, or we would have to cease operations altogether.

10

Cumulative unsuccessful exploration efforts could result in us having to cease operations.

The expenditures to be made by us in the exploration of our properties may not result in discoveries of oil and natural gas in commercial quantities. Many exploration projects do not result in the discovery of commercially recoverable oil and gas deposits, and this occurrence could ultimately result in us having to cease operations.

Oil and natural gas operations involve many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not fully insured, our business, financial condition, results of operations and prospects could be adversely affected.

Our involvement in the oil and natural gas exploration, development and production business subjects us to all of the risks and hazards typically associated with those types of operations, including hazards such as fire, explosion, blowouts, sour gas releases and spills, each of which could result in substantial damage to oil and natural gas wells, production facilities, other property and the environment or personal injury. In particular, we 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 us. In accordance with industry practice, we are not fully insured against all of these risks. Although we maintain liability insurance in an amount that we consider consistent with industry practice, the nature of these risks is such that liabilities could exceed policy limits, in which event we could incur significant costs that could have a material adverse effect upon our business, financial condition, results of operations and prospects. In addition, the risks we face are not, in all circumstances, insurable and, in certain circumstances, we may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. For instance, we do not have insurance to protect against the risk from terrorism. Oil and natural gas production operations are also subject to all of the risks typically associated with those operations, including encountering unexpected geologic 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 could have a material adverse effect on our business, financial condition, results of operations and prospects.

Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity.

The level of activity in the Canadian oil and natural gas industry is influenced by seasonal weather patterns. Oil and natural gas development activities, including seismic and drilling programs in northern Alberta and British Columbia, are restricted to those months of the year when the ground is frozen. Wet weather and spring thaw may make the ground unstable. Although not as prevalent, such conditions sometimes prevail in the Rocky Mountains of Colorado where the Company’s US properties are located. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. In addition, certain oil and natural gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain, and additional seasonal weather variations will also affect access to these areas. Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity during certain parts of the year.

The petroleum industry is highly competitive, and increased competitive pressures could adversely affect our business, financial condition, results of operations and prospects.

The petroleum industry is competitive in all of its phases. We compete with numerous other organizations in the search for, and the acquisition of, oil and natural gas properties and in the marketing of oil and natural gas. Our competitors include oil and natural gas companies that have substantially greater financial resources, staff and facilities than us. Our ability to increase our reserves in the future will depend not only upon our ability to explore and develop our present properties, but also upon our 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 and methods and reliability of delivery and storage.

We do not control all of the assets that are used in the operation of our business and, therefore, cannot ensure that those assets will be operated in a manner favorable to us.

Other companies operate some of the assets in which we have an interest. As a result, we have a limited ability to exercise influence over the operation of those assets or their associated costs, which could adversely affect our financial performance. Our return on assets operated by others will therefore depend upon a number of factors that may be outside of our control, including the timing and amount of capital expenditures, the operator's expertise and financial resources, the approval of other participants, the selection of technology and risk management practices.

11

Our ability to market oil and natural gas depends on our ability to transport our product to market. If we are unable to expand and develop the infrastructure in the areas surrounding certain of our assets, we may not be able to effectively market the oil and natural gas that we produce.

Due to the location of some of our assets, both in Canada and the United States, there is minimal infrastructure currently available to transport oil and natural gas from our existing and future wells to market. As a result, even if we are able to engage in successful exploration and production activities, we may not be able to effectively market the oil and natural gas that we produce, which could adversely affect our business, financial condition, results of operations and prospects.

Demand and competition for drilling equipment could delay our exploration and production activities, which could adversely affect our business, financial condition, results of operations and prospects.

Oil and natural gas exploration and development activities depend upon the availability of drilling and related equipment (typically leased from third parties) in the particular areas where such activities will be conducted. Demand for such limited equipment or access restrictions may affect the availability of such equipment to us and may delay exploration and development activities. To the extent we are not the operator of our oil and natural gas properties, we depend upon the operators of the properties for the timing of activities related to the properties and are largely unable to direct or control the activities of the operators.

Title to our oil and natural gas producing properties cannot be guaranteed and may be subject to prior recorded or unrecorded agreements, transfers, claims or other defects.

Although title reviews may be conducted prior to the purchase of oil and natural gas producing properties or the commencement of drilling wells, those reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat our claim. Unregistered agreements or transfers, or native land claims, may affect title. If title is disputed, we will need to defend our ownership through the courts, which would likely be an expensive and protracted process and have a negative effect on our operations and financial condition. In the event of an adverse judgment, we would lose our property rights. A defect in our title to any of our properties may have a material adverse effect on our business, financial condition, results of operations and prospects.

We may be unable to meet all of the obligations necessary to successfully maintain each of the licenses and leases and working interests in licenses and leases related to our properties, which could adversely affect our business, financial condition, results of operations and prospects.
Our properties are held in the form of licenses and leases and working interests in licenses and leases. If we or the holder of the license or lease fails to meet the specific requirement of a license or lease, the license or lease may terminate or expire. None of the obligations required to maintain each license or lease may be met. The termination or expiration of our licenses or leases or the working interests relating to a license or lease may have a material adverse effect on our business, financial condition, results of operations and prospects.

Risks related to financing continuing and future operations

We have a working capital deficiency and will be required to raise capital through financings. We may not be able to obtain capital or financing on satisfactory terms, or at all.

As of December 31, 2017, the Company had a working capital deficiency of approximately $8.2 million and an accumulated deficit of $115.8 million. Of this amount, $6.8 million is represented by a financial contract liability of Dejour USA, which was due on September 30, 2016. The maximum cash component due in full settlement of the financial contract liability is US$3.0 million. The details of the settlement progress are described in note 11 to the consolidated financial statements. We expect to incur general and administration expenses of approximately $1.5 million over the next twelve months. We cannot assure you that debt or equity financing will be available to us, and even if debt or equity financing is available, it may not be on terms acceptable to us. Our inability to access sufficient capital for our operations would have a material adverse effect on our business, financial condition, results of operations and prospects.

The Company's ability to continue as a going concern is dependent upon attaining profitable operations and obtaining sufficient financing to meet obligations and continue exploration and development activities. Whether and when the Company can attain profitability is uncertain. These uncertainties cast substantial doubt upon the Company’s ability to continue as going concern.

12

During the year ended December 31, 2017, the Company incurred a loss of $5.2 million and has an accumulated deficit of $115.8 million. Whether and when the Company can attain profitability is uncertain. The Company also has a working capital deficiency of $8.2 million as at December 31, 2017. These uncertainties cast substantial doubt upon the Company’s ability to continue as going concern in the next twelve months, because we will be required to obtain additional capital in the future to continue our operations and there is no assurance that we will be able to obtain such capital, through equity or debt financing, or any combination thereof, or on satisfactory terms or at all. Our independent auditors have included an explanatory paragraph in their report on our consolidated financial statements for the year ended December 31, 2017 that describes uncertainties that cast substantial doubt about our ability to continue as a going concern. Our audited consolidated financial statements have been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board applicable to a going concern, which implies we will continue to meet our obligations and continue our operations for the next twelve months. Realization values may be substantially different from carrying values as shown, and our consolidated financial statements do not include any adjustments relating to the recoverability or classification of recorded asset amounts or the amount and classification of liabilities that might be necessary as a result of the going concern uncertainty.

The Company’s stock was voluntarily delisted from the NYSE MKT at the close of trading on Thursday, August 4, 2016. Effective August 5, 2016, the Company’s stock was listed for trading on the OTCQB (“OTCQB”), in the United States, under the symbol of “DXIEF”.

We anticipate making substantial capital expenditures for future acquisition, exploration, development and production projects. We may not be able to obtain capital or financing necessary to support these projects on satisfactory terms, or at all.

We anticipate making substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future. If our revenues or reserves decline, we may not have access to the capital necessary to undertake or complete future drilling programs. Debt or equity financing, or cash generated by operations, may not be available to us or may not be sufficient to meet our requirements for capital expenditures or other corporate purposes. Even if debt or equity financing is available, it may not be on terms acceptable to us. Our inability to access sufficient capital for our operations could have a material adverse effect on our business, financial condition, results of operations and prospects.

Our cash flow from our reserves may not be sufficient to fund our ongoing activities at all times, thereby causing us to forfeit our interest in certain properties, miss certain acquisition opportunities and reduce or terminate our operations.

Our cash flow from our reserves may not be sufficient to fund our ongoing activities at all times and we are currently utilizing the loans from related parties to fund our working capital deficit. From time to time, we may require additional financing in order to carry out our oil and gas acquisition, exploration and development activities. Failure to obtain such financing on a timely basis could cause us to forfeit its interest in certain properties, not be able to take advantage of certain acquisition opportunities and reduce or terminate our level of operations. If our revenues from our reserves decrease as a result of lower oil and natural gas prices or otherwise, our ability to expend the necessary capital to replace our reserves or to maintain our production will be impaired. If our cash flow from operations is not sufficient to satisfy our capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or, if available, on favorable terms.

Debt that we incur in the future may limit our ability to obtain financing and to pursue other business opportunities, which could adversely affect our business, financial condition, results of operations and prospects.

From time to time, we may enter into transactions to acquire assets or equity of other organizations. These transactions may be financed in whole or in part with debt, which may increase our debt levels above industry standards for oil and natural gas companies of a similar size. Depending upon future exploration and development plans, we may require additional equity and/or debt financing that may not be available or, if available, may not be available on acceptable terms. None of our organizational documents currently limit the amount of indebtedness that we may incur. The level of our indebtedness from time to time could impair our ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise.

We may be exposed to the credit risk of third parties through certain of our business arrangements. Non-payment or non-performance by any of these third parties could have an adverse effect on our financial condition and results of operations.

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We may be exposed to third-party credit risk through our contractual arrangements with our current or future joint venture partners, marketers of our petroleum and natural gas production and other parties. In the event those entities fail to meet their contractual obligations to us, those failures could have a material adverse effect on our financial condition and results of operations. In addition, poor credit conditions in the industry and of joint venture partners may affect a joint venture partner's willingness to participate in our ongoing capital program, potentially delaying the program and the results of the program until we find a suitable alternative partner.

Risks related to maintaining reserves and acquiring new sources of oil and natural gas

Our success depends upon our ability to find, acquire, develop and commercially produce oil and natural gas, which depends upon factors outside of our control.

Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Our long-term commercial success depends upon our ability to find, acquire, develop and commercially produce oil and natural gas. We have only recently commenced production of oil and natural gas. There is no assurance that our other properties or future properties will achieve commercial production. Without the continual addition of new reserves, our existing reserves and our production will decline over time as our reserves are exploited. A future increase in our reserves will depend not only upon our ability to explore and develop any properties we may have from time to time, but also upon our ability to select and acquire new suitable producing properties or prospects. No assurance can be given that we will be able to locate satisfactory properties for acquisition or participation. Moreover, if acquisitions or participations are identified, we may determine that current market conditions, the terms of any acquisition or participation arrangement, or pricing conditions, may make the acquisitions or participations uneconomical, and further commercial quantities of oil and natural gas may not be produced, discovered or acquired by us, any of which could have a material adverse effect on our business, financial condition, results of operations and prospects.

Properties that we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.

Our long-term commercial success depends upon our ability to find, acquire, develop and commercially produce oil and natural gas reserves. However, our review of acquired properties is inherently incomplete, as it generally is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.

Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in the reserve estimates or the underlying assumptions may adversely affect the quantities and present value of our reserves.

There are numerous uncertainties inherent in estimating quantities of oil, natural gas reserves and the future cash flows attributed to the reserves. Our reserve and associated cash flow estimates are estimates only. In general, estimates of economically recoverable oil and natural gas reserves and the associated future net cash flows are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results. All estimates are to some degree speculative, and classifications of reserves are only attempts to define the degree of speculation involved. 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. Our actual production, revenues, taxes and development and operating expenditures with respect to our reserves will vary from our estimates of them, and those variations could be material.

Estimates of proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Recovery factors and drainage areas are 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, and those variations could be material.

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Our future oil and natural gas production may not result in revenue increases and may be adversely affected by operating conditions, production delays, drilling hazards and environmental damages.

Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees.

Risks related to management of the Company

We may experience difficulty managing our anticipated growth.

We may be subject to growth-related risks including capacity constraints and pressure on our internal systems and controls. Our ability to manage growth effectively will require us to continue to implement and improve our operational and financial systems and to attract and retain qualified management and technical personnel to meet the needs of our anticipated growth. Our inability to deal with this growth could have a material adverse effect on our business, financial condition, results of operations and prospects.

We depend upon key personnel and the absence of any of these individuals could result in us having to cease operations.

Our ability to continue our operation business depends, in large part, upon our ability to attract and maintain qualified key management and technical personnel. Competition for such personnel is intense and we may not be able to attract and retain such personnel.

Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations.

Our ability to successfully acquire additional licenses, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements depends on developing and maintaining close working relationships with industry participants and government officials and on our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to undertake in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

We cannot be certain that current expected expenditures and any current or planned completion/testing programs will be realized.

We believe that the costs used to prepare internal budgets are reasonable, however, there are assumptions, uncertainties, and risk that may cause our allocated funds on a per well basis to change as a result of having to alter certain activities from those originally proposed or programmed to reduce and mitigate uncertainties and risks. These assumptions, uncertainties, and risks are inherent in the completion and testing of wells and can include but are not limited to: pipe failure, casing collapse, unusual or unexpected formation pressure, environmental hazards, and other operating or production risk intrinsic in oil and or gas activities. Any of the above may cause a delay in any of our completion/testing programs or our ability to determine reserve potential.

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Risks related to federal, state, local and other laws, controls and regulations

We are subject to complex federal, provincial, state, local and other laws, controls and regulations that could adversely affect the cost, manner and feasibility of conducting our oil and natural gas operations.

Oil and natural gas exploration, production, marketing and transportation activities are subject to extensive controls and regulations imposed by various levels of government, which may be amended from time to time. Governments may regulate or intervene with respect to price, taxes, royalties and the exportation of oil and natural gas. Regulations may be changed from time to time in response to economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for crude oil and natural gas and increase our costs, any of which may have a material adverse effect on our business, financial condition, results of operations and prospects. In addition, in order to conduct oil and natural gas operations, we require licenses from various governmental authorities. We cannot assure you that we will be able to obtain all of the licenses and permits that may be required to conduct operations that we may desire to undertake.

There is uncertainty regarding claims of title and rights of the aboriginal people to properties in certain portions of western Canada, and such a claim, if made in respect of our property or assets, could adversely affect our business, financial condition, results of operations and prospects.

Aboriginal peoples have claimed aboriginal title and rights in portions of Western Canada. We are not aware that any claims have been made in respect of our properties and assets. However, if a claim arose and was successful, such claim may have a material adverse effect on our business, financial condition, results of operations and prospects. In addition, the process of addressing such claims, regardless of outcome, is expensive and time consuming and could result in delays which could have a material adverse effect on our business and financial results.

We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities, which could adversely affect our business, financial condition, results of operations and prospects.

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation under a variety of federal, provincial, state and local laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and natural gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with legislation can require significant expenditures, and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy any discharge. Environmental laws may result in a curtailment of production or a material increase in the costs of production, development or exploration activities, or otherwise adversely affect our business, financial condition, results of operations and prospects.

As a public company, our compliance costs and risks have increased in recent years.

Legal, accounting and other expenses associated with public company reporting requirements have increased significantly in the past few years. We anticipate that general and administrative costs associated with regulatory compliance will continue to increase with on-going compliance requirements under the Sarbanes-Oxley Act of 2002, as well as any new rules implemented by the SEC, Canadian Securities Administrators, the Toronto Stock Exchange and the Over-The-Counter Market (“OTC MKT”) in the future. These rules and regulations have significantly increased our legal and financial compliance costs and made some activities more time-consuming and costly. We cannot assure you that we will continue to effectively meet all of the requirements of these regulations, including Section 404 of the Sarbanes-Oxley Act and National Instrument 52-109 of the Canadian Securities Administrators. Any failure to effectively implement internal controls, or to resolve difficulties encountered in their implementation, could harm our operating results, cause us to fail to meet reporting obligations, or result in our principal executive officer and principal financial officer being required to give a qualified assessment of our internal control over financial reporting. Any such result could cause investors to lose confidence in our reported financial information, which could have a material adverse effect on the trading price of our common shares and our ability to raise capital. These rules and regulations have made it more difficult and more expensive for us to obtain director and officer liability insurance, and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage in the future. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers.

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Risks Related to Our Being a Foreign Private Issuer

As a foreign private issuer, our shareholders may receive less complete and timely data.

We are a “foreign private issuer” as defined in Rule 3b-4 under the United States Securities Exchange Act of 1934. Our equity securities are accordingly exempt from Sections 14(a), 14(b), 14(c), 14(f) and 16 of the Exchange Act, pursuant to Rule 3a12-3 of the Exchange Act. Therefore, we are not required to file a Schedule 14A proxy statement in relation to our annual meetings of shareholders. The submission of proxy and annual meeting of shareholder information on Form 6-K may result in shareholders having less complete and timely information in connection with shareholder actions. The exemption from Section 16 rules regarding reports of beneficial ownership and purchases and sales of common shares by insiders and restrictions on insider trading in our securities may result in shareholders having less data and there being fewer restrictions on insiders’ activities in our securities.

It may be difficult to enforce judgments or bring actions outside the United States against us and certain of our directors and officers.

It may be difficult to bring and enforce suits against us. We are incorporated in British Columbia, Canada. Many of our directors and officers are not residents of the United States and some of our assets are located outside of the United States. As a result, it may be difficult for U.S. holders of our common shares to effect service of process on these persons within the United States or to enforce judgments obtained in the U.S. based on the civil liability provisions of the U.S. federal securities laws against us or our officers and directors. In addition, a shareholder should not assume that the courts of Canada (i) would enforce judgments of U.S. courts obtained in actions against us or our officers or directors predicated upon the civil liability provisions of the U.S. federal securities laws or other laws of the United States, or (ii) would enforce, in original actions, liabilities against us or our officers or directors predicated upon the U.S. federal securities laws or other laws of the United States.

Risks related to investing in our common shares

We have not paid any dividends on our common shares. Consequently, your only opportunity currently to achieve a return on your investment will be if the market price of our common shares appreciates above the price that you pay for our common shares.

We have not declared or paid any dividends on our common shares since our incorporation. Any decision to pay dividends on our common shares will be made by our board of directors on the basis of our earnings, financial requirements and other conditions existing at such future time. Consequently, your only opportunity to achieve a return on your investment in our securities will be if the market price of our common shares appreciates and you are able to sell your common shares at a profit.

Our common share price has been volatile and your investment in our common shares could suffer a decline in value.

Our common shares are traded on the Toronto Stock Exchange and the OTCQB. The market price of our common shares may fluctuate significantly in response to a number of factors, some of which are beyond our control. These factors include price fluctuations of precious metals, government regulations, disputes regarding mining claims, broad stock market fluctuations and economic conditions in the United States.

Dilution through officer, director, employee, consultant or agent options could adversely affect our shareholders.

Because our success is highly dependent upon our officers, directors, employees, consultants and agents, we have granted to some or all of our key officers, directors, employees, consultants and agents options to purchase common shares as non-cash incentives. To the extent that we grant significant numbers of options and those options are exercised, the interests of our other shareholders may be diluted.

The issuance of additional common shares may negatively affect the trading price of our common shares.

We have issued equity securities in the past and may continue to issue equity securities to finance our activities in the future, including to finance future acquisitions, or as consideration for acquisitions of businesses or assets. In addition, outstanding options and warrants to purchase our common shares may be exercised, resulting in the issuance of additional common shares. The issuance by us of additional common shares would result in dilution to our shareholders, and even the perception that such an issuance may occur could have a negative effect on the trading price of our common shares.

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ITEM 4. INFORMATION ON THE COMPANY

A. History and Development of the Company

Introduction

Our executive office is located at Suite 520, 999 Canada Place, Vancouver, British Columbia, Canada V6C 3E1; telephone: (604) 638-5050 and facsimile: (604) 638-5051. The contact person is: Mr. Robert L. Hodgkinson, Co-Chairman and Chief Executive Officer (email: rhodgkinson@dxienergy.com) or Mr. David Matheson, Chief Financial Officer (email: dmatheson@dxienergy.com).

Our common shares are traded on the Toronto Stock Exchange under the symbol “DXI” in Canada and the OTCQB Marketplace (“OTCQB”) under the symbol “DXIEF” in the U.S.

Our authorized capital consists of three classes of shares: an unlimited number of common voting shares; an unlimited number of preferred shares designated as First Preferred Shares, issuable in series; and an unlimited number of preferred shares designated as Second Preferred Shares, issuable in series. There are no indentures or agreements limiting the payment of dividends and there are no conversion rights, special liquidation rights, pre-emptive rights or subscription rights.

The First Preferred Shares have priority over the Common Shares and the Second Preferred Shares with respect to the payment of dividends and in the distribution of assets in the event of a winding up of DXI Energy. The Second Preferred Shares have priority over the Common Shares with respect to dividends and surplus assets in the event of a winding up of DXI Energy.

As of December 31, 2017, there were 103,606,088 common shares issued and outstanding. As of December 31, 2017, there were no First Preferred Shares and no Second Preferred Shares issued and outstanding.

Incorporation and Name Changes

DXI Energy Inc. is incorporated under the laws of British Columbia, Canada. On June 29, 2015, the Company’s shareholders approved the consolidation of its issued and outstanding common shares on the basis of one (1) post-consolidation common share for every five (5) pre-consolidation common shares. On October 27, 2015, the Company changed its name from Dejour Energy Inc. to DXI Energy Inc. and effected a five-to-one share consolidation of its common shares. The Company began trading on a post-consolidation basis on October 30, 2015.

Financings

We have financed our operations through funds from related party loans, public/private placements of common shares, issuance of flow-through shares, common shares issued in debt settlements, and shares issued upon exercise of stock options. The following table summarizes our financings for the past three fiscal years.

Fiscal Year	Nature of Share Issuance	Number of Shares	Gross Proceeds (Cdn$)
2017	Private Placement (1)	14,371,831	1,170,000
2017	Private Placement (2)	44,425,971	2,687,000
2016	Private Placement (3)	8,298,333	995,800
2015	Exercise of Options	29,898	23,000

⁽¹⁾ In December 2017, the Company completed a private placement and 8,633,166 common shares were issued at a price of $0.075 per share for gross proceeds of $647,000 and an additional 5,738,665 flow-through shares were issued for gross proceeds of $523,000 (5,091,165 at $0.09 per share and 647,500 at $0.10 per share). The Company paid finders’ fees of $51,000 and other costs of $24,000 related to this offering. 946,667 of the common shares were issued at $0.075 per share to certain creditors of the Company to settle the amounts owing to them.

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(2)

In October 2017, the Company completed a private placement and 42,297,400 common shares were issued at a price of $0.06 per share for gross proceeds of $2,538,000 and additional 2,128,571 flow-through shares were issued at a price of $0.07 per share for gross proceeds of $149,000. The Company paid finders’ fees of $41,000 and other costs of $23,000 related to this offering. 21,924,067 of the common shares were issued at $0.06 per share to Directors and Officers of the Company (17,967,644) and certain creditors of the Company (3,956,423) to settle the amounts owing to them.

(3)

In June and July 2016, the Company completed a dual tranche private placement and 8,298,333 common shares were issued at a price of $0.12 per share for total gross proceeds of $995,800. The Company paid finders’ fees of $18,000 and other costs of $29,000 related to this offering. Directors and Officers of the Company purchased 3,600,000 common shares of this offering.

Past Capital Expenditures

Fiscal Year	Cash flows used for equipment and resource properties
2017	Cdn$456,000 (1)
2016	Cdn$530,000 (2)
2015	Cdn$5,738,000 (3)

(1)	$5,000 of these funds was spent on the purchase of corporate and other assets; and $451,000 was spent on our resource properties. (For a breakdown on the resource property expenditures, see Notes 5 and 6 to our audited consolidated financial statements for the fiscal year ended December 31, 2017, filed with this annual report on Form 20-F.)
(2)	$3,000 of these funds was spent on the purchase of corporate and other assets; and $527,000 was spent on our resource properties. (For a breakdown on the resource property expenditures, see Notes 5 and 6 to our audited consolidated financial statements for the fiscal year ended December 31, 2016, filed with this annual report on Form 20-F.)
(3)	$1,000 of these funds was spent on the purchase of corporate and other assets; and $5,737,000 was spent on our resource properties. (For a breakdown on the resource property expenditures, see Notes 5 and 6 to our audited consolidated financial statements for the fiscal year ended December 31, 2015, filed with this annual report on Form 20-F.)

Capital Expenditures

DXI Energy is committed to future growth through its strategy to implement a full-cycle exploration and development program, augmented by strategic acquisitions with exploitation upside.

During the year ended December 31, 2017, the Company incurred $0.4 million to conduct the seismic studies and exploration work for the upcoming drilling program at its Woodrush properties, north of Fort St. John, British Columbia. In the U.S., the Company paid $42,000 for the ongoing Kokopelli development program in Colorado.

During the year ended December 31, 2016, the Company incurred $0.3 million for the workover related to one water disposal well at its Woodrush properties, north of Fort St. John, British Columbia. In the U.S., the Company paid $0.2 million for the ongoing Kokopelli development program in Colorado.

During the year ended December 31, 2015, the Company incurred $1.0 million to complete and tie into production the 2 infill wells that were drilled in 2015 at its Woodrush properties, north of Fort St. John, British Columbia. In the U.S., the Company paid $4.5 million to drill, case and complete its 25% working interest share of eight natural gas wells at Kokopelli in Colorado and complete a salt water disposal facility.

Additions to property and equipment and exploration and evaluation assets:

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	Year ended December 31, 2017		Year ended December 31, 2016
(CA$ thousands)	$	% of total	$	% of total	% change
Land acquisition and retention	54	11.8%	40	7.5%	35%
Drilling and completion	120	26.3%	331	62.5%	-64%
Facility and pipelines	19	4.2%	-	0.0%	100%
Geological and geophysical	235	51.5%	-	0.0%	100%
Capitalized general and administrative	23	5.0%	159	30.0%	-86%
Other assets	5	1.1%	-	0.0%	100%
Total	456	100.0%	530	100.0%	-14%

Daily Production

	Three months ended December 31,		Year ended December 31,
	2017	2016	2017	2016
By Product
Oil and natural gas liquids (bbls/d)	89	106	82	209
Natural gas (mcf/d)	832	1,327	1,145	1,666
Total (boe/d)	228	327	273	487

The decrease in oil production for the three and twelve months ended December 31, 2017 reflects the natural decline in oil production and increase in water cut associated with Halfway formation waterfloods of the Woodrush type in northeastern British Columbia.

The decrease in natural gas production for the three and twelve months ended December 31, 2017 reflects the natural decline in natural gas production at Kokopelli in Colorado combined with the deliberate shut-in of certain low netback gas production at Woodrush in the 2^nd half of 2017.

B. Business Overview

General

The Company is in the business of acquiring, exploring and developing energy projects with a focus on oil and gas exploration in Canada and the United States.

The Company holds approximately 37,400 net acres of oil and gas leases in the following regions:

• The Peace River Arch of northeastern British Columbia and northwestern Alberta, Canada

• The Piceance, Paradox and Uinta Basins in the US Rocky Mountains

Summary

Over the past few years, the Company has continued to develop its Halfway oilfield in northeastern British Columbia, Canada while evaluating its exploration prospects in the Piceance Basin with the intent of developing drillable prospects of merit at the earliest possible opportunity. This process involved several distinct steps:

• Classification and prioritization of acreage based on economic promise, technical robustness, infrastructural and logistic advantage and commercial maturity

• Evaluation and development planning for top tier acreage positions

• Developing partnerships within financial and industry circles to speed the exploitation process, and

• Aggressively bringing production on line where feasible

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As a result of this process, the Company’s assets in Canada and the Piceance basin have moved to a higher weighting of lower risk development projects as opposed to higher risk exploration projects.

Our business objective is to grow our oil and gas production and generate sufficient cash flow to continue to expand company operations and enhance shareholder value.

Specialized Skill and Knowledge: Exploration for and development of petroleum and natural gas resources requires specialized skills and knowledge including in the areas of petroleum engineering, geophysics, geology and title. The Company and its subsidiaries have obtained personnel with the required specialized skills and knowledge to carry out their respective operations. While the current labour market in the industry is highly competitive, the Company expects to be able to attract and maintain appropriately qualified employees for fiscal 2018.

Cycles: All of the Company's operations in Canada are affected by seasonal operating conditions. Dejour Energy (Alberta) Ltd. holds properties in northwestern Alberta and northeastern British Columbia which are accessible to heavy equipment in winter only when the ground is frozen, typically between December to early April. For this reason, drilling and pipeline construction ceases over the remainder of the year, limiting growth to winter only. Production operations continue year round in these areas once production is established. The prices that the Company will receive for oil and gas production in the future are weighted to world benchmark prices and may be adversely affected by weather conditions and transportation restrictions. Following the two-year downturn in the oil and gas industry, the oil prices have recovered to approximately US$60.00 per barrel as at December 31, 2017 while natural gas prices paid to producers remain relatively “soft” in the Cdn$2.00 to Cdn$3.00/mcf range.

Commodity price cycles are also affected by world industrial supply and demand, domestic and international commodity transportation systems, and political factors affecting construction of pipelines and exports of controversial commodities like liquid natural gas. See "Risk Factors – Risks related to operating an exploration, development and production company".

Environmental Protection: The Company's operations are subject to environmental regulations (including regular environmental impact assessments and permitting) in the jurisdictions in which it operates. Such regulations cover a wide variety of matters, including, without limitation, emission of greenhouse gases, prevention of waste, pollution and protection of the environment, labour regulations and worker safety. Under such regulations there are preventative obligations, clean-up costs and liabilities for toxic or hazardous substances which may exist on or under any of its properties or which may be produced as a result of its operations. Environmental legislation and legislation relating to exploration and production of oil and natural gas will require stricter standards and enforcement, increased fines and penalties for non-compliance, more stringent environmental assessments of proposed projects and a heightened degree of responsibility for companies and their directors and employees. Such stricter standards could impact the Company's costs and have an adverse effect on results of operations. The Company expects to incur abandonment and site reclamation costs as existing oil and gas properties are abandoned and reclaimed; however, the Company does not anticipate making material expenditures beyond normal compliance with environmental regulations in 2018 and future years.

Employees: The Company had the equivalent of approximately 10 full-time employees and consultants during 2017.

Social or Environmental Policies: The health and safety of employees, contractors and the public, as well as the protection of the environment, is of utmost importance to the Company. The Company endeavors to conduct its operations in a manner that will minimize adverse effects of emergency situations by:

• complying with government regulations and standards;

• following industry codes, practices and guidelines;

• ensuring prompt, effective response and repair to emergency situations and environmental incidents; and

• educating employees and contractors of the importance of compliance with corporate safety and environmental rules and procedures.

The Company believes that all Company personnel have a vital role in achieving excellence in environmental, health and safety performance. This is best achieved through careful planning and the support and active participation of everyone involved.

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Competitive Conditions: The Company operates in geographical areas where there is strong competition by other companies for reserve acquisitions, exploration leases, licences and concessions and skilled industry personnel. The Company’s competitors include major integrated oil and natural gas companies and numerous other independent oil and natural gas companies and individual producers and operators, many of whom have greater financial and personnel resources than the Company. The Company’s ability to acquire additional property rights, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers is dependent upon developing and maintaining close working relationships with its current industry partners and joint operators, and its ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment.

Three Year History

2017

During the year ended December 31, 2017, the Company:

1.	Reduced financing expenses by 34% to $1,039,000 from $1,579,000 for the comparative year ended December 31, 2016 as a result of refinancing the Company’s loans from related parties;
2.	Raised gross proceeds of $3,857,000 in equity, of which $2,471,000 is cash, under challenging market conditions, allowing the Company to support the ongoing development of its Drake/Woodrush properties. Of the non-cash portion of equity, $1,078,000 represented the exchange of related party debt for the Company’s shares while $308,000 represented the exchange of other debt amounts held by arm’s length parties for the Company’s shares; and
3.	On December 22, 2017, the Company signed a “Funding and Participation Agreement” (“the Agreement”) with a private U.S. based investment firm to underwrite 50% of the capital costs of at least one exploration well at its Woodrush properties in Canada, currently scheduled to commence in the 1st quarter of 2018. Under the terms of the Agreement, the investment firm will pay approximately two-thirds of the total costs of the first well of the 2018 program, through tie in, to earn a 15% Gross Overriding Royalty (“GORR”). The investment firm has the right to elect to participate in the drilling and completion of a 2nd and subsequent wells, if any, by paying 50% of the capital costs to earn a 15% GORR in the well spacing unit on a well-by-well basis.

2016

During the year ended December 31, 2016, the Company:

1.	Retired the Company’s bank loan and related credit facility with a Canadian bank;
2.	Completed a $995,800 private placement;
3.	Decreased G&A expenses for the year ended December 31, 2016 by $675,000 (30%) to $1.6 million in response to a 24% decrease in average realized prices per BOE from 2015 to 2016; and
4.	Decreased the loss for the year ended December 31, 2016 to $5.5 million from $7.1 million for the comparative period ended December 31, 2015.

2015

During the year ended December 31, 2015, the Company:

1.	Successfully completed and tied into production two new wells at the Company’s Woodrush property, north of Fort St. John, British Columbia;
2.	Completed the drilling, casing and completion of eight natural gas wells in the Company’s Kokopelli development project in Colorado. Production from the eight natural gas wells was commenced in the 4th quarter of 2015. The Company has a 25% working interest in this project;

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3.	Secured $6.5 million in bridge financing from a company controlled by a Director and Officer ($4.5 million) and from a company associated with the Director and Officer ($2.0 million). Extended the maturity date of $6.5 million bridge financing from December 31, 2015 to November 30, 2018;
4.	Increased oil and natural gas production by 48% to 663 BOE/d from 449 BOE/d for the comparative year ended December 31, 2014;
5.	Reduced operating and transportation expenses for oil operations from $27.65/bbl for the year ended December 31, 2014 to $13.39/bbl for the year ended December 31, 2015; and
6.	Reduced G&A expenses per BOE by 56% to $9.28 per BOE from $21.31 per BOE for the comparative year ended December 31, 2014.

United States vs. Foreign Sales/Assets

Net Revenue for fiscal year ended:	Canada	United States
(Cdn$ in 000)	$	$
12/31/2015	6,606	490
12/31/2016	3,190	883
12/31/2017	1,814	666

Asset Location as of:	Canada	United States
(Cdn$ in 000)	$	$
12/31/2015	7,965	19,721
12/31/2016	5,639	15,621
12/31/2017	4,998	13,811

Commodity Price Environment

Generally, the demand for, and the price of, natural gas increases during the colder winter months and decreases during the warmer summer months. Pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Crude oil and the demand for heating oil are also impacted by seasonal factors, with generally higher prices in the winter. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations.

Our results of operations and financial condition are significantly affected by oil and natural gas commodity prices, which can fluctuate dramatically. The market for oil and natural gas is beyond our control and prices are difficult to predict. (See also ‘Trend Information’ under item 5 ‘Operating and Financial Review and Prospects’)

Forward Contracts

The Company is not bound by an agreement (including any transportation agreement) directly or through an aggregator, under which it may be precluded from fully realizing, or may be protected from the full effect of, future market prices for oil and gas. The Company had no forward commodity contracts in place at December 31, 2017.

Additional Information Concerning Abandonment and Reclamation Costs

For the Company’s Canadian and US oil and gas interests, the well abandonment costs for all wells with reserves have been included at the property level. The Company estimated the total undiscounted amount of the cash flows required to settle the decommissioning liabilities as at December 31, 2017 to be approximately $3,971,000. These obligations are expected to be settled over the next 15 years with the majority of costs incurred between 2018 and 2032.

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Government Regulations

Our oil and natural gas exploration, production and related operations, when developed, are subject to extensive laws and regulations promulgated by federal, state, tribal and local authorities and agencies. These laws and regulations often require permits for drilling operations, drilling bonds and reports concerning operations, and impose other requirements relating to the exploration for and production of oil and natural gas. Many of the laws and regulations govern the location of wells, the method of drilling and casing wells, the plugging and abandoning of wells, the restoration of properties upon which wells are drilled, temporary storage tank operations, air emissions from flaring, compression, the construction and use of access roads, sour gas management and the disposal of fluids used in connection with operations.

Our operations are subject to environmental regulations (including regular environmental impact assessments and permitting) in the jurisdictions in which it operates. Such regulations cover a wide variety of matters, including, without limitation, emission of greenhouse gases, prevention of waste, pollution and protection of the environment, labour regulations and worker safety. Under such regulations there are preventative obligations, clean-up costs and liabilities for toxic or hazardous substances which may exist on or under any of its properties or which may be produced as a result of its operations. Environmental legislation and legislation relating to exploration and production of oil and natural gas will require stricter standards and enforcement, increased fines and penalties for non-compliance, more stringent environmental assessments of proposed projects and a heightened degree of responsibility for companies and their directors and employees. Such stricter standards could impact our costs and have an adverse effect on results of operations.

The Comprehensive Environmental, Response, Compensation, and Liability Act, or CERCLA, and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of "hazardous substances" found at such sites. It is not uncommon for the government to file claims requiring cleanup actions, demands for reimbursement for government-incurred cleanup costs, or natural resource damages, or for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. The Federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes govern the disposal of "solid waste" and "hazardous waste" and authorize the imposition of substantial fines and penalties for noncompliance, as well as requirements for corrective actions. Although CERCLA currently excludes petroleum from its definition of "hazardous substance," state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum-related products. In addition, although RCRA classifies certain oil field wastes as "non-hazardous," such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements. CERCLA, RCRA and comparable state statutes can impose liability for clean-up of sites and disposal of substances found on drilling and production sites long after operations on such sites have been completed. Other statutes relating to the storage and handling of pollutants include the Oil Pollution Act of 1990, or OPA, which requires certain owners and operators of facilities that store or otherwise handle oil to prepare and implement spill response plans relating to the potential discharge of oil into surface waters. The OPA, contains numerous requirements relating to prevention of, reporting of, and response to oil spills into waters of the United States. State laws mandate oil cleanup programs with respect to contaminated soil. A failure to comply with OPA's requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions.

The Endangered Species Act, or ESA, seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, or destroy or modify the critical habitat of such species. Under the ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat. The ESA has been used to prevent or delay drilling activities and provides for criminal penalties for willful violations of its provisions. Other statutes that provide protection to animal and plant species and that may apply to our operations include, without limitation, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act. Although we believe that our operations are in substantial compliance with these statutes, any change in these statutes or any reclassification of a species as threatened or endangered or re-determination of the extent of "critical habit" could subject us to significant expenses to modify our operations or could force us to discontinue some operations altogether.

The National Environmental Policy Act, or NEPA, requires a thorough review of the environmental impacts of "major federal actions" and a determination of whether proposed actions on federal and certain Indian lands would result in "significant impact." For purposes of NEPA, "major federal action" can be something as basic as issuance of a required permit. For oil and gas operations on federal and certain Indian lands or requiring federal permits, NEPA review can increase the time for obtaining approval and impose additional regulatory burdens on the natural gas and oil industry, thereby increasing our costs of doing business and our profitability.

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The Clean Water Act, or CWA, and comparable state statutes, impose restrictions and controls on the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the Environmental Protection Agency (EPA) or an analogous state agency. The CWA regulates storm water run-off from oil and natural gas facilities and requires a storm water discharge permit for certain activities. Such a permit requires the regulated facility to monitor and sample storm water run-off from its operations. The CWA and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release.

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing as part of our operations. The process is typically regulated by state oil and natural gas commissions but the EPA has asserted federal regulatory authority pursuant to the Safe Water Drinking Act, or SDWA, over certain hydraulic fracturing activities involving the use of diesel. In addition, in May, 2014, the EPA issued an Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing operations under Section 8 of the Toxic Substance Control Act. To date, no other action has been taken. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting disclosure, and well construction requirements on hydraulic fracturing activities.

We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate (primarily the State of Colorado at present), we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

The Clean Air Act, as amended, restricts the emission of air pollutants from many sources, including oil and gas operations. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to remain in compliance. In addition, the EPA has promulgated more stringent regulations governing emissions of toxic air pollutants from sources in the oil and gas industry, and these regulations may increase the costs of compliance for some facilities.

Significant studies and research have been devoted to climate change and global warming, and climate change has developed into a major political issue in the United States and globally. Certain research suggests that greenhouse gas emissions contribute to climate change and pose a threat to the environment. Recent scientific research and political debate has focused in part on carbon dioxide and methane incidental to oil and natural gas exploration and production. Many state governments have enacted legislation directed at controlling greenhouse gas emissions, and future state and federal legislation and regulation could impose additional restrictions or requirements in connection with our operations and favor use of alternative energy sources, which could increase operating costs and demand for oil products. As such, our business could be materially adversely affected by domestic and international legislation targeted at controlling climate change.

We expect to incur abandonment and site reclamation costs as existing oil and gas properties are abandoned and reclaimed; however, we do not anticipate making material expenditures beyond normal compliance with environmental regulations in 2018 and future years.

The health and safety of employees, contractors and the public, as well as the protection of the environment, is of utmost importance to us. We endeavour to conduct our operations in a manner that will minimize adverse effects of emergency situations by:

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• complying with government regulations and standards;

• following industry codes, practices and guidelines;

• ensuring prompt, effective response and repair to emergency situations and environmental incidents; and

• educating employees and contractors of the importance of compliance with corporate safety and environmental rules and procedures.

We believe that all of our personnel have a vital role in achieving excellence in environmental, health and safety performance. This is best achieved through careful planning and the support and active participation of everyone involved.

Competition

We operate in geographical areas where there is strong competition by other companies for reserve acquisitions, exploration leases, licences and concessions and skilled industry personnel. Our competitors include major integrated oil and natural gas companies and numerous other independent oil and natural gas companies and individual producers and operators, many of whom have greater financial and personnel resources than us. Our ability to acquire additional property rights, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers is dependent upon developing and maintaining close working relationships with its current industry partners and joint operators, and its ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment.

We compete with many companies possessing greater financial resources and technical facilities for the acquisition of oil and gas properties, exploration and production equipment, as well as for the recruitment and retention of qualified employees.

Seasonality

The Company’s core operations are in Canada and they are affected by seasonal operating conditions. Dejour Energy (Alberta) Ltd., its wholly owned subsidiary, holds properties in northwestern Alberta and northeastern British Columbia which are accessible to heavy equipment in winter only when the ground is frozen, typically between December to early April. For this reason drilling and pipeline construction ceases over the remainder of the year, limiting growth to winter only. Production operations continue year round in these areas once production is established. The prices that we will receive for oil and gas production in the future are weighted to world benchmark prices and may be adversely affected by mild weather conditions.

C. Organizational Structure

We have three wholly-owned subsidiaries:

• Dejour Energy (USA) Corp. (“Dejour USA”), a Nevada corporation, holds DXI Energy's United States oil and gas interests;

• Dejour Energy (Alberta) Ltd. (“DEAL”), an Alberta corporation, holds DXI Energy’s Canadian oil and gas interests in northwestern Alberta and northeastern British Columbia; and

• 0855524 B.C. Ltd. (“0855524”), a British Columbia Corporation, which is currently inactive.

D. Property, Plant and Equipment

Our executive offices are located in rented premises of approximately 1,084 sq. ft. at Suite 520, 999 Canada Place, Vancouver, British Columbia, V6C 3E1. We began occupying these facilities on September 1, 2017.

Resource Properties

Our current focus is on oil and gas properties located in the United States and Canada and currently have oil and gas leases in the following regions:

• The Piceance, Paradox and Uinta Basins in the US Rocky Mountains.

• The Peace River Arch of northeastern British Columbia and northwestern Alberta, Canada.

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US Oil and Gas Interests

Kokopelli, Piceance Basin

The Company owns an approximate 25% working interest in 2,200 gross acres (550 net acres) at Kokopelli, its core area of operations. In 2013, the Company drilled four (4) Williams Fork wells jointly with partners. In June 2014, the Company sold approximately 16.25% of its 25% working interest in the four wells and assigned Operatorship in Kokopelli to a Denver-based Drilling Fund. In October 2014, the Company and the Drilling Fund commenced drilling eight new wells at Kokopelli, seven of which were drilled to the base of the Williams Fork zone at 8,900 ft. The eighth well was drilled through the Williams Fork zone to the base of the Mancos formation and completed in the Mancos at approximately 11,000 ft. The Company earned a 25% working interest in the eight new wells while a consortium of Funds managed by the Drilling Fund owns the remaining 75% working interest. During 2015, the Company completed the eight wells and tied the wells into production pipelines. Initial production from the eight new wells commenced in the 4^th quarter of 2015.

The Company and its partners intend to continue to develop the Kokopelli Project when natural gas and natural gas liquids prices paid to producers return to acceptable levels.

Canadian Oil and Gas Interests

Drake/Woodrush, Fort St. John, British Columbia

The Company’s Drake/Woodrush oilfield is located about 110 km. north of Fort St. John, British Columbia, Canada. In 2017, the Company continued its oil and gas production operations in Northeastern, British Columbia.

On December 22, 2017, the Company signed a “Funding and Participation Agreement” (“the Agreement”) with a private U.S. based investment firm to underwrite 50% of the capital costs of at least one exploration well at Woodrush, currently scheduled to commence in the first quarter of 2018. Under the terms of the Agreement, the investment firm will pay approximately two-thirds of the total cost of the first well of the 2018 program, through tie in, to earn a 15% Gross Overriding Royalty (“GORR”).

The investment firm has the right to elect to participate in the drilling and completion of a 2^nd and subsequent wells, if any, by paying 50% of the capital costs to earn a 15% GORR in the well spacing unit on a well-by-well basis.

Reserve Data

The standards of the SEC require that proved reserves be estimated using existing economic conditions (constant pricing). Based on this methodology, the Company’s results have been calculated utilizing the 12-month average price for each of the years presented.

The Company reports in Canadian currency and therefore the Reserves Data set forth in the tables below has been converted to Canadian dollars at the prevailing conversion rate at December 31, 2017. The conversion rate used per Bank of Canada is 1.2545.

In 2017, GLJ Petroleum Consultants (“GLJ”), independent petroleum engineering consultants based in Calgary, Alberta was retained by the Company to evaluate the Canadian properties of the Company. Their report, titled “Third Party Report on Reserves, Dejour Energy (Alberta) Ltd.”, is dated March 21, 2018 and has an effective date of December 31, 2017.

Gustavson Associates (“Gustavson”), independent petroleum engineering consultants based in Denver, Colorado were retained by the Company to evaluate the US properties of the Company. Their report, titled “Reserve Estimate and Financial Forecast as to Dejour’s Interests in the Kokopelli Field Area, Garfield County, Colorado” is dated March 20, 2018 and has an effective date of January 1, 2018.

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The reserves data set forth below (the "Reserves Data"), derived from GLJ and Gustavson’s reports, summarizes our oil, liquids and natural gas reserves.

The GLJ and Gustavson reports are based on certain factual data supplied by the Company, and GLJ and Gustavson's opinion of reasonable practice in the industry. The extent and character of ownership and all factual data pertaining to the Company’s petroleum properties and contracts (except for certain information residing in the public domain) were supplied by the Company to GLJ and Gustavson and accepted without any further investigation. GLJ and Gustavson accepted this data as presented and neither title searches nor field inspections were conducted. All statements relating to the activities of the Company for the year ended December 31, 2017 include a full year of operating data on the properties of the Company.

The reserve estimates of crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas liquids and natural gas reserves may be greater than or less than the estimates provided herein.

Controls Over Reserve Report Preparation

Our reserve estimates reports as of December 31, 2017 are prepared by our independent qualified reserve evaluators, GLJ and Gustavson. To ensure accuracy and completeness of the data prior to disclosure of reserve estimates to the public, our reserves committee does the following: (1) reviews our procedures for providing information to the independent qualified reserve evaluators, (2) meets with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the qualified reserves evaluators to report without reservation, (3) reviews the reserves data with management and the independent qualified reserves evaluator. If the reserve committee is satisfied with results of its evaluation it will approve the content of our reserve disclosure. If any concerns arise in the reserve committee’s evaluation, the reserve committee will work with our management and the independent qualified reserves evaluators to resolve the issues before disclosure of reserves is made public.

As of December 31, 2017, the Company’s reserve committee was composed of: Stan Page, A. Ross Gorrell and Ronnie Bozzer. Please see “Item 6. Directors, Senior Management and Employees, A. Directors and Senior Management” for biographical information on the members of the reserve committee.

Summary of Oil and Gas Reserves as of Fiscal Year-End Based on Average Fiscal Year Prices

	Net Reserves
Proved Reserves Category	Oil (Mbbl)	Condensate (MBO)	Natural Gas (Mmcf)	Natural Gas Liquids (Mbbl)
Developed
Canada	59	-	217	-
United States	-	8	978	40
Undeveloped
Canada	-	-	-	-
United States	-	235	26,630	1,078
TOTAL PROVED	59	243	27,825	1,118

Given economic commodity prices, the Company plans to fully develop its reserves over the next five years.

(1) Canada – Increase in Total Proved Oil Reserves of 12 Mbbls:

During the year ended December 31, 2017, the slight increase in light and medium oil reserves was primarily due to lower operating expenses as this helps the economic limit lending to the positive technical revisions.

(2) United States – Increase in Total Proved Oil and Natural Gas Reserves of 5,761 Mboe:

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During the year ended December 31, 2017, the increase in total proved reserves was mainly a result of a higher 12-month average trailing oil and natural gas prices.

Total Proved Reserves

The table below compares our estimated proved reserves and associated present value (discounted at an annual rate of 10%) of the estimated future revenue before income tax.

	December 31, 2017
Canada (Proved Developed and Undeveloped Reserves)	Natural Gas	Oil	Natural Gas Liquids	Total	PV-10 (2)
	(Mmcf)	(Mbbl)	(Mbbl)	(Mmcfe)	(Cdn$ thousands)
2017 12-month average prices (SEC) (1)	217	59	-	571	$234

	December 31, 2017
United States (Proved Developed and Undeveloped Reserves)	Natural Gas	Condensate	Natural Gas Liquids	Total	PV-10 (2)
	(Mmcf)	(Mbbl)	(Mbbl)	(Mmcfe)	(Cdn$ thousands)
2017 12-month average prices (SEC) (1)	27,608	243	1,118	35,774	$3,277

	December 31, 2017
Total (Proved Developed and Undeveloped Reserves)	Natural Gas	Oil	Condensate	Natural Gas Liquids	Total	PV-10 (2)
	(Mmcf)	(Mbbl)	(Mbbl)	(Mbbl)	(Mmcfe)	(Cdn$ thousands)
2017 12-month average prices (SEC) (1)	27,825	59	243	1,118	36,345	$3,511

Reconciliation to Standardized Measure

As at December 31, 2017
(CA$ thousands)		Canada		USA			Total
Present value of estimated future net cash flows before income taxes	$	234	$	3,277		$	3,511
Income taxes - discounted		-		(624	)		(624	)
Standardized measure of discounted future net cash flow	$	234	$	2,651		$	2,885

Notes:

(1)

The 12-month average prices (SEC) are calculated based on an average of market prices posted at or near the first of each month from January to December 2017, adjusted for pipeline transportation costs from the wellhead to the interstate pipeline prevailing at December 31, 2017. The 12-month average prices (SEC) used for Canadian properties were Cdn$53.93 per barrel of oil and Cdn$1.25 per Mcf of natural gas. The 12-month average prices (SEC) used for US properties were US$44.95 per barrel of condensate, US$3.10 per Mcf of natural gas, and US$35.18 per barrel of NGLs.

(2)

Present value of estimated future net cash flows before income taxes (PV-10) is considered a non-GAAP financial measure as defined by the SEC. We believe that our PV-10 presentation is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account the related deferred income taxes, as such taxes may differ among various companies because of differences in the amounts and timing of deductible basis, net operating loss carryforwards and other factors. We believe investors and creditors use our PV-10, before tax, as a basis for comparison of the relative size and value of our proved reserves to the reserve estimates of other companies. PV-10 is not a measure of financial or operating performance under GAAP and is not intended to represent the current market value of our estimated oil and natural gas reserves. PV-10, before tax, should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.

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⁽³⁾ US dollars are converted into Canadian dollars using the closing exchange rate on December 31, 2017, which is US$1.00 = Cdn$1.2545.

Oil and Gas Production, Production Prices and Production Costs

The following is our total net oil and gas production for the fiscal years ended December 31, 2017, 2016 and 2015. Production came from our Canadian and United States properties.

Production
Fiscal Year Ended	Oil and Natural Gas Liquids (bbls)	Natural Gas (Mcf)	Total (BOE)
December 31, 2017	29,932	418,006	99,600
December 31, 2016	76,506	609,858	178,147
December 31, 2015	134,772	644,022	242,109

The following table includes the average prices the Company received for its production for the fiscal years ended December 31, 2017, 2016 and 2015.

Average Sales Prices
Fiscal Year Ended	Oil and Natural Gas Liquids ($/bbls)	Natural Gas ($/Mcf)	Total ($/BOE)
December 31, 2017	56.21	2.71	28.27
December 31, 2016	43.25	2.47	27.02
December 31, 2015	52.68	2.33	35.52

The following table includes the average production cost, not including ad valorem and severance taxes, per unit of production for the fiscal years ended December 31, 2017, 2016 and 2015.

Average Production Costs
Fiscal Year Ended	Oil and Natural Gas Liquids ($/bbls)	Natural Gas ($/Mcf)	Total ($/BOE)
December 31, 2017	30.84	3.58	24.29
December 31, 2016	25.80	2.86	20.86
December 31, 2015	23.64	3.35	22.09

Drilling and Other Exploratory and Development Activities

During the fiscal years ended December 31, 2017, December 31, 2016 and December 31, 2015, no wells were drilled in Canada and the United States.

Delivery Commitments

We have no current delivery commitments for either oil or natural gas.

Oil and Gas Properties and Wells

The following tables summarizes the number of producing and non-producing wells as at December 31, 2017:

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	Producing Wells
Country	Oil		Natural Gas
	Gross	Net	Gross	Net
Canada	3	2.97	4	3.88
USA	-	-	12	2.29
Total	3	2.97	16	6.17

	Non-Producing Wells
Country	Oil (1)		Natural Gas (2)
	Gross	Net	Gross	Net
Canada	6	5.94	27	20.03
USA	-	-	-	-
Total	6	5.94	27	20.03

(1)	Includes water source wells and injection wells
(2)	Includes non-producing wells, shut-in wells and wells being temporarily suspended

The following tables summarizes the number of producing and non-producing wells as at December 31, 2016:

	Producing Wells
Country	Oil		Natural Gas
	Gross	Net	Gross	Net
Canada	3	2.97	5	4.42
USA	-	-	12	2.29
Total	3	2.97	17	6.71

	Non-Producing Wells
Country	Oil (1)		Natural Gas (2)
	Gross	Net	Gross	Net
Canada	6	5.94	26	19.49
USA	-	-	-	-
Total	6	5.94	26	19.49

(1)	Includes water source wells and injection wells
(2)	Includes non-producing wells, shut-in wells and wells being temporarily suspended

The following tables summarizes the number of producing and non-producing wells as at December 31, 2015:

	Producing Wells
Country	Oil		Natural Gas
	Gross	Net	Gross	Net
Canada	3	2.97	5	4.42
USA	-	-	12	2.29
Total	3	2.97	17	6.71

	Non-Producing Wells
Country	Oil (1)		Natural Gas (2)
	Gross	Net	Gross	Net
Canada	6	5.94	26	19.49
USA	-	-	-	-
Total	6	5.94	26	19.49

(1)	Includes water source wells and injection wells
(2)	Includes non-producing wells, shut-in wells and wells being temporarily suspended

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Interest in Oil and Gas Properties

The following table sets forth information for our interest in oil and gas properties as of December 31, 2017 relating to our leasehold acreage. Developed acres are acres spaced or assigned to productive wells including undrilled acreage held-byproduction under the terms of a lease. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of gas or oil, regardless of whether such acreage contains proved reserves. Gross acres are the total number of acres in which a working interest is owned. Net acres are the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
As at December 31, 2017, the Company’s developed and undeveloped acres are as follows:

	Developed Acreage		Undeveloped Acreage		Total
	Gross	Net	Gross	Net	Gross	Net
Canada	9,497	7,218	8,584	5,875	18,081	13,093
U.S.A	2,240	590	27,176	23,814	29,416	24,404
TOTAL	11,737	7,808	35,760	29,689	47,497	37,497

The Company’s net undeveloped acres as of December 31, 2017, together with expiries for the period from 2018 to 2020 and thereafter is as follows.

	Undeveloped Acreage
As of December 31, 2017	Net	2018 Expirations	2019 Expirations	2020 and thereafter Expirations
Canada:
Saddle Hills/Manning	917	-	-	917
Woodrush/Hunter	4,958	2,788	-	2,170
Subtotal:	5,875	2,788	-	3,087
U.S.A:
Ashley	480	-	-	480
Book Cliffs	1,762	-	-	1,762
Dinosaur	18,971	-	-	18,971
Pinyon Ridge	640	-	-	640
Roan Creek	1,961	-	-	1,961
Subtotal:	23,814	-	-	23,814
TOTAL:	29,689	2,788		26,901

ITEM 4A. UNRESOLVED STAFF COMMENTS

None.

ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

The following is a discussion of our consolidated operating results and financial position, including all our wholly-owned subsidiaries. It should be read in conjunction with our audited consolidated financial statements and notes for the year ended December 31, 2017 and related notes included therein under the heading "Item 18. Financial Statements" below.

The financial statements of the Company for the years ended December 31, 2017, 2016, and 2015 are prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) and interpretations of the International Financial Reporting Interpretations Committee (“IFRIC”).

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Certain forward-looking statements are discussed in this Item 5 with respect to our activities and future financial results. These are subject to risks and uncertainties that may cause projected results or events to differ materially from actual results or events. Readers should also read the "Cautionary Note Regarding Forward-Looking Statements" above and “Item 3. Key Information - Risk Factors.”

CRITICAL ACCOUNTING ESTIMATES AND JUDGMENTS

The preparation of financial statements in accordance with IFRS requires management to make estimates and judgments that affect reported assets, liabilities, revenues, expenses, gains, and losses. These estimates and judgments are subject to change based on experience and new information. The financial statement areas that require significant estimates and judgments are as follows:

Decommissioning liability

The Company recognizes decommissioning liabilities for its exploration and evaluation assets and property and equipment. Measurement of the decommissioning liabilities involves estimates and judgements as to the cost and timing of incurrence of future decommissioning programs. It also involves assessment of appropriate discount rates, rates of inflation applicable to future costs and the rate used to measure the accretion charge for each reporting period. Measurement of the liability also reflects current engineering methodologies as well as current and expected future environmental legislation and standards. Actual decommissioning costs will ultimately depend on future market prices for the decommissioning costs which will reflect the market conditions at the time the decommissioning costs are actually incurred. The final cost of the currently recognized decommissioning provisions may be higher or lower than currently provided for.

Exploration and evaluation expenditures

The application of the Company’s accounting policy for exploration and evaluation expenditures requires judgment in determining whether it is likely that future economic benefits will flow to the Company, which is based on assumptions about future events or circumstances. Estimates and assumptions made may change if new information becomes available. If, after the expenditure is capitalized, information becomes available suggesting that the recovery of the expenditure is unlikely, the amount capitalized is written off in profit or loss in the period in which the new information becomes available.

Share-based payment transactions

The Company measures the cost of equity-settled transactions with employees by reference to the fair value of the equity instruments at the date at which they are granted. Management uses judgment to determine the most appropriate valuation model to estimate the fair value for share-based payment transactions. The inputs to the valuation model, including the expected life of the share option, volatility and dividend yield, require judgment for determination.

Financial contract liability

The application of the Company’s accounting policy for financial liabilities requires the Company to adjust the carrying amounts of the financial liabilities in the event it revises its payments or receipts to reflect actual and revised estimated cash flows. The Company’s financial contract liability was originally recognized at fair value using the effective interest method which ensures that any interest expense over the period of repayment is at a constant rate on the balance of the liability carried in the balance sheet. Effective June 30, 2014, the Company’s financial contract liability was reduced by the residual reserve value of its working interest in the wellbores at September 30, 2016.

At December 31, 2017, the financial contract liability was adjusted to reflect the present value of the amount outstanding at year-end, net of the present value of the residual reserves of its working interest in the wellbores.

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Impairment

Management applies judgment in assessing the existence of impairment and impairment reversal indicators based on various internal and external factors.

The recoverable amounts of CGUs and individual assets have been determined based on the higher of fair value less costs to sell or value-in-use. The key estimates the Company applies in determining the recoverable amount normally include anticipated future commodity prices, expected production volumes, future operating and development costs, and discount rates. Changes to these assumptions will affect the recoverable amounts of CGUs and individual assets and may then require a material adjustment to their related carrying value. At December 31, 2017, the Company has one CGU in Canada (Drake/Woodrush) and one CGU in the United States (Kokopelli).

Financial instruments

When estimating the fair value of financial instruments, the Company uses valuation methodologies that utilize observable market data where available. In addition to market information, the Company incorporates transaction specific details that market participants would utilize in a fair value measurement, including the impact of non-performance risk.

Reserves

The estimate of reserves is used in forecasting the recoverability and economic viability of the Company’s oil and gas properties, and in the depletion and impairment calculations. The process of estimating reserves is complex and requires significant interpretation and judgment. It is affected by economic conditions, production, operating and development activities, and is performed using available geological, geophysical, engineering, and economic data. Reserves are evaluated at least annually by the Company’s independent reserve evaluators and updates to those reserves, if any, are estimated internally. Future development costs are estimated using assumptions as to the number of wells required to produce the commercial reserves, the cost of such wells and associated production facilities and other capital costs.

FUTURE ACCOUNTING PRONOUNCEMENTS

Certain pronouncements were issued by “IASB” or “IFRIC” that are mandatory for accounting periods beginning after January 1, 2018 or later periods. The following new accounting standards, amendments to accounting standards and interpretations, have not been early adopted in these consolidated financial statements:

IFRS 9, “Financial Instruments”: In July 2014, the IASB completed the final phase of its project to replace IAS 39, the current standard on the recognition and measurement of financial instruments. IFRS 9 is now the new standard which sets out the recognition and measurement requirements for financial instruments and some contracts to buy or sell non-financial items. IFRS 9 provides a single model of classifying and measuring financial assets and liabilities and provides for only two classification categories: amortized cost and fair value. Hedge accounting requirements have also been updated in the new standard and are now more aligned with the risk management activities of an entity. IFRS 9 is effective for annual periods beginning on or after January 1, 2018. Early adoption is permitted; however, if an entity elects to apply this standard early, it must disclose that fact and apply all of the requirements in this standard at the same time. The Company has determined that there will not be any material impact on its consolidated financial statements as a result of the adoption of IFRS 9.

IFRS 15, “Revenue from Contracts with Customers”: the standard was issued in May 2014 and amended in April 2016. IFRS 15 applies to contracts with customers, excluding, most notably, insurance and leasing contracts. IFRS 15 prescribes a framework in accounting for revenues from contracts within its scope, including (a) identifying the contract, (b) identify separate performance obligations in the contract, (c) determine the transaction price of the contract, (d) allocate the transaction price to the performance obligations and (e) recognize revenues when each performance obligation is satisfied. IFRS 15 also prescribes additional financial statement presentations and disclosures. The Company currently expects to adopt IFRS 15 as of January 1, 2018, under the modified retrospective method where the cumulative effect is recognized at the date of initial application. The Company has completed the evaluation of IFRS 15. It has been concluded that the adoption of IFRS 15 will not have a material effect on the Company’s consolidated financial statements.

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IFRS 16, “Leases”: In January 2016, the IASB issued the standard to replace IAS 17 “Leases”. For lessees applying IFRS 16, a single recognition and measurement model for leases would apply, with required recognition of assets and liabilities for most leases. The standard will come into effect for annual periods beginning on or after January 1, 2019, with earlier adoption permitted. It is anticipated that the adoption of IFRS 16 will have impact on the Company’s consolidated balance sheet due to the operating lease commitments.

A. Operating Results

The Company’s annual audited Consolidated Financial Statements for the year ended December 31, 2017, including 2016 and 2015 required comparative information, have been prepared in accordance with IFRS.

All financial information is stated in Canadian dollars, the Company’s presentation currency, unless otherwise noted.

Year ended December 31, 2017 compared to the year ended December 31, 2016

1. Revenues

For the year ended December 31, 2017, total revenue, before royalties, decreased by $1,992,000 or, 41%, due to a decline in oil and natural gas production for the year. This was partially offset by a slight increase in combined average realized prices.

2. Oil Operations

The average price received for oil sales increased by 30% for the year ended December 31, 2017, relative to the corresponding period of 2016. The increase in DXI Energy’s average realized oil price reflected the benchmark price recovery in Canada and the rest of the world.

Operating and transportation expenses for the year ended December 31, 2017 were higher, relative to the corresponding period of 2016, mainly due to the temporary closure of the contract processing terminal in northeastern B.C. and the necessity to transport oil to an alternative facility further from the Woodrush oilfield. In addition, the increase resulted in higher per unit costs as fixed operating costs were allocated over a lower oil production volume.

3. Natural Gas Operations

The average price received for gas sales increased by 10% for the year ended December 31, 2017, relative to the corresponding period of 2016. The increase in DXI Energy’s average realized gas price reflected the benchmark price recovery in northeastern British Columbia and northwestern Alberta, Canada and the Piceance Basin in the United States.

Operating and transportation expenses for the year ended December 31, 2017 were higher, relative to the corresponding period of 2016, primarily due to certain fixed operating costs being allocated to reduced natural gas production volumes.

4. General and Administrative Expenses

G&A expenses for fiscal 2017 were slightly higher compared to the amount recorded for fiscal 2016. Lower G&A expenses for fiscal 2016 was due to the capitalization of G&A expenses in 2016.

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

1. Revenues

For the year ended December 31, 2016, total revenue, before royalties, decreased by $3,771,000 or, 44%, due to a decline in combined average realized prices and a reduction in oil and natural gas production.

2. Oil Operations

The average price received for oil sales decreased by 18% for the year ended December 31, 2016, relative to the prior year. The decrease in DXI Energy’s average realized oil price reflected lower benchmark prices in Canada and the rest of the world.

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Average oil royalties paid for the year ended December 31, 2016 were lower by 27%, relative to those paid in the year ended December 31, 2015, due to lower average oil prices received in 2016.

Operating and transportation expenses for the year ended December 31, 2016 were higher, compared to the amount recorded for the year ended December 31, 2015, mainly due to the temporary closure of the contract processing terminal and the necessity to transport oil to an alternative facility further from the Woodrush oilfield.

3. Natural Gas Operations

The average price received for gas sales increased by 6% for the year ended December 31, 2016, relative to the prior year. The increase in DXI Energy’s average realized gas price reflected the slight benchmark price recovery in both Canada and the United States.
Average gas royalties for the three and twelve months ended December 31, 2016 were higher compared to the corresponding periods of 2015. Initiation of gas production from the eight wells at Kokopelli in September 2015 contributed to the increase in royalties in both periods as the effective rate in Colorado is higher than the lower royalty rates for marginal gas production in British Columbia.

Operating and transportation expenses for the year ended December 31, 2016 were lower, relative to the amount recorded for the year ended December 31, 2015. The decline resulted from lower variable operating costs due to lower natural gas production volume at Kokopelli in Colorado. This was partially offset by the increased costs associated with to the temporary closure of the contract processing terminal and the necessity to transport oil to an alternative facility further from the Woodrush oilfield.

4. General and Administrative Expenses

G&A expenses for fiscal 2016 were lower compared to the amount recorded for fiscal 2015. The reduction in G&A expenses for fiscal 2016 was due to the implementation of the Company’s overall cost savings plan.

Financial Instruments and Risk Management

The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and current portion of loans from related parties. Management has determined that the fair value of these financial instruments approximates their carrying values due to their immediate or short-term maturity.

From time to time, the Company enters into derivative contracts such as forwards, futures and swaps in an effort to mitigate the effects of volatile commodity prices and protect cash flows to enable funding of its exploration and development programs. Commodity prices can fluctuate due to political events, meteorological conditions, disruptions in supply and changes in demand.

The primary risks and how the Company mitigates them are disclosed in Item 11 – Quantitative and Qualitative Disclosures About Market Risk, below.

B. Liquidity and Capital Resources

Loans from Related Parties

On March 12, 2015, as amended on May 6, 2015, June 22, 2015, September 28, 2015, November 18, 2015 and June 5, 2017, the Company issued a promissory note for $4.5 million to Hodgkinson Equities Corp. (“HEC”), a private company controlled by the CEO of the Company. The promissory note is secured by all assets of Dejour USA and a negative pledge by the Company not to further encumber its Canadian oil and gas properties without HEC’s prior approval. The principal and interest at Canadian prime rate plus 5% per annum was repayable by the earlier of (i) within 10 business days of receipt of written demand from HEC for the repayment and (ii) June 10, 2015 or such later date to which the term of the promissory note may be extended. On May 6, 2015, the due date of the loan was extended to September 30, 2015. On September 28, 2015, the due date of the loan was further extended to December 31, 2015. On November 18, 2015, the Company extended the due date of the loan from December 31, 2015 to November 30, 2018. Additionally, a monthly principal repayment of $114,230.77 is due on the 1^st day of each month commencing June 1, 2016. HEC agreed to waive the requirement of the Company to repay the total monthly principal repayments of $1,371,000 until the loan was restructured on June 5, 2017. In consideration for the extension, the Company issued HEC 9,000,000 Warrants. Each Warrant entitles the holder to acquire one common share at a price of C$0.45/US$ 0.35 per share any time prior to December 4, 2020. Shares acquired through the exercise of Warrants prior to April 5, 2016 were restricted from sale through the facilities of the stock exchanges. On February 19, 2016, the Company rescinded the negative pledge security agreement and issued a first mortgage in favour of HEC on its Canadian oil and gas properties. The first mortgage security so issued ranked “pari passu” with HVI’s first mortgage security interest. On June 5, 2017, the Company restructured the term of the loan with extension of the due date from November 30, 2018 to June 5, 2022; reduction of the interest rate to Canadian prime rate plus 1% per annum; and the right to convert the entire outstanding amount into 58,441,558 common shares of the Company at a price of $0.077 per share. In exchange for the modification, HEC agreed to cancel the 9,000,000 warrants described above. Upon an event of default, all the indebtedness under the promissory note become due and payable and the interest rate is immediately increased to the Canadian prime rate plus 4.5% per annum.

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On June 22, 2015, as amended on September 28, 2015, November 18, 2015 and June 5, 2017, the Company issued a promissory note for $2.0 million to Hodgkinson Ventures Inc. (“HVI”), a private company associated with the CEO of the Company, on a “pari passu” basis with the loan from HEC. The promissory note is secured by all assets of Dejour USA and a negative pledge by the Company not to further encumber its Canadian oil and gas properties without HVI’s prior approval. The principal and interest at Canadian prime rate plus 5% per annum was repayable on or before September 30, 2015. On September 28, 2015, the due date of the loan was extended to December 31, 2015. On November 18, 2015, the Company extended the due date of the loan from December 31, 2015 to November 30, 2018. Additionally, a monthly principal repayment of $50,769.23 is due on the 1^st day of each month commencing June 1, 2016. HVI agreed to waive the requirement of the Company to repay the total monthly principal repayments of $660,000 until the loan was restructured on June 5, 2017. In consideration for the extension, the Company issued HVI 4,000,000 Warrants. Each Warrant entitles the holder to acquire one common share at a price of C$0.45/US$ 0.35 per share any time prior to December 4, 2020. Shares acquired through the exercise of Warrants prior to April 5, 2016 were restricted from sale through the facilities of the stock exchanges. On February 19, 2016, the Company rescinded the negative pledge security agreement and issued a first mortgage in favour of HVI on its Canadian oil and gas properties. The first mortgage security so issued ranked “pari passu” with HEC’s first mortgage security interest. On June 5, 2017, the Company restructured the term of the loan with extension of the due date from November 30, 2018 to June 5, 2022; reduction of the interest rate to Canadian prime rate plus 1% per annum; and the right to convert the entire outstanding amount into 25,974,025 common shares of the Company at a price of $0.077 per share. In exchange for the modification, HVI agreed to cancel the 4,000,000 warrants described above. Upon an event of default, all the indebtedness under the promissory note become due and payable and the interest rate is immediately increased to the Canadian prime rate plus 4.5% per annum.

On September 15, 2015, as amended on January 11, 2016, March 31, 2016, June 2, 2016, September 30, 2016, December 30, 2016 and June 30, 2017, the Company issued a grid promissory note of up to $1.0 million to a director and officer of the Company and his spouse. The promissory note bears interest at 12% per annum. The principal and interest accrued on the loan were repayable on or before December 31, 2015. On January 11, 2016, the Company issued an additional grid promissory note of up to $200,000 to a director and officer of the Company and his spouse and the due date of the loan was extended to March 31, 2016. On March 31, 2016, the due date of the loan was further extended to September 30, 2016. On June 2, 2016, the Company increased the maximum amount of the non-revolving loan from $1.2 million to $1.5 million. The interest rate was also reduced from 12% to 10% per annum. Additionally, the Company issued a 2^nd mortgage in favour of the Lenders on DEAL’s oil and gas properties to a maximum of $1.5 million as partial security for the loan. On September 30, 2016, the due date of the loan was extended to December 31, 2016. On December 31, 2016, the due date of the loan was extended to June 30, 2017. On June 30, 2017, the due date of the loan was further extended to June 30, 2018. The maximum loan amount available at December 31, 2017 was $1.5 million (December 31, 2016 - $1.5 million). During the year ended December 31, 2017, $450,000 was borrowed (2016 - $50,000) and $500,000 was repaid via issuance of the Company’s common shares (2016 - $Nil) leaving a balance outstanding of $1,000,000 at December 31, 2017 (December 31, 2016 - $1,050,000).

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Financial Contract Liability

On December 31, 2012, Dejour USA entered into a financial contract with a U.S. oil and gas drilling fund (“Drilling Fund”) to fund the drilling of up to three wells and the completion of up to four wells in the State of Colorado. The total amount contributed by the Drilling Fund was US$7,000,000.

The financial contract contains a provision whereby Dejour USA must purchase the Drilling Funds’ working interest in the four wells funded by the US$7,000,000 if the Drilling Fund fails to obtain a certain minimum return on investment by September 30, 2016. A subsequent amendment limited Dejour USA’s cash exposure to a potential “put” by the Drilling Fund to US$3,000,000, with the difference to be settled by an assignment of working interests in certain P&NG properties owned by Dejour USA. The Company is not a party to the financial contract.

On September 30, 2016, the Drilling Fund served notice to Dejour USA requiring Dejour USA to purchase the Drilling Funds’ working interest in the 4 wellbores in accordance with the contract. However, prior to serving such notice, the Drilling Fund executed certain assignments transferring ownership of its working interests in the 4 wellbores to another entity and the assignee mortgaged its interest therein. Dejour USA and its attorneys are reviewing the impact of the Drilling Fund’s actions on the validity of the financial contract between the parties.

As at December 31, 2017, Dejour USA has recorded a liability owing to the Drilling Fund of $6,752,000, as follows:

(CA$ thousands)	$
Balance at January 1, 2016 (US$5,207)	7,207
Accretion expense (US$222)	296
Foreign exchange gain	(214	)
Adjustment to financial contract liability (US$47)	(63	)
Balance at December 31, 2016 (US$5,382)	7,226
Foreign exchange gain	(474	)
Balance at December 31, 2017 (US$5,382)	6,752

This amount, if any, is subject to a resolution of the financial contract between the parties. Dejour USA has received no formal communication from the Drilling Fund since the “put” notice date of September 30, 2016.

Working Capital Position

As at December 31, 2017 (CA$ thousands)	$
Working capital deficit	(8,167	)
Non-cash flow-through shares liability	93
Adjusted working capital deficit	(8,074	)
Add: current portion of loans from related parties	1,458
Add: non-cash portion of financial contract liability	2,988
Adjusted working capital deficit (excluding loans from related parties and financial contract liability)	(3,628	)

Working capital is defined as current assets less current liabilities.

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As at December 31, 2017, the Company had a working capital deficit of $8.2 million. Excluding the non-cash flow-through shares liability of $0.1 million, the adjusted working capital deficit was $8.1 million. Of this amount, $6.8 million is represented by a financial contract liability of Dejour USA, which was due on September 30, 2016. The maximum cash component due in full settlement of the financial contract liability is US$3.0 million. The details of the settlement progress are described in the “Financial Contract Liability” section above. Our independent auditors have included an explanatory paragraph in their report on our consolidated financial statements for the year ended December 31, 2017 that describes uncertainties that cast substantial doubt about our ability to continue as a going concern.

Capital Resources

a) Canada

In 2017, the Company incurred $0.4 million to conduct the seismic studies and exploration work for the upcoming drilling program at its Woodrush properties, north of Fort St. John, British Columbia. These capital expenditures were funded by cash on hand of the Company.

b) United States

In 2017, the Company paid $42,000 for the ongoing Kokopelli development program in Colorado. The Company funded this program through the use of a combination of cash on hand and the loans from the companies associated with a director and officer of the Company.

C. Research and Development, Patents and Licenses, etc.

None.

D. Trend Information

a) Oil Prices

The general outlook for crude oil prices will be tied primarily to the supply response to the current price environment and the pace of growth of the global economy. Overall, crude oil price volatility and a modest price improvement are expected in 2018. Agreement to extend production cuts through to the end of 2018 led by OPEC will support oil prices through 2018.

b) Natural gas

In 2017, natural gas prices were higher than those in 2016. This was the result of consumption exceeding production and supply, leading to lower inventory level. Prices are expected to be higher again in 2018 since there is higher probability of an increase in natural gas consumption as a result of colder weather per forecast.

E. Off-Balance Sheet Arrangements

The Company has no material undisclosed off-balance sheet arrangements that have or are reasonably likely to have, a current or future effect on our results of operations or financial condition at December 31, 2017.

F. Tabular Disclosure of Contractual Obligations

As of December 31, 2017, and in the normal course of business we have obligations to make future payments, representing contracts and other commitments that are known and committed.

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(CA$ thousands)	2018	2019	2020	2021	2022	Thereafter	Total
	$	$	$	$	$	$	$
Trade and other payables	1,291	-	-	-	-	Nil	1,291
Debt repayments	1,000	-	-	-	6,500	Nil	7,500
Interest payments	50	-	-	-	-	Nil	50
Operating lease obligations	88	92	-	-	-	Nil	180
Financial contract liability(1)	6,752	-	-	-	-	Nil	6,752
Total	9,181	92	-	-	6,500	Nil	15,773

⁽¹⁾ This represents the Company’s obligations over the 36-month put option period until it expires. See Note 11 to the consolidated financial statements for details.

G. Safe Harbor

The Company seeks safe harbor for our forward-looking statements contained in Items 5.E and F. See the heading “Cautionary Note Regarding Forward-Looking Statements” above.

ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

A. Directors and Senior Management

The following table sets forth all current directors and executive officers of DXI Energy as of the date of this annual report on Form 20-F, with each position and office held by them in the Company and the period of service as such.

Name, Jurisdiction of Residence and Position (1)	Principal occupation or employment during the past 5 years	Number of DXI Energy Common Shares beneficially owned, directly or indirectly, or controlled or directed (2)	Percentage of DXI Energy Common Shares beneficially owned, directly or indirectly, or controlled or directed (2)	Director Since
Robert L. Hodgkinson British Columbia, Canada Director, Chairman and Chief Executive Officer (Age: 68)	President of a private company, Hodgkinson Equities Corporation, which provides consulting services to emerging businesses in the petroleum resource industry. Formerly a director of Titan Uranium (TSX-V: TUE).	19,963,741	19.27%	May 18, 2004
Craig Sturrock (3)(4) British Columbia, Canada Director (Age: 74)	Tax lawyer since 1971. Currently, he is a partner at Thorsteinssons LLP, and his practice focuses primarily on civil and criminal tax litigation.	307,783	0.30%	August 22, 2005
Dr. A. Gorrell (4)(5)(6) British Columbia, Canada Director (Age: 73)	Dr. Gorrell has over 30 years’ experience with both private and public oil and gas property exploration and development in Western Canada and China. Dr. Gorrell has served as director, officer and controlling principal of several oil and gas ventures listed on the Toronto Stock Exchange. Currently, Dr. Gorrell is a director, President/CEO and Co-Chairman of Petromin Resources Ltd.	146,117	0.14%	December 14, 2012

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Name, Jurisdiction of Residence and Position (1)	Principal occupation or employment during the past 5 years	Number of DXI Energy Common Shares beneficially owned, directly or indirectly, or controlled or directed (2)	Percentage of DXI Energy Common Shares beneficially owned, directly or indirectly, or controlled or directed (2)	Director Since
Ronnie Bozzer (3)(4)(5)(6) British Columbia, Canada Director (Age: 68)	Mr. Bozzer has extensive years of legal practice encompassing mergers and acquisitions, banking and finance transactions, public private partnerships, syndications and securitizations.	90,000	0.09%	January 15, 2014
Stan Page (3)(5)(6) Texas, United States Director (Age: 60)	Mr. Page has over 38 years of experience in the oil and gas industry. For the past 30 years, Mr. Page has held various leadership field and operation positions with major oil companies including BP America and Amoco Production Co. From 2010 to 2016, he was Senior Vice-President of US Operations for Quicksilver Resources where he provided strategic direction for engineering, geology, procurement, drilling, completion and day to day procedures.	-	-	August 30, 2017
David Matheson British Columbia, Canada Chief Financial Officer (Age: 68)	Mr. Matheson has over 30 years of executive experience in the oil and gas industry in both operations and finance. He previously served as CFO and then as President of Equatorial Energy Ltd., a public Canadian oil and gas exploration & production company with operations in Canada and Indonesia. Mr. Matheson was admitted to the Institute of Chartered Accountants in British Columbia, the Northwest Territories, and Canada in 1975.	1,863,890	1.80%	N/A

(1)	Each director will serve until the next annual general meeting of the Company or until a successor is duly elected or appointed in accordance with the Notice of Articles and Articles of the Company and the Business Corporations Act (British Columbia).
(2)	The number of common shares beneficially owned, directly or indirectly, or over which control or direction is exercised is based upon information furnished to the Company by individual directors and executive officers.
(3)	Member of audit committee.
(4)	Member of governance and nominating committee.
(5)	Member of compensation committee.
(6)	Member of reserves committee.

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Directors and Executive Officers

Brief biographies for DXI Energy's directors and executive officers are set forth below:

Robert L. Hodgkinson: Mr. Hodgkinson was the founder and Chairman of Optima Petroleum, which drilled wells in Alberta and the Gulf of Mexico before merging to form Petroquest Energy, a NASDAQ traded company. Subsequently, he founded and was CEO of Australian Oil Fields, which would later merge to become Resolute Energy/Cardero Energy Inc. Mr. Hodgkinson was also a Vice-President and partner of Canaccord Capital Corporation, and an early stage investor and original lease financier in Synenco Energy's Northern Lights Project in the Alberta oil sands.

Craig Sturrock: Mr. Sturrock has served as a director and founding member of various public and private companies. Admitted to the British Columbia Bar in 1969, he joined Thorsteinssons LLP, tax lawyers in 1971. He served for 15 years as a tax lawyer and partner at Birnie, Sturrock & Company returning to Thorsteinssons as a partner in 1989. He is an author and speaker for the Canadian and British Columbia Bar Associations, the Continuing Legal Education Society of British Columbia and the Canadian Tax Foundation. He is also a former member of the Board of Governors of the Canadian Tax Foundation.

Dr. A. Gorrell: Dr. Gorrell has over 30 years’ experience with both private and public oil and gas property exploration and development in Western Canada and China. Dr. Gorrell has served as director, officer and controlling principal of several oil and gas ventures listed on the Toronto Stock Exchange. Currently, Dr. Gorrell is a director, President/CEO and Co-Chairman of Petromin Resources Ltd.

Ronnie Bozzer: Mr. Bozzer's legal practice encompasses mergers and acquisitions, banking and finance transactions, public private partnerships, syndications and securitizations. His honours include receiving the highest peer review rating by Martindale Hubbell, becoming Chairman of Canada's International Finance Centre and recognition by "2010 Best Lawyers in Canada" in the specialty of Banking Law. Mr Bozzer is also listed as Canadian Leading Lawyer in the field of Corporate Law by "Law Day".

Stan Page: Mr. Page has over 38 years of experience in the oil and gas industry. For the past 30 years, Mr. Page has held various leadership field and operation positions with major oil companies including BP America and Amoco Production Co. From 2010 to 2016, he was Senior Vice-President of US Operations for Quicksilver Resources where he provided strategic direction for engineering, geology, procurement, drilling, completion and day to day procedures.

David Matheson: Mr. Matheson has over 30 years of executive experience in the oil and gas industry in both operations and finance. He previously served as CFO and then as President of Equatorial Energy Ltd., a public Canadian oil and gas exploration & production company with operations in Canada and Indonesia. Mr. Matheson was admitted to the Chartered Professional Accountants of Canada in 1975.

Family Relationships

There are no family relationships between any directors or executive officers of the Company.

Arrangements

There are no known arrangements or understandings with any major shareholders, customers, suppliers or others, pursuant to which any of the Company’s officers or directors was selected as an officer or director of the Company, other than indicated immediately above and at “Item 7. Major Shareholders and Related Party Transactions - Related Party Transactions.”

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

To the knowledge of the Company, no director or executive officer of the Company is, or has been in the last ten years, a director, chief executive officer or chief financial officer of an issuer that, while that person was acting in that capacity, (a) was the subject of a cease trade order or similar order or an order that denied the issuer access to any exemptions under Canadian securities legislation, for a period of more than 30 consecutive days, or (b) was subject to an event that resulted, after that person ceased to be a director, chief executive officer or chief financial officer, in the issuer being the subject of a cease trade or similar order or an order that denied the issuer access to any exemption under Canadian securities legislation, for a period of more than 30 consecutive days. To the knowledge of the Company, no director or executive officer of the Company, or a shareholder holding a sufficient number of securities in the Company to affect materially the control of the Company, is or has been in the last ten years, a director or executive officer of an issuer that, while or acting in that capacity within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets. To the knowledge of the Company, in the past ten years, no such person has become bankrupt, made a proposal under any legislation related to bankruptcy or insolvency, or was subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold their assets.

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Conflicts of Interest

Certain of the Company's directors and officers serve or may agree to serve as directors or officers of other reporting companies or have significant shareholdings in other reporting companies and, to the extent that such other companies may participate in ventures in which the Company may participate, the directors of the Company may have a conflict of interest in negotiating and concluding terms respecting the extent of such participation. In the event that such a conflict of interest arises at a meeting of the Company's directors, a director who has such a conflict will abstain from voting for or against the approval of such participation or such terms and such director will not participate in negotiating and concluding terms of any proposed transaction. From time to time, several companies may participate in the acquisition, exploration and development of natural resource properties thereby allowing for their participation in larger programs, permitting involvement in a greater number of programs and reducing financial exposure in respect of any one program. It may also occur that a particular company will assign all or a portion of its interest in a particular program to another of these companies due to the financial position of the company making the assignment. Under the laws of the Province of British Columbia, the directors of the Company are required to act honestly, in good faith and in the best interests of the Company. In determining whether or not the Company will participate in a particular program and the interest therein to be acquired by it, the directors will primarily consider the degree of risk to which the Company may be exposed and its financial position at that time. See also "Description of the Business – Risk Factors".

B. Compensation

Basis of Compensation for Executive Officers

The Company compensates its executive officers through a combination of base compensation, bonuses and Common Stock options. The base compensation provides an immediate cash incentive for the executive officers. Bonuses encourage and reward exceptional performance over the financial year. Common Stock options ensure that the executive officers are motivated to achieve long term growth of the Company and continuing increases in shareholder value. In terms of relative emphasis, the Company places more importance on Common Stock options as long term incentives. Bonuses are related to performance and may form a greater or lesser part of the entire compensation package in any given year. Each of these means of compensation is briefly reviewed in the following sections.

Base Compensation

Base compensation, including that of the Chief Executive Officer, are set by the Compensation Committee and approved by the Board of Directors on the basis of the applicable executive officer’s responsibilities, experience and past performance. The compensation program is intended to provide a base compensation competitive among companies of a comparable size and character in the oil and gas industry. In making such an assessment, the Board considers the objectives set forth in the Company’s business plan and the performance of executive officers and employees in executing the plan in combination with the overall result of the activities undertaken.

Common Stock Options

The Company provides long term incentive compensation to its executive officers through the Common Stock Option Plan, which is considered an integral part of the Company’s compensation program. Upon the recommendation of management and approval by the Board of Directors, stock options are granted under the Company’s Option Plan to new directors, officers and key employees, usually upon their commencement of employment with the Company. The Board approves the granting of additional stock options from time to time based on its assessment of the appropriateness of doing so in light of the long term strategic objectives of the Company, its current stage of development, the need to retain or attract key technical and managerial personnel in a competitive industry environment, the number of stock options already outstanding, overall market conditions, and the individual’s level of responsibility and performance within the Company.

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The Board views the granting of stock options as a means of promoting the success of the Company and creating and enhancing returns to its shareholders. As such, the Board does not grant stock options in excessively dilutive numbers. Total options outstanding are presently limited to 10% of the total number of shares outstanding under the rules of the TSX. Grant sizes are, therefore, determined by various factors including the number of eligible individuals currently under the Option Plan and future hiring plans of the Company.

No stock options were granted to the executive officers and directors of the Company in 2017.

Summary Compensation Table

The following table provides a summary of the compensation earned during the fiscal year ended December 31, 2017 for the Named Executive Officers and Directors listed in the table below.

		Annual Compensation			Long Term Compensation
Name and principal position	Year	Salary ($)	Consulting Fees ($)	Bonus ($)	Awards		Payouts ($)	All other compensation ($)
					Securities Under Option/ SAR's Granted (#)	Shares/ Units Subject to Resale Restrictions ($)
Robert Hodgkinson, Director, Chairman and Chief Executive Officer	2017 2016 2015	Nil 48,600 48,600	240,600(1) 192,000 192,000	Nil Nil Nil	Nil 300,000 100,000	Nil Nil Nil	Nil Nil Nil	Nil Nil Nil
David Matheson, Chief Financial Officer	2017 2016 2015	200,000(2) 200,000 200,000	Nil Nil Nil	Nil Nil Nil	Nil 400,000 100,000	Nil Nil Nil	Nil Nil Nil	Nil Nil Nil
Craig Sturrock, Director	2017 2016 2015	Nil Nil Nil	Nil Nil Nil	Nil Nil Nil	Nil 200,000 25,000	Nil Nil Nil	Nil Nil Nil	7,167(3) 7,500 8,000
Dr. A. Gorrell, Director	2017 2016 2015	Nil Nil Nil	Nil Nil Nil	Nil Nil Nil	Nil 150,000 20,000	Nil Nil Nil	Nil Nil Nil	5,167(4) 6,000 6,000
Ronnie Bozzer, Director	2017 2016 2015	Nil Nil Nil	Nil Nil Nil	Nil Nil Nil	Nil 200,000 35,000	Nil Nil Nil	Nil Nil Nil	7,500(5) 8,000(5) 8,000
Stan Page, Director(6)	2017	Nil	Nil	Nil	Nil	Nil	Nil	2,000(5)
James Dai, Director (7)	2017 2016 2015	Nil Nil Nil	Nil Nil Nil	Nil Nil Nil	Nil 150,000 100,000	Nil Nil Nil	Nil Nil Nil	3,167 8,000 5,500

(1)	Include an unpaid amount of $40,100 payable by the Company to Mr. Hodgkinson at December 31, 2017.
(2)	Include an unpaid amount of $49,000 payable by the Company to Mr. Matheson at December 31, 2017.
(3)	Include an unpaid amount of $4,000 payable by the Company to Mr. Sturrock at December 31, 2017.
(4)	Included an unpaid amount of $3,000 payable by the Company to Dr. Gorrell at December 31, 2017.
(5)	Included in accounts payable and accrued liabilities at December 31, 2017.
(6)	Mr. Page was appointed as a director of the Company on August 30, 2017.
(7)	Mr. Dai resigned from the Board on August 30, 2017. He ceased to be a director of the Company effective that date.

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Director Compensation

The Company has compensation agreements for its Directors who are not executive officers. Under the agreements, Directors receive $2,500 per meeting for the first 4 meetings each year, and $1,500 for each meeting thereafter. The Board of Directors may award special remuneration to any Director undertaking any special services on behalf of the Company other than services ordinarily required of a Director. Per an amendment to the agreements approved by the Board of Directors, effective January 1, 2010, the Directors received $1,000 per quarter plus $500 for each meeting.

For the most recently completed fiscal year, each non-management director of the Company earned total compensation for services provided to the Company in his capacity as director as follows:

Name	Fees earned $
Craig Sturrock	7,167(1)
Dr. A. Gorrell	5,167(2)
Ronnie Bozzer	7,500(3)
Stan Page(4)	2,000(3)
James Dai (5)	3,167

(1)	Include an unpaid amount of $4,000 payable by the Company to Mr. Sturrock at December 31, 2017.
(2)	Included an unpaid amount of $3,000 payable by the Company to Dr. Gorrell at December 31, 2017.
(3)	Included in accounts payable and accrued liabilities at December 31, 2017.
(4)	Mr. Page was appointed as a director of the Company on August 30, 2017.
(5)	Mr. Dai resigned from the Board on August 30, 2017. He ceased to be a director of the Company effective that date.

Long Term Incentive Plan Awards

Long term incentive plan awards ("LTIP") means any plan providing compensation intended to serve as an incentive for performance to occur over a period longer than one financial year, whether the performance is measured by reference to financial performance of the Company or an affiliate of the Company, the price of the Company's shares, or any other measure, but does not include option or stock appreciation rights plans or plans for compensation through restricted shares or units. The Company did not award any LTIPs to any executive officer during the most recently completed financial year ended December 31, 2017. There are no pension plan benefits in place for the executive officers.

Stock Appreciation Rights

Stock appreciation rights ("SARs") means a right, granted by the Company or any of its subsidiaries as compensation for services rendered or in connection with office or employment, to receive a payment of cash or an issue or transfer of securities based wholly or in part on changes in the trading price of the Company's shares. No SARs were granted to, or exercised by, any executive officer of the Company during the most recently completed financial year ended December 31, 2017.

Bonus/Profit Sharing/Non-Cash Compensation

The Board adopted a bonus plan for eligible executives, which include the senior executives of the Company or any subsidiary of the Company, including but not limited to the CEO, President, Executive Vice-President and CFO who, by the nature of their positions are, in the opinion of the Committee, in a senior position to contribute to the success of the Company.

The bonus plan includes both non-discretionary and discretionary portions.

A) Executives Non-Discretionary;

Each Eligible Executives will receive a USD$100,000 award should:

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i)

Total Shareholder Return % exceeds Total XEG Return % by a minimum of 10% and in addition. For purposes of the bonus plan, “XEG” is defined as the iShares™ CDN Energy Sector Index Fund, trading under the symbol “XEG” on the TSX. Total Shareholder Return and Total XEG Return are based on the 20 days average closing shares price of DXI Energy shares and XEG on the TSX at the end of each fiscal year.;

ii)

Total Shareholder Return is positive (the share price of DXI Energy shares is higher at the end of the year, in comparison to, the price of the shares at the beginning of the year).

For example, for fiscal 2011, if Total Shareholder Return % is 20%, while Total XEG Return is 5%, then DXI Energy’s stock outperformed the XEG by 15% and a USD$100,000 award is payable to each executives. However, this award would only be payable in the event that during the same period shareholder return is positive.

B) Executives Discretionary;

The Compensation Committee, upon the recommendation of the CEO, shall review (i) performance goals and objectives (“Performance Targets') for the Company and the subsidiaries for such period and (ii) target awards (“Target Awards') for each Participant which shall be based on, up to 30% of the Participant's base compensation, provided however, the Performance Targets for each Executive Participants shall be exactly the same during each year, calculated based on the same percentage of each Participants base compensation, unless otherwise agreed by the Participants.

Such Performance Targets shall include but not be limited to the following:

• Increase in oil & gas production;

• Achievement of financial stability and working capital position including compliance with the Company loan covenants;

• Increase in Proved Developed Production (PDP) Reserves;

• Increase in Proved and Probable (2P) reserves;

• Creating significant positive impact on the Company business as demonstrated by significant accomplishments not in the base budget/business plan;

• Increase in Operating Cash flow and Adjusted EBITDA;

• Reduce operation costs;

• Reducing overhead costs;

• Other factors or extraordinary success, that in the opinion of the Committee, enhance shareholder value.

Pension/Retirement Benefits

No funds were set aside or accrued by the Company during fiscal 2017 to provide pension, retirement or similar benefits for Directors or Senior Management.

C. Board Practices

The Company’s Governance Committee has establish the following committees to ensure the Company maintains the highest possible governance standards in the conduct of its business:

1.	Governance and Nominating Committee;
2.	Compensation Committee;
3.	Audit Committee, and
4.	Reserves Committee.

Each of the primary functions of these committees is located on the Company’s website at www.dxienergy.com as follows:

Governance and Nominating Committee

The Governance and Nominating Committee is comprised of three Directors, Ronnie Bozzer (Chairman), Craig Sturrock, and A. Ross Gorrell.

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(a)	“Responsibilities” for the Governance and Nominating Committee can be found on the Company’s website at www.dxienergy.com  under “Investors/Corporate Governance/Committees and Responsibilities/Governance and nominating Committee”.
(b)	The Company’s “Charter” for the Governance and Nominating Committee can be found on the Company’s website at www.dxienergy.com under “Investors/Corporate Governance/Governance and Nominating Committee Charter”.

Compensation Committee

The Company’s Compensation Committee is comprised of three Directors, Ronnie Bozzer (Chairman), A. Ross Gorrell, and Stan Page.

(a)	“Responsibilities” for the Compensation Committee can be found on the Company’s website at www.dxienergy.com under “Investors/Corporate Governance/Committees and Responsibilities/Compensation Committee”.
(b)	The Company’s “Charter” for the Compensation Committee can be found on the Company’s website at www.dxienergy.com under “Investors/Corporate Governance/Compensation Committee Charter”.

Audit Committee

The Company’s Audit Committee is comprised of three Directors, Craig Sturrock (Chairman), Ronnie Bozzer, and Stan Page.

(a)	“Responsibilities” for the Audit Committee can be found on the Company’s website at www.dxienergy.com under “Investors/Corporate Governance/Committees and Responsibilities/Audit Committee”.
(b)	The Company’s “Charter” for the Audit Committee can be found on the Company’s website at www.dxienergy.com under “Investors/Corporate Governance/Audit Committee Charter”.

Reserves Committee

The Company has a Reserves Committee comprised of three directors, Stan Page (Chairman), A. Ross Gorrell and Ronnie Bozzer.

(a)	“Responsibilities” for the Reserves Committee can be found on the Company’s website at www.dxienergy.com under “Investors/Corporate Governance/Committees and Responsibilities/Reserves Committee”.
(b)	The Company’s “Charter” for the Reserves Committee can be found on the Company’s website at www.dxienergy.com under “Investors/Corporate Governance/Reserves Committee Charter”.

Differences between Canadian and NYSE Governance Standards

DXI Energy’s corporate governance practices satisfy all the existing guidelines for effective corporate governance established by Canadian National Instrument 58-1-1 and National Policy 58-201 (collectively CSA Rules). The Company qualifies for and is currently listed on the OTCQB Venture Market in the OTC Markets Group in the United States. The Company qualifies for the OTCQB’s elevated status because it is a full SEC registrant in the United States. Although no longer listed on the NYSE, the Company still adheres to NYSE corporate governance standards and will continue to do so. The NYSE corporate governance listing standards applicable to DXI Energy’s corporate governance policies satisfy all the existing guidelines for effective corporate governance established by the CSA Rules. The rules of the New York Stock Exchange (“the NYSE”), as set for the in the NYSE Listed Company Manual (“the NYSE Manual”), permit listed companies that are “foreign private issuers”, as defined under the U.S. Securities Exchange Act of 1934, as amended (“The Exchange Act”), including DXI Energy, to follow home country practice in lieu of certain NYSE corporate governance provisions.

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The significant differences between DXI Energy’s corporate governance practices and those followed by NYSE-listed U.S. companies pursuant to the NYSE Manual can be found on the Company’s website at www.dxienergy.com under “Investors/Corporate Governance/DXI Energy Inc. Differences between Canadian and NYSE Governance Standards”.

D. Employees

The Company had the equivalent of approximately 10 full-time employees and consultants during 2017.

E. Share Ownership

Directors and Officer Beneficial Ownership

The following table discloses information regarding beneficial ownership of the Company’s voting securities, consisting solely of common shares, as of April 16, 2018 by the Company’s executive officers and directors.

Name of Beneficial Owner	Number of Common Shares	Percentage of Outstanding Common Shares Owned
Robert L. Hodgkinson	19,963,741(1)	19.27%
Craig Sturrock	307,783	0.30%
Dr. A. Gorrell	146,117	0.14%
Ronnie Bozzer	90,000	0.09%
Stan Page	-	0%
David Matheson	1,863,890	1.80%
Total	22,371,531	21.60%

(1)	10,870,404 of these shares are owned by Hodgkinson Equities Corp., a private company controlled by Robert Hodgkinson. The remaining 9,093,337 shares are owned by Robert Hodgkinson.
(2)	All percentages are based on 103,606,088 common shares outstanding as of April 16, 2018.

Stock Option Plan

We have a Stock Option Plan that was initially approved in 2009 and amended in 2012 and 2015 (the “Option Plan”). The principal purposes of which is to (i) advance our interests by aiding us, and our subsidiaries, in motivating, attracting and retaining key employees and directors capable of assuring the future success of the Company; and (ii) secure for us and our shareholders the benefits inherent in the ownership of our common shares by key employees and directors of the Company and our subsidiaries. We also have a United States stock incentive sub-plan that was initially approved in 2009 and amended in 2012 (the “Sub-Plan”) and forms a part of the Option Plan. Any option granted under the Sub-Plan is also subject to the terms and conditions of the Option Plan. Where there is a conflict between the terms and conditions of the Sub-Plan and the terms and conditions of the Option Plan, the terms and conditions of the Option Plan govern.

Directors, officers, employees and other insiders of us or any of our subsidiaries, as well as any person or corporation engaged to provide services for us or for any entity controlled by us for an initial, renewable or extended period of twelve months or more (or a lesser period of time if approved by the committee that administers the Option Plan and acceptable to the Toronto Stock Exchange (the “TSX”) (including individuals employed by such person or corporation), are eligible to participate in the Option Plan. Eligible participants who are natural persons resident in the United States, United States citizens, or are otherwise subject to United States tax law may participate in the Sub-Plan.

At the time of grant of any option, the aggregate number of common shares reserved for issuance under the Option Plan (which includes the Sub-Plan) that may be made subject to options any time and from time to time, together with common shares reserved for issuance at that time under any of our other share compensation arrangements, may not exceed 10% of the total number of issued and outstanding common shares, on a non-diluted basis, on the date of grant of the option. Of this 10%, the number of common shares reserved for issuance to any one participant pursuant to the Sub-Plan in any year may not exceed 5% of our total outstanding common shares on a non-diluted basis. Common shares subject to any option (or portion thereof) under the Option Plan that has been cancelled or otherwise terminated prior to the issuance or transfer of such common shares will again be available for options under the Option Plan. The number of common shares authorized under the Option Plan may be increased, decreased or fixed by the Board of Directors. Subject to adjustment in accordance with the Sub-Plan, a maximum of 3,700,000 common shares, less those common shares issued under the Option Plan, may be issued pursuant to stock options issued under the Sub-Plan. To clarify this rule, notwithstanding the number of options permitted under the US Sub-Plan to a total of 3.7 million, the Company is still bound by its Option Plan whereby the maximum number of shares that can be awarded as options is still 10%, but within the 10% as permitted, up to 3,700,000 can be allocated to the US Sub-Plan. If a stock option terminates, is forfeited or is cancelled without the issuance of any common shares, or any common shares covered by a stock option or to which a stock option relates are not issued for any other reason, then the number of common shares counted against the aggregate number of common shares available under the Sub-Plan with respect to such stock option, to the extent of any such termination, forfeiture, cancellation or other event, will again be available for granting stock options under the Sub-Plan.

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The option exercise price will be determined by the committee that administers the Option Plan or the Sub-Plan administrator, as applicable. The exercise price may not be less than the last closing price per common share on the TSX on the trading day immediately preceding the day the options are granted, or if the common shares are not listed on the TSX, on the most senior of any other exchange on which the common shares are then traded, on the last trading day immediately preceding the date of grant of such options.

The Option Plan may be terminated by the committee that administers the Option Plan at any time. The Sub-Plan terminates at midnight on January 5, 2022, unless it is terminated before then by our Board of Directors. Any option outstanding under the Option Plan or Sub-Plan at the time of termination shall remain in effect until such option has been exercised, has expired, has been surrendered to us or has been terminated.

A copy of the Option Plan and Sub-Plan is incorporated by reference into this Form 20-F as Exhibits 4.1 and 4.2, respectively.

Stock Options Outstanding

The names and titles of the Directors/Executive Officers of the Company to whom outstanding stock options have been granted and the number of common shares subject to such options is set forth in the following table as of April 16, 2018:

Name	No. of Options Held	No. of Options Vested	Exercise Price per Option	Grant Date	Expiration Date
Robert Hodgkinson	300,000	300,000	$0.16	June 6, 2016	June 5, 2021
Craig Sturrock	200,000	200,000	$0.16	June 6, 2016	June 5, 2021
Craig Sturrock	400,000	400,000	$0.09	January 18, 2018	December 30, 2020
Dr. A. Gorrell	150,000	150,000	$0.16	June 6, 2016	June 5, 2021
Dr. A. Gorrell	450,000	450,000	$0.09	January 18, 2018	December 30, 2020
Ronnie Bozzer	200,000	200,000	$0.16	June 6, 2016	June 5, 2021
Ronnie Bozzer	400,000	400,000	$0.09	January 18, 2018	December 30, 2020
Stan Page	600,000	600,000	$0.09	January 18, 2018	December 30, 2020
David Matheson	400,000	400,000	$0.16	June 6, 2016	June 5, 2021

ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS.

A. Major Shareholders

Shareholders

The Company is aware of one person who each beneficially own 5% or more of the Registrant's voting securities. The following table lists as of April 16, 2018 persons and/or companies holding 5% or more beneficial interest in the Company’s outstanding common stock.

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5% or Greater Shareholders as of April 16, 2018

Title of Class	Name of Shareholder	Number of Common Shares	Percent of Common Shares
Common	Robert L. Hodgkinson (1)(2)	19,963,741	19.27%

(1)	10,870,404 of these shares are owned by Hodgkinson Equities Corp., a private company controlled by Robert Hodgkinson. The remaining 9,093,337 shares are owned by Robert Hodgkinson.
(2)	58,441,558 shares are to be issued at a price of $0.077 per share if Hodgkinson Equities Corp. exercises the right to convert the entire loan amount of $4.5 million into shares.

All percentages are based on 103,606,088 common shares outstanding as of April 16, 2018.

Changes in ownership by major shareholders

To the best of the Company’s knowledge there have been no changes in the ownership of the Company’s shares other than disclosed herein.

Voting Rights

The Company’s major shareholders do not have different voting rights.

Shares Held in the United States

As of April 4, 2018, there were approximately 6,894 registered holders of the Company’s shares in the United States, with combined holdings of 32,903,503 common shares.

Change of Control

As of the date of this annual report, there were no arrangements known to the Company which may, at a subsequent date, result in a change of control of the Company.

Control by Others

To the best of the Company’s knowledge, the Company is not directly or indirectly owned or controlled by another corporation, any foreign government, or any other natural or legal person, severally or jointly.

B. Related Party Transactions

During the years ended December 31, 2017 and 2016, the Company entered into the following transactions with related parties:

(a)	Compensation awarded to key management included a total of salaries and consulting fees of $466,000 (2016 - $470,000) and non-cash stock-based compensation of $Nil (2016 - $80,000). Key management includes the Company’s officers and directors. The salaries and consulting fees are included in general and administrative expenses. Included in accounts payable and accrued liabilities at December 31, 2017 is $131,000 (December 31, 2016 - $262,000) owing to the two officers of the Company.
(b)	Interest expenses of $370,000 (2016 - $595,000) related to the loans from related parties were paid in cash to the CEO of the Company and his spouse or the companies controlled by or associated with the CEO of the Company. And, interest expenses of $139,000 (2016 - $Nil) related to the loans from related parties were paid via issuance of the Company’s shares to the companies controlled by or associated with the CEO of the Company.
(c)	In 2015, the Company entered into loan agreements with a director and officer of the Company and his spouse and the private companies associated with the director and officer of the Company. The terms and conditions of these agreements are described in the “Liquidity and Capital Resources” section under Item 5 “Operating and Financial Review and Prospects”.

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C. Interests of Experts and Counsel

Not Applicable.

ITEM 8. FINANCIAL INFORMATION.

A. Consolidated Statements and Other Financial Information

Financial Statements

Description	Page
Consolidated Financial Statements for the Years Ended December 31, 2017, 2016 and 2015	F-1 - F-36

Supplementary Oil and Gas Reserve Estimation and Disclosures (Unaudited) for the years ending December 31, 2017 and 2016

Legal Proceedings

The Directors and the management of the Company do not know of any material, active or pending, legal proceedings against them; nor is the Company involved as a plaintiff in any material proceeding or pending litigation.

The Directors and the management of the Company know of no active or pending proceedings against anyone that might materially adversely affect an interest of the Company.

Dividend Policy

The Company has not paid any dividends on its common shares. Any decision to pay dividends on common shares in the future will be made by the board of directors on the basis of the earnings, financial requirements and other conditions existing at such time.

B. Significant Changes

None.

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ITEM 9. THE OFFER AND LISTING

A. Offering and Listing Details

The Company’s common shares were listed on the New York Stock Exchange, or the NYSE, in the United States, under the symbol of “DXI”. The Company’s stock was voluntarily delisted from the NYSE MKT at the close of trading on Thursday, August 4, 2016. The Company’s common shares remain listed for trading on the Toronto Stock Exchange, or the TSX, in Canada, under the symbol of “DXI”. Effective August 5, 2016, the Company’s common shares are listed for trading on the OTCQB (“OTCQB”), in the United States, under the symbol of “DXIEF.”

The following table sets forth, for the periods indicated, the reported high and low prices:

	OTCQB (US$)		TSX (Cdn$)		NYSE (US$)
	High	Low	High	Low	High	Low
Annual High and Low Market Prices – Past 5 Years
Year Ended:
December 31, 2017	$0.132	$0.034	$0.165	$0.045	N/A	N/A
December 31, 2016	$0.14	$0.03	$0.37	$0.03	$0.30	$0.10
December 31, 2015	N/A	N/A	$1.10	$0.18	$0.93	$0.12
December 31, 2014	N/A	N/A	$1.80	$0.63	$1.65	$0.57
December 31, 2013	N/A	N/A	$1.30	$0.50	$1.23	$0.46
Quarterly High and Low Market Prices – Past 2 Years
Quarter Ended:
December 31, 2017	$0.132	$0.043	$0.165	$0.055	N/A	N/A
September 30, 2017	$0.059	$0.034	$0.075	$0.045	N/A	N/A
June 30, 2017	$0.065	$0.035	$0.080	$0.045	N/A	N/A
March 31, 2017	$0.089	$0.045	$0.110	$0.065	N/A	N/A
December 31, 2016	$0.08	$0.03	$0.11	$0.03	N/A	N/A
September 30, 2016	$0.14	$0.06	$0.19	$0.09	$0.18	$0.11
June 30, 2016	N/A	N/A	$0.31	$0.14	$0.26	$0.10
March 31, 2016	N/A	N/A	$0.37	$0.21	$0.30	$0.14
Monthly High and Low Market Prices – Most Recent 6 Months
March 31, 2018	$0.090	$0.053	$0.120	$0.070	N/A	N/A
February 28, 2018	$0.100	$0.069	$0.135	$0.095	N/A	N/A
January 31, 2018	$0.092	$0.060	$0.120	$0.075	N/A	N/A
December 31, 2017	$0.108	$0.069	$0.135	$0.100	N/A	N/A
November 30, 2017	$0.132	$0.063	$0.165	$0.075	N/A	N/A
October 31, 2017	$0.072	$0.043	$0.095	$0.055	N/A	N/A

On April 16, 2018, the closing price of our common shares on the TSX was Cdn$0.065 per common share and on the OTCQB was US$0.056 per common share.

B. Plan of Distribution

Not Applicable.

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C. Markets

Our common shares, no par value, are traded on the TSX in Canada under the symbol of “DXI” and the OTCQB in the United States under the symbol of “DXIEF”.

D. Selling Shareholders

Not Applicable.

E. Dilution

Not Applicable.

F. Expenses of the Issue

Not Applicable.

ITEM 10. ADDITIONAL INFORMATION

A. Share Capital

Not Applicable.

B. Memorandum and Articles of Association

DXI Energy Inc. is incorporated under the laws of British Columbia, Canada. The Company was originally incorporated as “Dejour Mines Limited” on March 29, 1968 under the laws of the Province of Ontario. By articles of amendment dated October 30, 2001, the issued shares were consolidated on the basis of one (1) new for every fifteen (15) old shares and the name of the Company was changed to Dejour Enterprises Ltd. On June 6, 2003, the shareholders approved a resolution to complete a one-for-three-share consolidation, which became effective on October 1, 2003. In 2005, the Company was continued in British Columbia under the Business Corporations Act (British Columbia) (the “Act”). Effective March 9, 2011, the Company changed its name from Dejour Enterprises Ltd. to Dejour Energy Inc. On October 27, 2015, the Company changed its name from Dejour Energy Inc. to DXI Energy Inc. and effected a five-to-one share consolidation of its common shares. The Company’s common shares began trading on a post-consolidation basis on October 30, 2015.

There are no restrictions on what business the Company may carry on in the Articles of Incorporation.

Under Article 17 of the Company’s Articles and under Part 5, Division 3 of the Act, a director must declare its interest in any existing or proposed contract or transaction with the Company and is not allowed to vote on any transaction or contract with the Company in which has a disclosable interest, unless all directors have a disclosable interest in that contract or transaction, in which case any or all of those directors may vote on such resolution. A director may hold any office or place of profit with the Company in conjunction with the office of director, and no director shall be disqualified by his office from contracting with the Company. A director or his firm may act in a professional capacity for the Company and he or his firm shall be entitled to remuneration for professional services. A director may become a director or other officer or employee of, or otherwise interested in, any corporation or firm in whom the Company may be interested as a shareholder or otherwise. The director shall not be accountable to the Company for any remuneration or other benefits received by him from such other corporation or firm subject to the provisions of the Act.

Article 16 of the Company’s Articles addresses the powers and duties of the directors. Directors must, subject to the Act, manage or supervise the management of the business and affairs of the Company and have the authority to exercise all such powers which are not required to be exercised by the shareholders as governed by the Act. Article 19 of the Company’s Articles addresses Committees of the Board of Directors. Directors may, by resolution, create and appoint an executive committee consisting of the director or directors that they deem appropriate. This executive committee has, during the intervals between meetings of the Board, all of the directors’ powers, except the power to fill vacancies in the Board, the power to remove a Director, the power to change the membership of, or fill vacancies in, any committee of the Board and any such other powers as may be set out in the resolution or any subsequent directors’ resolution. Directors may also by resolution appoint one or more committees other than the executive committee.

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These committees may be delegated any of the directors’ powers except the power to fill vacancies on the board of directors, the power to remove a director, the power to change the membership or fill vacancies on any committee of the directors, and the power to appoint or remove officers appointed by the directors. Article 18 of the Company’s Articles details the proceedings of directors. A director may, and the Secretary or Assistant Secretary, if any, on the request of a director must call a meeting of the directors at any time. The quorum necessary for the transaction of the business of the directors may be fixed by the directors and if not so fixed shall be deemed to a majority of the directors. If the number of directors is set at one, it quorum is deemed to be one director.

Article 8 of the Company’s Articles details the borrowing powers of the directors. They may, on behalf of the Company:

• Borrow money in a manner and amount, on any security, from any source and upon any terms and conditions as they deem appropriate;

• Issue bonds, debentures, and other debt obligations either outright or as security for any liability or obligation of the Company or any other person at such discounts or premiums and on such other terms as they consider appropriate;

• Guarantee the repayment of money by any other person or the performance of any obligation of any other person; and

• Mortgage, charge, or grant a security in or give other security on, the whole or any part of the present or future assets and undertaking of the Company.

A director need not be a shareholder of the Company, and there are no age limit requirements pertaining to the retirement or non-retirement of directors. The directors are entitled to the remuneration for acting as directors, if any, as the directors may from time to time determine. If the directors so decide, the remuneration of directors, if any, will be determined by the shareholders. The remuneration may be in addition to any salary or other remuneration paid to any officer or employee of the Company as such who is also a director. The Company must reimburse each director for the reasonable expenses that he or she may incur in and about the business of the Company. If any director performs any professional or other services for the Company that in the opinion of the directors are outside the ordinary duties of a director, or if any director is otherwise specially occupied in or about the Company’s business, he or she may be paid remuneration fixed by the directors, or, at the option of that director, fixed by ordinary resolution and such remuneration may be either in addition to, or in substitution for, any other remuneration that he or she may be entitled to receive. Unless other determined by ordinary resolution, the directors on behalf of the Company may pay a gratuity or pension or allowance on retirement to any director who has held any salaried office or place of profit with the Company or to his or her spouse or dependents and may make contributions to any fund and pay premiums for the purchase or provision of any such gratuity, pension or allowance.

Article 21 of the Company’s Articles provides for the mandatory indemnification of directors, former directors, and alternate directors, as well as his or hers heirs and legal personal representatives, or any other person, to the greatest extent permitted by the Act. The indemnification includes the mandatory payment of expenses actually and reasonably incurred by such person in respect of that proceeding. The failure of a director, alternate director, or officer of the Company to comply with the Act or the Company’s Articles does not invalidate any indemnity to which he or she is entitled. The directors may cause the Company to purchase and maintain insurance for the benefit of eligible parties who:

(a)	is or was a director, alternate director, officer, employee or agent of the Company;
(b)	is or was a director, alternate director, officer employee or agent of a corporation at a time when the corporation is or was an affiliate of the Company;
(c)	at the request of the Company, is or was a director, alternate director, officer, employee or agent of a corporation or of a partnership, trust, joint venture or other unincorporated entity;

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(d) at the request of the Company, holds or held a position equivalent to that of a director, alternate director or officer of a partnership, trust, joint venture or other unincorporated entity;

against any liability incurred by him or her as such director, alternate director, officer, employee or agent or person who holds or held such equivalent position

Under Article 9 of the Company’s Articles and subject to the Act, the Company may alter its authorized share structure by directors’ resolution or ordinary resolution, in each case determined by the directors, to:

(a)	create one or more classes or series of shares or, if none of the shares of a series of a class or series of shares are allotted or issued, eliminate that class or series of shares;
(b)	increase, reduce or eliminate the maximum number of shares that the Company is authorized to issue out of any class or series of shares or establish a maximum number of shares that the company is authorized to issue out of any class or series of shares for which no maximum is established;
(c)	subdivide or consolidate all or any of its unissued, or fully paid issued, shares;
(d)	if the Company is authorized to issue shares of a class or shares with par value;

(i)	decrease the par value of those shares; or
(ii)	if none of the shares of that class of shares are allotted or issued, increase the par value of those shares;

(e)	change all or any of its unissued, or fully paid issued, shares with par value into shares without par value or any of its unissued shares without par value into shares with par value;
(f)	alter the identifying name of any of its shares; or

by ordinary resolution otherwise alter its share or authorized share structure.

Subject to Section9.2 of the Company’s Articles and the Act, the Company may:

(1)

by directors’ resolution or ordinary resolution, in each case determined by the directors, create special rights or restrictions for, and attach those special rights or restrictions to, the shares of any class or series of shares, if none of those shares have been issued, or vary or delete any special rights or restrictions attached to the shares of any class or series of shares, if none of those shares have been issued; and

(2)

by special resolution of the shareholders of the class or series affected, do any of the acts in Section 9.1 of the Company’s Articles if any of the shares of the class or series of shares has been issued.

The Company may by resolution of its directors or by ordinary resolution, in each case as determined by the directors, authorize an alteration of its Notice of Articles in order to change its name.

The directors may, whenever they think fit, call a meeting of shareholders. An annual general meeting shall be held once every calendar year at such time (not being more than 15 months after holding the last preceding annual meeting) and place as may be determined by the Directors.

There are no limitations upon the rights to own securities.

There is no special ownership threshold above which an ownership position must be disclosed. However, any ownership level above 10% must be disclosed to the TSX and all applicable Canadian Securities Commission.

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Description of Share Capital

The Company is authorized to issue an unlimited number of common shares, preferred shares and series 1 preferred shares of which, as of April 16, 2018, 103,606,088 common shares, are issued and outstanding. The rights, preferences and restrictions attaching to each class of the Company’s shares are as follows:

Common Shares

All the common shares of the Company are of the same class and, once issued, rank equally as to dividends, voting powers, and participation in assets. All common shareholders are entitled to receive notice of, attend and be heard at any meeting of shareholders of the Company, except a meeting of the holders of shares of another class, as such, and except a meeting of the holders of a particular series, as such. Holders of shares of common stock are entitled to one vote for each share held of record on all matters to be acted upon by the shareholders, including the election of directors. Except as otherwise required by law the holders of the Company’s common shares will possess all voting power. Generally, all matters to be voted on by shareholders must be approved by a majority (or, in the case of election of directors, by a plurality) of the votes entitled to be cast by all common shares that are present in person or represented by proxy. Subject to the special rights and restrictions attached to the shares of any class or series of classes, one holder of common shares issued, outstanding and entitled to vote, represented in person or by proxy, is necessary to constitute a quorum at any meeting of our shareholders.

Upon liquidation, dissolution or winding up of the Company, whether voluntary or involuntary, or other disposition of the property or assets of the Company, holders of shares of common stock are entitled to receive pro rata the assets of Company, if any, remaining after payments of all debts and liabilities to the holders of preferred shares or any other shares ranking senior to shares of common stock. No shares have been issued subject to call or assessment. There are no preemptive or conversion rights and no provisions for redemption or purchase for cancellation, surrender, or sinking or purchase funds.

The holders of the Company’s common shares will be entitled to such cash dividends as may be declared from time to time by our Board of Directors but such dividend will rank junior to the holders of preferred shares and series 1 preferred shares.

In the event of any merger or consolidation with or into another company in connection with which the Company’s common shares are converted into or exchangeable for shares, other securities or property (including cash), all holders of the Company’s common shares will be entitled to receive the same kind and amount of shares and other securities and property (including cash).

There are no indentures or agreements limiting the payment of dividends on the Company’s common shares and there are no special liquidation rights or subscription rights attaching to the Company’s common shares.

Preferred Shares

Preferred shares may, at any time and from time to time, be issued in one or more series and the Company may, by directors’ resolution or ordinary resolution, do one or more of the following:

• determine the maximum number of shares of any of those series of preferred shares that the Company is authorized to issue, determine that there is no maximum number or alter any determination made or otherwise, in relation to a maximum number of those shares, and authorize the alteration of the Notice of Articles accordingly;

• alter the Articles of the Company, and authorize the alteration of the Notice of Articles, to create an identifying name by which the shares of any of those series of preferred shares may be identified or to alter any identifying name created for those shares; and

• alter the Articles of the Company, and authorize the alteration of the Notice of Articles, to attach special rights or restrictions to the shares of any of those series of preferred shares or to alter any special rights or restrictions attached to those shares, subject to the special rights and restrictions attached to the preferred shares.

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If the alterations, determinations or authorizations contemplated above are to be made in relation to a series of shares of which there are issued shares, those alterations, determinations or authorizations may be made by ordinary resolution. However, no special rights or restrictions attached to a series of preferred shares shall confer on the series of preferred shares priority over another series of preferred shares respecting (i) dividends or (ii) return of capital on the dissolution of the Company or on the occurrence of any event that entitles the shareholders holding the shares of all series of preferred shares to a return of capital.

All holders of preferred shares shall not be entitled to receive notice of, attend and be heard at any meeting of or vote at any meeting of shareholders of the Company, except any specific meeting of the holders of preferred shares.

The holders of the Company’s preferred shares will be entitled to such cash dividends as may be declared from time to time by our Board of Directors and shall rank senior to the holders of our common shares and any other shares of the Company ranking junior to the preferred shares.

Upon liquidation, dissolution or winding up of the Company, whether voluntary or involuntary, or other disposition of the property or assets of the Company, holders of the holders of the Preferred Shares, including the Series 1 Preferred Shares, shall be entitled to receive, for each preferred share held, from the property and assets of the Company, a sum equivalent to the amount paid up thereon together with the premium (if any) thereon and any dividends declared thereon before any amount shall be paid or any property or asset of the Company is distributed to the holders of the common shares or any other shares ranking junior to the preferred shares with respect to repayment of capital. After payment to the holders of the preferred shares of the amount so payable to them, the holders of the preferred shares shall not be entitled to share in any further distribution of the property or assets of the Company except as specifically provided in special rights and restrictions attached to any particular series of preferred shares.

Series 1 Preferred Shares

The Company may, at any time and from time to time, issue series 1 preferred shares. The Company may, by directors’ resolution or ordinary resolution passed before the issue of any series 1 preferred shares, in each case as determined by the directors or, if there are issued series 1 preferred shares, by ordinary resolution, do one or more of the following:

• determine the maximum number of the series 1 preferred shares that the Company is authorized to issue, determine that there is no maximum number or alter any determination made in relation to a maximum number of those shares, and authorize the alteration of the Notice of Articles accordingly;

• alter the Articles of the Company, and authorize the alteration of the Notice of Articles, to alter the name of the series 1 preferred shares; and

• alter the Articles of the Company, and authorize the alteration of the Notice of Articles, to attach special rights or restrictions to the series 1 preferred shares or to alter any special rights or restrictions attached to those shares, subject to the special rights and restrictions attached to the preferred shares.

The special rights and restrictions that may be attached to the series 1 preferred shares may include, without in any way limiting or restricting the generality of such paragraph, rights and restrictions respecting the following:

• the rate or amount of dividends, whether cumulative, non-cumulative or partially cumulative and the dates, places and currencies of payment thereof;

• the consideration for, and the terms and conditions of, any purchase for cancellation or redemption thereof, including redemption after a fixed term or at a premium, conversion or exchange rights;

• the terms and conditions of any share purchase plan or sinking fund;

• the restrictions respecting the payment of dividends on, or the repayment of capital in respect of, any other shares of the Company;

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• voting rights; and

• the issuance of any shares of any other class or series of shares of the Company or any evidences of indebtedness or any other securities convertible into or exchangeable for such shares

No special rights or restrictions attached to the series 1 preferred shares confers on the series 1 preferred shares priority over another series of preferred shares respecting (i) dividends or (ii) return of capital on the dissolution of the Company or on the occurrence of any event that entitles the shareholders holding the shares of all series of preferred shares to a return of capital.

All holders of series 1 preferred shares are not entitled to receive notice of, attend and be heard at any meeting of or vote at any meeting of shareholders of the Company, except any specific meeting of the holders of series 1 preferred shares.

The holders of the Company’s series 1 preferred shares will be entitled to such cash dividends as may be declared from time to time by the Company’s Board of Directors and will rank senior to the holders of the Company’s common shares and any other shares of the Company ranking junior to the preferred shares.

Dividend Record

The Company has not paid any dividends on its common shares and has no policy with respect to the payment of dividends.

Ownership of Securities and Change of Control

There are no limitations on the rights to own securities, including the rights of non-resident or foreign shareholders to hold or exercise voting rights on the securities imposed by foreign law or by the constituent documents of the Company.

Any person who beneficially owns, directly or indirectly, or exercises control or direction over more than 10% of the Company’s voting shares is considered an insider, and must file an insider report with the Canadian regulatory commissions within ten days of becoming an insider, disclosing any direct or indirect beneficial ownership of, or control or direction over securities of the Company. In addition, if the Company itself holds any of its own securities, the Company must disclose such ownership.

There are no provisions in the Company’s Articles or Notice of Articles that would have an effect of delaying, deferring or preventing a change in control of the Company operating only with respect to a merger, acquisition or corporate restructuring involving the Company or its subsidiaries.

Differences from Requirements in the United States

Except for the Company’s quorum requirements, certain requirements related to related party transactions and the requirement for notice of shareholder meetings, discussed above, there are no significant differences in the law applicable to the Company, in the areas outlined above, in Canada versus the United States. In most states in the United States, a quorum must consist of a majority of the shares entitled to vote. Some states allow for a reduction of the quorum requirements to less than a majority of the shares entitled to vote. Having a lower quorum threshold may allow a minority of the shareholders to make decisions about the Company, its management and operations. In addition, most states in the United States require that a notice of meeting be mailed to shareholders prior to the meeting date. Additionally, in the United States, a director may not be able to vote on the approval of any transaction in which the director has an interest.

C. Material Contracts

The following are material contracts to which the Company is a party:

Financial Contract with a U.S. Oil and Gas Drilling Fund

On December 31, 2012, Dejour USA entered into a financial contract with a U.S. oil and gas drilling fund (“Drilling Fund”) to fund the drilling of up to three wells and the completion of up to four wells in the State of Colorado. The total amount contributed by the Drilling Fund was US$7,000,000.

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The financial contract contains a provision whereby Dejour USA must purchase the Drilling Funds’ working interest in the four wells funded by the US$7,000,000 if the Drilling Fund fails to obtain a certain minimum return on investment by September 30, 2016. A subsequent amendment limited Dejour USA’s cash exposure to a potential “put” by the Drilling Fund to US$3,000,000, with the difference to be settled by an assignment of working interests in certain P&NG properties owned by Dejour USA. The Company is not a party to the financial contract.

On September 30, 2016, the Drilling Fund served notice to Dejour USA requiring Dejour USA to purchase the Drilling Funds’ working interest in the 4 wellbores in accordance with the contract. However, prior to serving such notice, the Drilling Fund executed certain assignments transferring ownership of its working interests in the 4 wellbores to another entity and the assignee mortgaged its interest therein. Dejour USA and its attorneys are reviewing the impact of the Drilling Fund’s actions on the validity of the financial contract between the parties.

As at December 31, 2017, Dejour USA has recorded a liability owing to the Drilling Fund of $6,752,000 (US$5,382,000). This amount, if any, is subject to a resolution of the financial contract between the parties. Dejour USA has received no formal communication from the Drilling Fund since the “put” notice date of September 30, 2016.

HEC loan to the Company

On March 12, 2015, as amended on May 6, 2015, June 22, 2015, September 28, 2015, November 18, 2015 and June 5, 2017, the Company issued a promissory note for $4.5 million to Hodgkinson Equities Corp. (“HEC”), a private company controlled by the CEO of the Company. The promissory note is secured by all assets of Dejour USA and a negative pledge by the Company not to further encumber its Canadian oil and gas properties without HEC’s prior approval. The principal and interest at Canadian prime rate plus 5% per annum was repayable by the earlier of (i) within 10 business days of receipt of written demand from HEC for the repayment and (ii) June 10, 2015 or such later date to which the term of the promissory note may be extended. On May 6, 2015, the due date of the loan was extended to September 30, 2015. On September 28, 2015, the due date of the loan was further extended to December 31, 2015. On November 18, 2015, the Company extended the due date of the loan from December 31, 2015 to November 30, 2018. Additionally, a monthly principal repayment of $114,230.77 is due on the 1^st day of each month commencing June 1, 2016. HEC agreed to waive the requirement of the Company to repay the total monthly principal repayments of $1,371,000 until the loan was restructured on June 5, 2017. In consideration for the extension, the Company issued HEC 9,000,000 Warrants. Each Warrant entitles the holder to acquire one common share at a price of C$0.45/US$ 0.35 per share any time prior to December 4, 2020. Shares acquired through the exercise of Warrants prior to April 5, 2016 were restricted from sale through the facilities of the stock exchanges. On February 19, 2016, the Company rescinded the negative pledge security agreement and issued a first mortgage in favour of HEC on its Canadian oil and gas properties. The first mortgage security so issued ranked “pari passu” with HVI’s first mortgage security interest. On June 5, 2017, the Company restructured the term of the loan with extension of the due date from November 30, 2018 to June 5, 2022; reduction of the interest rate to Canadian prime rate plus 1% per annum; and the right to convert the entire outstanding amount into 58,441,558 common shares of the Company at a price of $0.077 per share. In exchange for the modification, HEC agreed to cancel the 9,000,000 warrants described above. Upon an event of default, all the indebtedness under the promissory note become due and payable and the interest rate is immediately increased to the Canadian prime rate plus 4.5% per annum.

HVI loan to the Company

On June 22, 2015, as amended on September 28, 2015, November 18, 2015 and June 5, 2017, the Company issued a promissory note for $2.0 million to Hodgkinson Ventures Inc. (“HVI”), a private company associated with the CEO of the Company, on a “pari passu” basis with the loan from HEC. The promissory note is secured by all assets of Dejour USA and a negative pledge by the Company not to further encumber its Canadian oil and gas properties without HVI’s prior approval. The principal and interest at Canadian prime rate plus 5% per annum was repayable on or before September 30, 2015. On September 28, 2015, the due date of the loan was extended to December 31, 2015. On November 18, 2015, the Company extended the due date of the loan from December 31, 2015 to November 30, 2018. Additionally, a monthly principal repayment of $50,769.23 is due on the 1^st day of each month commencing June 1, 2016. HVI agreed to waive the requirement of the Company to repay the total monthly principal repayments of $660,000 until the loan was restructured on June 5, 2017. In consideration for the extension, the Company issued HVI 4,000,000 Warrants. Each Warrant entitles the holder to acquire one common share at a price of C$0.45/US$ 0.35 per share any time prior to December 4, 2020. Shares acquired through the exercise of Warrants prior to April 5, 2016 were restricted from sale through the facilities of the stock exchanges. On February 19, 2016, the Company rescinded the negative pledge security agreement and issued a first mortgage in favour of HVI on its Canadian oil and gas properties. The first mortgage security so issued ranked “pari passu” with HEC’s first mortgage security interest. On June 5, 2017, the Company restructured the term of the loan with extension of the due date from November 30, 2018 to June 5, 2022; reduction of the interest rate to Canadian prime rate plus 1% per annum; and the right to convert the entire outstanding amount into 25,974,025 common shares of the Company at a price of $0.077 per share. In exchange for the modification, HVI agreed to cancel the 4,000,000 warrants described above. Upon an event of default, all the indebtedness under the promissory note become due and payable and the interest rate is immediately increased to the Canadian prime rate plus 4.5% per annum.

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Funding and Participation Agreement with a U.S. investment partner

On December 22, 2017, the Company signed a “Funding and Participation Agreement” (“the Agreement”) with a private U.S. based investment firm to underwrite 50% of the capital costs of at least one exploration well at Woodrush, currently scheduled to commence in the first quarter of 2018. Under the terms of the Agreement, the investment firm will pay approximately two-thirds of the total cost of the first well of the 2018 program, through tie in, to earn a 15% Gross Overriding Royalty (“GORR”).

The investment firm has the right to elect to participate in the drilling and completion of a 2^nd and subsequent wells, if any, by paying 50% of the capital costs to earn a 15% GORR in the well spacing unit on a well-by-well basis.

D. Exchange Controls

There are no governmental laws, decrees, or regulations in Canada relating to restrictions on the export or import of capital, or affecting the remittance of interest, dividends, or other payments to non-resident holders of the Company’s common stock. Any remittances of dividends to United States residents are, however, subject to Canadian withholding tax at the rate of 25% under the Canadian Tax Act. However, pursuant to Article X of the reciprocal tax treaty between Canada and the United States, if the U.S. Holder is entitled to benefit under the Treaty, the applicable rate of Canadian withholding tax is generally reduced to 15% (a further reduction of 10% may be applicable if the shareholder is a corporation owning at least 10% of the outstanding Common Stock of the Company.

Except as provided in the Investment Canada Act (the “ICA”), there are no limitations specific to the rights of non-Canadians to hold or vote the common shares of the Company under the laws of Canada or the Province of British Columbia or in the charter documents of the Company.

Management of the Company considers that the following general summary is materially complete and fairly describes those provisions of the ICA pertinent to an investment by an American investor in the Company.

The ICA requires a non-Canadian making an investment which would result in the acquisition of control of a Canadian business, the gross value of the assets of which exceed certain threshold levels or the business activity of which is related to Canada’s cultural heritage or national identity, to either notify, or file an application for review with, Investment Canada, the federal agency created by the ICA.

The notification procedure involves a brief statement of information about the investment of a prescribed form which is required to be filed with Investment Canada by the investor at any time up to 30 days following implementation of the investment. It is intended that investments requiring only notification will proceed without government intervention unless the investment is in a specific type of business activity related to Canada’s cultural heritage and national identity.

If an investment is reviewable under the ICA, an application for review in the form prescribed is normally required to be filed with Investment Canada prior to the investment taking place and the investment may not be implemented until the review has been completed and the Minister responsible for Investment Canada is satisfied that the investment is likely to be of net benefit to Canada. If the Minister is not satisfied that the investment is likely to be of net benefit to Canada, the non-Canadian must not implement the investment or, if the investment has been implemented, may be required to divest himself of control of the business that is the subject of the investment.

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The following investments by non-Canadians are subject to notification under the ICA:

(a)	an investment to establish a new Canadian business; and
(b)	an investment to acquire control of a Canadian business that is not reviewable pursuant to the ICA.

An investment is reviewable under the ICA if there is an acquisition by a non-Canadian of a Canadian business and the asset value of the Canadian business being acquired equals or exceeds the following thresholds:

(a)	for non-WTO Investors, the threshold is $5,000,000 for a direct acquisition and over $50,000,000 for an indirect acquisition. The $5,000,000 threshold will apply however for an indirect acquisition if the asset value of the Canadian business being acquired exceeds 50% of the asset value of the global transaction;
(b)	except as specified in paragraph (c) below, a threshold is calculated annually for reviewable direct acquisitions by or from WTO Investors. The threshold for 2012 is $330,000,000. Pursuant to Canada’s international commitments, indirect acquisitions by or from WTO Investors are not reviewable; and
(c)	the limits set out in paragraph (a) apply to all investors for acquisitions of a Canadian business that is a cultural business.:

WTO Investor as defined in the ICA means:

(a)	an individual, other than a Canadian, who is a national of a WTO Member or who has the right of permanent residence in relation to that WTO Member;
(b)	a government of a WTO Member, whether federal, state or local, or an agency thereof;
	an entity that is not a Canadian-controlled entity, and that is a WTO investor-controlled entity, as determined in accordance with the ICA;
(c)	a corporation or limited partnership:

(i)	that is not a Canadian-controlled entity, as determined pursuant to the ICA;
(ii)	that is not a WTO investor within the meaning of the ICA;
(iii)	of which less than a majority of its voting interests are owned by WTO investors;
(iv)	that is not controlled in fact through the ownership of its voting interests; and
(v)	of which two thirds of the members of its board of directors, or of which two thirds of its general partners, as the case may be, are any combination of Canadians and WTO investors;

(d) a trust:

(i)	that is not a Canadian-controlled entity, as determined pursuant to the ICA;
(ii)	that is not a WTO investor within the meaning of the ICA;
(iii)	that is not controlled in fact through the ownership of its voting interests, and
(iv)	of which two thirds of its trustees are any combination of Canadians and WTO investors, or

(e) any other form of business organization specified by the regulations that is controlled by a WTO investor.

WTO Member as defined in the ICA means a member of the World Trade Organization.

Generally, an acquisition is direct if it involves the acquisition of control of the Canadian business or of its Canadian parent or grandparent and an acquisition is indirect if it involves the acquisition of control of a non-Canadian parent or grandparent of an entity carrying on the Canadian business. Control may be acquired through the acquisition of actual or de jure voting control of a Canadian corporation or through the acquisition of substantially all of the assets of the Canadian business. No change of voting control will be deemed to have occurred if less than one-third of the voting control of a Canadian corporation is acquired by an investor.

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The ICA specifically exempts certain transactions from either notification or review. Included among the category of transactions is the acquisition of voting shares or other voting interests by any person in the ordinary course of that person’s business as a trader or dealer in securities.

E. Taxation

CANADIAN FEDERAL INCOME TAX CONSIDERATIONS

The following summary describes the principal Canadian federal income tax considerations generally applicable to a holder who is the beneficial holder of common shares of the Company and who, at all relevant times, for the purposes of the application of the Income Tax Act (Canada) and the Income Tax Regulations (collectively, the “Canada Tax Act”) (i) deals at arm’s length with the Company, (ii) is not affiliated with the Company, (iii) holds the common shares as capital property, and (iv) who, for the purposes of the Canada Tax Act and the Canada – United States Income Tax Convention (the “Treaty”), is at all relevant times resident in and only in the United States, is a qualifying person entitled to all of the benefits of the Treaty, and (v) does not use or hold and is not deemed to use or hold the shares in carrying on a business in Canada (a “U.S. Holder”). Special rules, which are not discussed below, may apply to a U.S. Holder that is an insurer or authorized foreign bank that carries on business in Canada and elsewhere.

This summary is based on the current provisions of the Canada Tax Act and the current published administrative policies and assessing practices of the Canada Revenue Agency (“CRA”) published in writing prior to the date hereof. This summary also takes into account all specific proposals to amend the Canada Tax Act and Regulations publicly announced by the Minister of Finance (Canada) prior to the date hereof (collectively, the “Tax Proposals”) and assumes all Tax Proposals will be enacted in the form proposed. There is no certainty that the Tax Proposals will be enacted in the form proposed, if at all. This summary does not otherwise take into account or anticipate any changes in laws or administrative policy or assessing practice whether by judicial, regulatory, administrative or legislative decision or action nor does it take into account provincial, territorial or foreign income tax legislation or considerations.

This summary is of a general nature only and is not, and is not intended to be, nor should it be construed to be, legal or tax advice to any particular purchaser of Units. This summary is not exhaustive of all Canadian federal income tax considerations. Accordingly, purchasers should consult their own tax advisors regarding the income tax consequences of purchasing Units based on their particular circumstances.

Dividends

Dividends paid or credited or deemed to be paid or credited to a U.S. Holder by the Company will be subject to Canadian withholding tax at the rate of 25% under the Canada Tax Act, subject to any reduction in the rate of withholding to which the U.S. Holder is entitled under the Treaty. For example, if the U.S. Holder is entitled to benefits under the Treaty and is the beneficial owner of the dividends, the applicable rate of Canadian withholding tax is generally reduced to 15%. The rate of Canadian withholding tax for such U.S. Holder will generally be further reduced under the Treaty to 5% if such holder is a corporation that beneficially owns at least 10% of the voting shares of the Company, and may be further reduced to nil if such holder is a qualifying pension TRUST i/o fund.

Dispositions

A U.S. Holder will not be subject to tax under the Canada Tax Act on any capital gain realized on a disposition of a common share (including a deemed disposition on death), unless the common share is or is deemed to be “taxable Canadian property” to the U.S. Holder for the purposes of the Canada Tax Act.

Generally, provided the Shares are listed on a “designated stock exchange” as defined in the Canada Tax Act (which includes the TSX) at the time of disposition, the Shares will not constitute taxable Canadian property of a U.S. Holder, unless at any time during the 60-month period immediately preceding the disposition, the U.S. Holder, persons with whom the U.S. Holder did not deal at arm’s length, or the U.S. Holder together with all such persons, owned 25% or more of the issued shares of any class of shares of the Company and more than 50% of the fair market value of those shares was derived directly or indirectly from any one or combination of (i) real or immovable property situated in Canada,(ii) Canadian resource properties, (iii) timber resource properties, and (iv) options in respect of, or interests in, or for civil rights law rights in, property described in any of (i) to (iii), whether or not that property exists.

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U.S. Holders whose common shares may constitute taxable Canadian property should consult with their own tax advisors.

CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

The following is a general summary of certain material U.S. federal income tax considerations applicable to a U.S. Holder (as defined below) arising from and relating to the acquisition, ownership, and disposition of common shares of the Company.

This summary is for general information purposes only and does not purport to be a complete analysis or listing of all potential U.S. federal income tax considerations that may apply to a U.S. Holder arising from and relating to the acquisition, ownership, and disposition of common shares. In addition, this summary does not take into account the individual facts and circumstances of any particular U.S. Holder that may affect the U.S. federal income tax consequences to such U.S. Holder, including specific tax consequences to a U.S. Holder under an applicable tax treaty. Accordingly, this summary is not intended to be, and should not be construed as, legal or U.S. federal income tax advice with respect to any U.S. Holder. Each U.S. Holder should consult its own tax advisor regarding the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local, and foreign tax consequences relating to the acquisition, ownership and disposition of common shares.

No legal opinion from U.S. legal counsel or ruling from the Internal Revenue Service (the “IRS”) has been requested, or will be obtained, regarding the U.S. federal income tax consequences of the acquisition, ownership, and disposition of common shares. This summary is not binding on the IRS, and the IRS is not precluded from taking a position that is different from, and contrary to, the positions taken in this summary. In addition, because the authorities on which this summary is based are subject to various interpretations, the IRS and the U.S. courts could disagree with one or more of the positions taken in this summary.

Scope of this Summary

Authorities

This summary is based on the Internal Revenue Code of 1986, as amended (the “Code”), Treasury Regulations (whether final, temporary, or proposed), published rulings of the IRS, published administrative positions of the IRS, U.S. court decisions, the Convention Between Canada and the United States of America with Respect to Taxes on Income and on Capital, signed September 26, 1980, as amended (the “Treaty”), and U.S. court decisions that are applicable and, in each case, as in effect and available, as of the date of this document. Any of the authorities on which this summary is based could be changed in a material and adverse manner at any time, and any such change could be applied on a retroactive or prospective basis which could affect the U.S. federal income tax considerations described in this summary. This summary does not discuss the potential effects, whether adverse or beneficial, of any proposed legislation that, if enacted, could be applied on a retroactive or prospective basis.

U.S. Holders

For purposes of this summary, the term "U.S. Holder" means a beneficial owner of common shares that is for U.S. federal income tax purposes:

• an individual who is a citizen or resident of the U.S.;

• a corporation (or other entity taxable as a corporation for U.S. federal income tax purposes) organized under the laws of the U.S., any state thereof or the District of Columbia;

• an estate whose income is subject to U.S. federal income taxation regardless of its source; or

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• a trust that (a) is subject to the primary supervision of a court within the U.S. and the control of one or more U.S. persons for all substantial decisions or (b) has a valid election in effect under applicable Treasury regulations to be treated as a U.S. person.

Non-U.S. Holders

For purposes of this summary, a “non-U.S. Holder” is a beneficial owner of common shares that is not a U.S. Holder. This summary does not address the U.S. federal income tax consequences to non-U.S. Holders arising from and relating to the acquisition, ownership, and disposition of common shares. Accordingly, a non-U.S. Holder should consult its own tax advisor regarding the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local, and foreign tax consequences (including the potential application of and operation of any income tax treaties) relating to the acquisition, ownership, and disposition of common shares.

U.S. Holders Subject to Special U.S. Federal Income Tax Rules Not Addressed

This summary does not address the U.S. federal income tax considerations applicable to U.S. Holders that are subject to special provisions under the Code, including the following U.S. Holders: (a) U.S. Holders that are tax-exempt organizations, qualified retirement plans, individual retirement accounts, or other tax-deferred accounts; (b) U.S. Holders that are financial institutions, underwriters, insurance companies, real estate investment trusts, or regulated investment companies; (c) U.S. Holders that are dealers in securities or currencies or U.S. Holders that are traders in securities that elect to apply a mark-to-market accounting method; (d) U.S. Holders that have a “functional currency” other than the U.S. dollar; (e) U.S. Holders that own common shares as part of a straddle, hedging transaction, conversion transaction, constructive sale, or other arrangement involving more than one position; (f) U.S. Holders that acquired common shares in connection with the exercise of employee stock options or otherwise as compensation for services; (g) U.S. Holders that hold common shares other than as a capital asset within the meaning of Section 1221 of the Code (generally, property held for investment purposes); (h) partnerships and other pass-through entities (and investors in such partnerships and entities); or (i) U.S. Holders that own or have owned (directly, indirectly, or by attribution) 10% or more of the total combined voting power of the outstanding shares of the Company. This summary also does not address the U.S. federal income tax considerations applicable to U.S. Holders who are: (a) U.S. expatriates or former long-term residents of the U.S. subject to Section 877 of the Code; (b) persons that have been, are, or will be a resident or deemed to be a resident in Canada for purposes of the Act; (c) persons that use or hold, will use or hold, or that are or will be deemed to use or hold common shares in connection with carrying on a business in Canada; (d) persons whose common shares constitute “taxable Canadian property” under the Act; or (e) persons that have a permanent establishment in Canada for the purposes of the Treaty. U.S. Holders that are subject to special provisions under the Code, including U.S. Holders described immediately above, should consult their own tax advisor regarding the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local, and foreign tax consequences relating to the acquisition, ownership and disposition of common shares.

If an entity that is classified as a partnership (or pass-through entity) for U.S. federal income tax purposes holds common shares, the U.S. federal income tax consequences to such partnership and the partners of such partnership generally will depend on the activities of the partnership and the status of such partners. Partners of entities that are classified as partnerships for U.S. federal income tax purposes should consult their own tax advisor regarding the U.S. federal income tax consequences arising from and relating to the acquisition, ownership, and disposition of common shares.

Tax Consequences Not Addressed

This summary does not address the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local, and foreign tax consequences to U.S. Holders of the acquisition, ownership, and disposition of common shares. Each U.S. Holder should consult its own tax advisor regarding the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local, and foreign tax consequences of the acquisition, ownership, and disposition of common shares.

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U.S. Federal Income Tax Consequences of the Acquisition, Ownership, and Disposition of Common Shares

If the Company is not considered a “passive foreign investment company” (a “PFIC”, as defined below) at any time during a U.S. Holder’s holding period, the following sections will generally describe the U.S. federal income tax consequences to U.S. Holders of the acquisition, ownership, and disposition of the Company’s common shares.

Distributions on Common Shares

A U.S. Holder that receives a distribution, including a constructive distribution, with respect to a common share will be required to include the amount of such distribution in gross income as a dividend (without reduction for any Canadian income tax withheld from such distribution) to the extent of the current or accumulated “earnings and profits” of the Company, as computed for U.S. federal income tax purposes. A dividend generally will be taxed to a U.S. Holder at ordinary income tax rates. To the extent that a distribution exceeds the current and accumulated “earnings and profits” of the Company, such distribution will be treated first as a tax-free return of capital to the extent of a U.S. Holder’s tax basis in the common shares and thereafter as gain from the sale or exchange of such common shares (see “Sale or Other Taxable Disposition of Common Shares” below). However, the Company does not intend to maintain the calculations of earnings and profits in accordance with U.S. federal income tax principles, and each U.S. Holder should therefore assume that any distribution by the Company with respect to the common shares will constitute ordinary dividend income. Dividends received on common shares generally will not be eligible for the “dividends received deduction.”

Dividends paid by the Company generally will be taxed at the preferential tax rates applicable to long-term capital gains if (a) the Company is a “qualified foreign corporation” (as defined below), (b) the U.S. Holder receiving such dividend is an individual, estate, or trust, and (c) certain holding period requirements are met. The Company generally will be a “qualified foreign corporation” under Section 1(h)(11) of the Code (a “QFC”) if (a) the Company is eligible for the benefits of the Treaty, or (b) common shares of the Company are readily tradable on an established securities market in the U.S. However, even if the Company satisfies one or more of such requirements, the Company will not be treated as a QFC if the Company is a PFIC for the taxable year during which the Company pays a dividend or for the preceding taxable year. (See the section below under the heading "Passive Foreign Investment Company Rules").

If the Company is a QFC, but a U.S. Holder otherwise fails to qualify for the preferential tax rate applicable to dividends discussed above, a dividend paid by the Company to a U.S. Holder, including a U.S. Holder that is an individual, estate, or trust, generally will be taxed at ordinary income tax rates (and not at the preferential tax rates applicable to long-term capital gains). The dividend rules are complex, and each U.S. Holder should consult its own tax advisor regarding the dividend rules.

Sale or Other Taxable Disposition of Common Shares

A U.S. Holder will recognize gain or loss on the sale or other taxable disposition of common shares in an amount equal to the difference, if any, between (a) the amount of cash plus the fair market value of any property received and (b) such U.S. Holder’s tax basis in such common shares sold or otherwise disposed of. Subject to the PFIC rules discussed below, any such gain or loss generally will be capital gain or loss, which will be long-term capital gain or loss if, at the time of the sale or other disposition, such common shares are held for more than one year.

Gain or loss recognized by a U.S. Holder on the sale or other taxable disposition of common shares generally will be treated as “U.S. source” for purposes of applying the U.S. foreign tax credit rules unless the gain is subject to tax in Canada and is sourced as “foreign source” under the Treaty and such U.S. Holder elects to treat such gain or loss as “foreign source.”

Preferential tax rates apply to long-term capital gains of a U.S. Holder that is an individual, estate, or trust. There are currently no preferential tax rates for long-term capital gains of a U.S. Holder that is a corporation. Deductions for capital losses are subject to significant limitations under the Code.

Receipt of Foreign Currency

The amount of any distribution paid in foreign currency to a U.S. Holder in connection with the ownership of common shares, or on the sale, exchange or other taxable disposition of common shares, generally will be equal to the U.S. dollar value of such foreign currency based on the exchange rate applicable on the date of receipt (regardless of whether such foreign currency is converted into U.S. dollars at that time). A U.S. Holder that receives foreign currency and converts such foreign currency into U.S. dollars at a conversion rate other than the rate in effect on the date of receipt may have a foreign currency exchange gain or loss, which generally would be treated as U.S. source ordinary income or loss. If the foreign currency received is not converted into U.S. dollars on the date of receipt, a U.S. Holder will have a basis in the foreign currency equal to its U.S. dollar value on the date of receipt. Any U.S. Holder who receives payment in foreign currency and engages in a subsequent conversion or other disposition of the foreign currency may have a foreign currency exchange gain or loss that would be treated as ordinary income or loss, and generally will be U.S. source income or loss for foreign tax credit purposes. Each U.S. Holder should consult its own U.S. tax advisor regarding the U.S. federal income tax consequences of receiving, owning, and disposing of foreign currency.

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Foreign Tax Credit

A U.S. Holder who pays (whether directly or through withholding) Canadian income tax with respect to dividends paid on common shares generally will be entitled, at the election of such U.S. Holder, to receive either a deduction or a credit for such Canadian income tax paid. Generally, a credit will reduce a U.S. Holder’s U.S. federal income tax liability on a dollar-for-dollar basis, whereas a deduction will reduce a U.S. Holder’s income subject to U.S. federal income tax. This election is made on a year-by-year basis and applies to all foreign taxes paid (whether directly or through withholding) by a U.S. Holder during a year.

Complex limitations apply to the foreign tax credit, including the general limitation that the credit cannot exceed the proportionate share of a U.S. Holder’s U.S. federal income tax liability that such U.S. Holder’s “foreign source” taxable income bears to such U.S. Holder’s worldwide taxable income. In applying this limitation, a U.S. Holder’s various items of income and deduction must be classified, under complex rules, as either “foreign source” or “U.S. source.” Generally, dividends paid by a foreign corporation should be treated as foreign source for this purpose, and gains recognized on the sale of stock of a foreign corporation by a U.S. Holder should be treated as U.S. source for this purpose, except as otherwise provided in an applicable income tax treaty, and if an election is properly made under the Code. However, the amount of a distribution with respect to the common shares that is treated as a “dividend” may be lower for U.S. federal income tax purposes than it is for Canadian federal income tax purposes, resulting in a reduced foreign tax credit allowance to a U.S. Holder. In addition, this limitation is calculated separately with respect to specific categories of income. Dividends paid by the Company generally will constitute “foreign source” income and generally will be categorized as “passive income.”

The foreign tax credit rules are complex, and each U.S. Holder should consult its own tax advisor regarding the foreign tax credit rules.

Additional Tax on Passive Income

For tax years beginning after December 31, 2012, certain individuals, estates and trusts whose income exceeds certain thresholds will be required to pay a 3.8% Medicare surtax on “net investment income” including, among other things, dividends and net gain from disposition of property (other than property held in a trade or business). U.S. Holders should consult with their own tax advisors regarding the effect, if any, of this tax on their ownership and disposition of common shares.

Information Reporting; Backup Withholding Tax For Certain Payments

Under U.S. federal income tax law and regulations, certain categories of U.S. Holders must file information returns with respect to their investment in, or involvement in, a foreign corporation. For example, recently enacted legislation generally imposes new U.S. return disclosure obligations (and related penalties) on U.S. Holders that hold certain specified foreign financial assets in excess of $50,000. The definition of specified foreign financial assets includes not only financial accounts maintained in foreign financial institutions, but also, unless held in accounts maintained by a financial institution, any stock or security issued by a non-U.S. person, any financial instrument or contract held for investment that has an issuer or counterparty other than a U.S. person and any interest in a foreign entity. U.S. Holders may be subject to these reporting requirements unless their common shares are held in an account at a domestic financial institution. Penalties for failure to file certain of these information returns are substantial. U.S. Holders of common shares should consult with their own tax advisors regarding the requirements of filing information returns, these rules, including the requirement to file an IRS Form 8938.

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Payments made within the U.S., or by a U.S. payor or U.S. middleman, of dividends on, and proceeds arising from the sale or other taxable disposition of, common shares generally will be subject to information reporting and backup withholding tax, at the rate of 28% (and increasing to 31% for payments made after December 31, 2012), if a U.S. Holder (a) fails to furnish such U.S. Holder’s correct U.S. taxpayer identification number (generally on Form W-9), (b) furnishes an incorrect U.S. taxpayer identification number, (c) is notified by the IRS that such U.S. Holder has previously failed to properly report items subject to backup withholding tax, or (d) fails to certify, under penalty of perjury, that such U.S. Holder has furnished its correct U.S. taxpayer identification number and that the IRS has not notified such U.S. Holder that it is subject to backup withholding tax. However, certain exempt persons, such as corporations, generally are excluded from these information reporting and backup withholding tax rules. Any amounts withheld under the U.S. backup withholding tax rules will be allowed as a credit against a U.S. Holder’s U.S. federal income tax liability, if any, or will be refunded, if such U.S. Holder furnishes required information to the IRS in a timely manner. Each U.S. Holder should consult its own tax advisor regarding the information reporting and backup withholding rules.

Passive Foreign Investment Company Rules

If the Company were to constitute a PFIC (as defined below) for any year during a U.S. Holder’s holding period, then certain different and potentially adverse tax consequences would apply to such U.S. Holder’s acquisition, ownership and disposition of common shares.

The Company generally will be a PFIC under Section 1297 of the Code if, for a tax year, (a) 75% or more of the gross income of the Company for such tax year is passive income (the “income test”) or (b) 50% or more of the value of its average quarterly assets held by the Company either produce passive income or are held for the production of passive income, based on the fair market value of such assets (the “asset test”). “Gross income” generally includes all revenues less the cost of goods sold, plus income from investments and from incidental or outside operations or sources, and “passive income” includes, for example, dividends, interest, certain rents and royalties, certain gains from the sale of stock and securities, and certain gains from commodities transactions. Active business gains arising from the sale of commodities generally are excluded from passive income if substantially all (85% or more) of a foreign corporation’s commodities are (a) stock in trade of such foreign corporation or other property of a kind which would properly be included in inventory of such foreign corporation, or property held by such foreign corporation primarily for sale to customers in the ordinary course of business, (b) property used in the trade or business of such foreign corporation that would be subject to the allowance for depreciation under Section 167 of the Code, or (c) supplies of a type regularly used or consumed by such foreign corporation in the ordinary course of its trade or business, and certain other requirements are satisfied.

In addition, for purposes of the PFIC income test and asset test described above, if the Company owns, directly or indirectly, 25% or more of the total value of the outstanding shares of another foreign corporation, the Company will be treated as if it (a) held a proportionate share of the assets of such other foreign corporation and (b) received directly a proportionate share of the income of such other foreign corporation. In addition, for purposes of the PFIC income test and asset test described above, “passive income” does not include any interest, dividends, rents, or royalties that are received or accrued by the Company from a “related person” (as defined in Section 954(d)(3) of the Code), to the extent such items are properly allocable to the income of such related person that is not passive income.

Under certain attribution rules, if the Company is a PFIC, U.S. Holders will be deemed to own their proportionate share of any subsidiary of the Company which is also a PFIC (a ‘‘Subsidiary PFIC’’), and will be subject to U.S. federal income tax on (i) a distribution on the shares of a Subsidiary PFIC or (ii) a disposition of shares of a Subsidiary PFIC, both as if the holder directly held the shares of such Subsidiary PFIC.

The Company does not believe that it was a PFIC during the tax year ending December 31, 2012. However, PFIC classification is fundamentally factual in nature, generally cannot be determined until the close of the tax year in question, and is determined annually. Additionally, the analysis depends, in part, on the application of complex U.S. federal income tax rules, which are subject to differing interpretations. Furthermore, if for any given year the Company reaches either of the test standards (i.e., “income test” and “asset test”), it remains a PFIC forever, no matter how active it becomes in the future. Consequently, there can be no assurance that the Company has never been and will not become a PFIC for any tax year during which U.S. Holders hold common shares.

If the Company were a PFIC in any tax year and a U.S. Holder held common shares, such holder generally would be subject to special rules with respect to “excess distributions” made by the Company on the common shares and with respect to gain from the disposition of common shares. An “excess distribution” generally is defined as the excess of distributions with respect to the common shares received by a U.S Holder in any tax year over 125% of the average annual distributions such U.S. Holder has received from the Company during the shorter of the three preceding tax years, or such U.S. Holder’s holding period for the common shares. Generally, a U.S. Holder would be required to allocate any excess distribution or gain from the disposition of the common shares ratably over its holding period for the common shares. Such amounts allocated to the year of the disposition or excess distribution would be taxed as ordinary income, and amounts allocated to prior tax years would be taxed as ordinary income at the highest tax rate in effect for each such year and an interest charge at a rate applicable to underpayments of tax would apply.

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While there are U.S. federal income tax elections that sometimes can be made to mitigate these adverse tax consequences (including, without limitation, the “QEF Election” and the “Mark-to-Market Election”), such elections are available in limited circumstances and must be made in a timely manner. U.S. Holders should be aware that, for each tax year, if any, that the Company is a PFIC, the Company can provide no assurances that it will satisfy the record keeping requirements of a PFIC, or that it will make available to U.S. Holders the information such U.S. Holders require to make a QEF Election under Section 1295 of the Code with respect of the Company or any Subsidiary PFIC. U.S. Holders are urged to consult their own tax advisers regarding the potential application of the PFIC rules to the ownership and disposition of common shares, and the availability of certain U.S. tax elections under the PFIC rules.

F. Dividends and Paying Agents

Not Applicable.

G. Statements by Experts

Not Applicable.

H. Documents on Display

We are subject to the informational requirements of the Exchange Act and file reports and other information with the SEC. You may read and copy any of our reports and other information at, and obtain copies upon payment of prescribed fees from, the Public Reference Room maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. In addition, the SEC maintains a Website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC at http://www.sec.gov. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.

We are required to file reports and other information with the securities commissions in Canada. You are invited to read and copy any reports, statements or other information, other than confidential filings, that we file with the provincial securities commissions. These filings are also electronically available from the Canadian System for Electronic Document Analysis and Retrieval (“SEDAR”) (http://www.sedar.com), the Canadian equivalent of the SEC’s electronic document gathering and retrieval system.

We “incorporate by reference” information that we file with the SEC, which means that we can disclose important information to you by referring you to those documents. The information incorporated by reference is an important part of this Form 20-F and more recent information automatically updates and supersedes more dated information contained or incorporated by reference in this Form 20-F.

As a foreign private issuer, we are exempt from the rules under the Exchange Act prescribing the furnishing and content of proxy statements to shareholders.

We will provide without charge to each person, including any beneficial owner, to whom a copy of this annual report has been delivered, on the written or oral request of such person, a copy of any or all documents referred to above which have been or may be incorporated by reference in this annual report (not including exhibits to such incorporated information that are not specifically incorporated by reference into such information). Requests for such copies should be directed to us at the following address: 520 – 999 Canada Place, Vancouver, British Columbia, Canada V6C 3E1, Telephone: (604) 638-5050, Facsimile: (604) 638-5051.

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I. Subsidiary Information

Not applicable.

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ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is engaged primarily in oil and gas exploration and production and manages related industry risk issues directly. The Company may be at risk for environmental issues and fluctuations in commodity pricing. Management is not aware of and does not anticipate any significant environmental remediation costs or liabilities in respect of its current operations.

The Company’s functional currency is the Canadian dollar. The Company operates in foreign jurisdictions, giving rise to significant exposure to market risks from changes in foreign currency rates. The financial risk is the risk to the Company’s operations that arises from fluctuations in foreign exchange rates and the degree of volatility of these rates. Currently, the Company does not use derivative instruments to reduce its exposure to foreign currency risk.

The Company also has exposure to a number of risks from its use of financial instruments including: credit risk, liquidity risk, and market risk. This note presents information about the Company’s exposure to each of these risks and the Company’s objectives, policies and processes for measuring and managing risk, and the Company’s management of capital.

The Board of Directors has overall responsibility for the establishment and oversight of the Company’s risk management framework. The Board has implemented and monitors compliance with risk management policies. The Company’s risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company’s activities.

(a) Credit Risk

Credit risk arises from credit exposure to receivables due from joint operating partners and marketers included in accounts receivable. The maximum exposure to credit risk is equal to the carrying value of the financial assets.

The Company is exposed to third party credit risk through its contractual arrangements with its current or future joint operating partners, marketers of its petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to the Company, such failures may have a material adverse effect on the Company’s business, financial condition, and results of operations.

The objective of managing the third party credit risk is to minimize losses in financial assets. The Company assesses the credit quality of the partners, taking into account their financial position, past experience, and other factors. The Company mitigates the risk of non-collection of certain amounts by obtaining the joint operating partners’ share of capital expenditures in advance of a project and by monitoring accounts receivable on a regular basis. As at December 31, 2017 and 2016, no accounts receivable has been deemed uncollectible or written off during the year.

The Company considers all amounts outstanding for more than 90 days as past due. Currently, there is no indication that amounts are non-collectable; thus an allowance for doubtful accounts has not been set up. As at December 31, 2017, $Nil of accounts receivable are past due.

(b) Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they are due. The nature of the oil and gas industry is capital intensive and the Company maintains and monitors a certain level of cash flow to finance operating and capital expenditures.

The Company’s ongoing liquidity and cash flow are impacted by various events and conditions. These events and conditions include but are not limited to commodity price fluctuations, general credit and market conditions, operation and regulatory factors, such as government permits, the availability of drilling and other equipment, lands and pipeline access, weather, and reservoir quality.

To mitigate the liquidity risk, the Company closely monitors its credit facility, production level and capital expenditures to ensure that it has adequate liquidity to satisfy its financial obligations.

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(c) Market Risk

Market risk is the risk that changes in market prices, such as foreign exchange rates, commodity prices, and interest rates will affect the Company’s net earnings. The objective of market risk management is to manage and control market risk exposures within acceptable limits, while maximizing returns. The Company utilizes financial derivatives to manage certain market risks. All such transactions are conducted in accordance with the risk management policy that has been approved by the Board of Directors.

(i) Foreign Currency Exchange Risk

Foreign currency exchange rate risk is the risk that the fair value of financial instruments or future cash flows will fluctuate as a result of changes in foreign exchange rates. Although substantially all of the Company’s oil and natural gas sales are denominated in Canadian dollars, the underlying market prices in Canada for oil and natural gas are impacted by changes in the exchange rate between the Canadian and United States dollars. Given that changes in exchange rate have an indirect influence, the impact of changing exchange rates cannot be accurately quantified. The Company had no forward exchange rate contracts in place as at or during the year ended December 31, 2017 and 2016.

The Company was exposed to the following foreign currency risk at December 31:

(CA$ thousands)	2017		2016
Expressed in foreign currencies	CND$		CND$
Cash and cash equivalents	30		1
Accounts receivable	228		282
Accounts payable and accrued liabilities	(213	)	(312	)
Balance sheet exposure	45		(29	)

The following foreign exchange rates applied for the year ended and as at December 31:

	2017	2016
December 31, reporting date rate	1.2545	1.3427
YTD average USD to CAD	1.2986	1.3253

The Company has performed a sensitivity analysis on its foreign currency denominated financial instruments. Based on the Company’s foreign currency exposure noted above and assuming that all other variables remain constant, a 10% appreciation of the US dollar against the Canadian dollar would result in the decrease of net loss of $5,000 at December 31, 2017 (2016 – increase of net loss of $3,000). For a 10% depreciation of the above foreign currencies against the Canadian dollar, assuming all other variables remain constant, there would be an equal and opposite impact on net loss.

(ii) Interest Rate Risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. At December 31, 2017, the Company was exposed to interest rate fluctuations on the bank credit facility and the loans from related parties which bore a floating rate of interest. Assuming all other variables remain constant, an increase or decrease of 1% in market interest rate at December 31, 2017 would have increased or decreased net loss by $65,000. The Company had no interest rate swap contracts in place at or during the year ended December 31, 2017 and 2016.

(iii) Commodity Price Risk

Revenues and consequently cash flows fluctuate with commodity prices and the US/Canadian dollar exchange rate. Commodity prices are determined on a global basis and circumstances that occur in various parts of the world are outside of the control of the Company. The Company may protect itself from fluctuations in prices by using the financial derivative sales contracts. The Company may enter into commodity price contracts to manage the risks associated with price volatility and thereby protect its cash flows used to fund its capital program. Assuming all other variables remain constant, an increase or decrease of oil price of $1 per bbl and gas price of $0.01 per mcf at December 31, 2017 would have decreased or increased net loss by $34,000. The Company had no commodity contracts in place at December 31, 2017.

71

(d) Capital Management Strategy

The Company’s policy on capital management is to maintain a prudent capital structure so as to maintain financial flexibility, preserve access to capital markets, maintain investor, creditor and market confidence, and to allow the Company to fund future developments. The Company considers its capital structure to include share capital, cash and cash equivalents, bank line of credit, and working capital. In order to maintain or adjust capital structure, the Company may from time to time issue shares or enter into debt agreements and adjust its capital spending to manage current and projected operating cash flows and debt levels.

The Company’s share capital is not subject to any external restrictions. The Company has not paid or declared any dividends, nor are any contemplated in the foreseeable future. There have been no changes to the Company’s capital management strategy during the year ended December 31, 2017.

ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

A.-C.

Not applicable.

D. American Depositary Receipts

The Company does not have securities registered as American Depositary Receipts.

72

PART II

ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

None.

ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

A. – D.

None.

E. Use of Proceeds

Not Applicable.

ITEM 15. CONTROLS AND PROCEDURES

A. Disclosure Controls and Procedures

As of the end of the fiscal year ended December 31, 2017, an evaluation of the effectiveness of the Company’s “disclosure controls and procedures” (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), was performed by the Company’s management, under the supervision and with the participation of the Company’s Chief Executive Officer and Chief Financial Officer. Based on that evaluation, the Company’s CEO and CFO have concluded that the Company’s disclosure controls and procedures were effective to give reasonable assurance that the information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Our management concluded that our disclosure controls and procedures were effective. The applicable information was filed on a timely basis with the Canadian securities regulators on SEDAR and was publicly accessible on www.SEDAR.com and on the Company’s website, but was not timely furnished on Edgar on Form 6-K. We have taken steps designed to ensure that future information required to be furnished on Form 6-K will be so furnished on a timely basis.

B. Management’s Report on Internal Control over Financial Reporting

The Company’s management, including the Company’s Chief Executive Officer and the Company’s Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over the Company’s internal control over financial reporting, as such term is defined in Rule 13a-15(f) under the Exchange Act. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation and fair presentation of financial statements for external purposes in accordance with International Financial Reporting Standards. It should be noted that a control system, no matter how well conceived or operated, can only provide reasonable assurance, not absolute assurance, that the objectives of the control system are met. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies and procedures may deteriorate.

The Company’s management, (with the participation of the Company’s Chief Executive Officer and the Company’s Chief Financial Officer), conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2017. This evaluation was based on the criteria set forth in Internal Control-Integrated Framework (2013) (“COSO Framework”) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, management has concluded that, as of December 31, 2017, the Company’s internal control over financial reporting was effective and management’s assessment did not identify material weaknesses.

73

C. Attestation Report of the Registered Public Accounting Firm

Because the Company is not an “accelerated filer” or “large accelerated filer” within the meaning of such terms under the Exchange Act, this Annual Report is not required to include an attestation report of the Company’s independent auditors regarding the Company’s internal control over financial reporting.

D. Changes in Internal Control Over Financial Reporting

There were no amendments to the Company’s system of internal control over financial reporting during the year ended December 31, 2017 and the Company is not aware of any amendments to its system of internal control that should be implemented to strengthen its system of internal control over financial reporting.

ITEM 16. [RESERVED]

ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT

The Company does not have a financial expert, as defined by the US Securities and Exchange Commission, serving on the Company’s “Audit Committee”. In 2011, the Company adopted “International Financial Reporting Standards” (“IFRS”) to comply with Canadian public company reporting standards. The Audit Committee members do not, as yet, have sufficient experience and in-depth understanding of IFRS to qualify as experts.

ITEM 16B. CODE OF ETHICS

The Board of Directors of the Company has adopted a Code of Conduct and Ethics that outlines the Company’s values and its commitment to ethical business practices in every business transaction. This code applies to all directors, officers, and employees of the Company and its subsidiaries and affiliates. A copy of the Company’s Code of Business Conduct and Ethics is available on the Company’s website at www.dxienergy.com.

Reporting Unethical and Illegal Conduct/Ethics Questions

The Company is committed to taking prompt action against violations of the Code of Conduct and Ethics and it is the responsibility of all directors, officers and employees to comply with the Code and to report violations or suspected violations to the Company’s Compliance Officer. Employees may also discuss their concerns with their supervisor who will then report suspected violations to the Compliance Officer.

The Compliance Officer is appointed by the Board of Directors and is responsible for investigating and resolving all reported complaints and allegations and shall advise the President and CEO, the CFO and/or the Audit Committee.

During the fiscal year ended December 31, 2017, the Company did not substantially amend, waive, or implicitly waive any provision of the Code with respect to any of the directors, executive officers or employees subject to it.

ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table sets out the fees billed to the Company by BDO Canada LLP for professional services rendered during fiscal years ended December 31, 2017 and December 31, 2016. During these years, BDO Canada LLP was our external auditors.

	Year ended December 31, 2017	Year ended December 31, 2016
	$	$
Audit Services (1)	142,500	157,000
Audit Related Services (2)	17,653	16,000
Tax Services (3)	6,866	10,600
All Other Fees (4)	13,224	15,522

74

NOTES:

(1)	Audit fees consist of fees for the audit of the Company’s annual financial statements and review of the Company’s quarterly financial statements, or services that are normally provided in connection with statutory and regulatory filings or engagements.
(2)	Audit-related fees consist of fees for assurance and related services that are reasonably related to the performance of the audit or review of the Company’s financial statements and are not reported as Audit fees. During fiscal 2017 and 2016, the services provided in this category included consultation on accounting and audit-related matters and review of reserves disclosure.
(3)	Tax fees consist of fees for tax compliance services, tax advice and tax planning. During fiscal 2017 and 2016, the services provided in this category included assistance and advice in relation to the preparation of corporate income tax returns.
(4)	During fiscal 2017 and 2016, the aggregate fees in this category consist of Canadian Public Accountability Board (“CPAB”) fees and administration costs.

Pre-Approval Policies and Procedures

Generally, in the past, prior to engaging the Company’s auditors to perform a particular service, the Company’s audit committee has, when possible, obtained an estimate for the services to be performed. The audit committee in accordance with procedures for the Company approved all of the services described above.

In relation to the pre-approval of all audit and audit-related services and fees the Company’s audit committee charter provides that the audit committee shall:

Review and pre-approve all audit and audit-related services and the fees and other compensation related thereto, and any non-audit services, provided by the Company’s external auditors. The pre-approval requirement is waived with respect to the provision of non-audit services if:

i.	the aggregate amount of all such non-audit services provided to the Company constitutes not more than five percent of the total amount of revenues paid by the Company to its external auditors during the fiscal year in which the non-audit services are provided;
ii.	such services were not recognized by the Company at the time of the engagement to be non-audit services; and
iii.	such services are promptly brought to the attention of the Committee by the Company and approved prior to the completion of the audit by the Committee or by one or more members of the Committee who are members of the Board to whom authority to grant such approvals has been delegated by the Committee.

Provided the pre-approval of the non-audit services is presented to the Committee’s first scheduled meeting following such approval such authority may be delegated by the Committee to one or more independent members of the Committee.

We did not rely on the de minimus exemption provided by Section (c)(7)(i)(C) of Rule 2-01 of SEC Regulation S-X in 2017.

ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES

None.

ITEM 16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PERSONS

The Company did not repurchase any common shares in the fiscal year ended December 31, 2017.

ITEM 16F. CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT

Not applicable.

ITEM 16G. CORPORATE GOVERNANCE

Not applicable

ITEM 16H – MINE SAFETY DISCLOSURE

Not Applicable.

75

PART III

ITEM 17. FINANCIAL STATEMENTS

The Company has provided financial statements pursuant to Item 18.

ITEM 18. FINANCIAL STATEMENTS

Report of Independent Registered Chartered Professional Accountants, dated April 17, 2018

Consolidated Balance Sheets at December 31, 2017 and 2016

Consolidated Statements of Comprehensive Loss for the years ending December 31, 2017, 2016 and 2015.

Consolidated Statements of Changes in Shareholder’s Equity for the years ended December 31, 2017, 2016 and 2015.

Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015.

Notes to the Consolidated Financial Statements

Supplementary Oil and Gas Reserve Estimation and Disclosures (Unaudited) for the years ending December 31, 2017 and 2016

76

ITEM 19. EXHIBITS

Financial Statements

Description	Page
Consolidated Financial Statements for the Years Ended December 31, 2017, 2016 and 2015.	F-1 - F-36

Supplementary Oil and Gas Reserve Estimation and Disclosures (Unaudited) for the years ending December 31, 2017 and 2016

EXHIBIT
NUMBER	DESCRIPTION
1.1(1)	Articles
1.2(1)	Notice of Articles
1.3(1)	Certificate of Continuation
1.4(1)	Notice of Alteration
1.5(2)	Certificate of Name Change
1.6(1)	Amendment to Articles to Include Special Rights
4.1(1)	Option Plan
4.2(1)	Option Plan (Sub-Plan)
4.3(3)	Financial Contract with Bakken Drilling Fund III, LP dated December 31, 2012
4.4(4)	Amendment to Financial Contract with Bakken Drilling Fund III, LP dated September 10, 2013
4.5(5)	Amendment to Financial Contract with Bakken Drilling Fund III, LP dated June 16, 2014
4.6(6)	Loan Agreement with HEC dated March 12, 2015
4.7(7)	Amendment No.1 to the Loan Agreement with HEC dated May 6, 2015
4.8(8)	Amendment No.2 to the Loan Agreement with HEC dated June 22, 2015
4.9(8)	Loan Agreement with HVI dated June 22, 2015
4.10(9)	Amendment No.3 to the Loan Agreement with HEC dated September 28, 2015
4.11(9)	Amendment No.1 to the Loan Agreement with HVI dated September 28, 2015
4.12(10)	Amendment No.4 to the Loan Agreement with HEC dated November 18, 2015
4.13(11)	Amendment No.2 to the Loan Agreement with HVI dated November 18, 2015
4.14(12)	Amendment No.5 to the Loan Agreement with HEC dated June 5, 2017
4.15(12)	Amendment No.3 to the Loan Agreement with HVI dated June 5, 2017
4.16(13)	Funding and Participation Agreement with Acceleration Resources LLC dated December 22, 2017
8.1*	List of Subsidiaries
12.1*	Certification of CEO Pursuant to Rule 13a-14(a)
12.2*	Certification of CFO Pursuant to Rule 13a-14(a)
13.1*	Certification of CEO Pursuant to 18 U.S.C. Section 1350
13.2*	Certification of CFO Pursuant to 18 U.S.C. Section 1350
15.1*	Consent of BDO Canada LLP
15.2*	Consent Letter from GLJ Petroleum Consultants

77

EXHIBIT
NUMBER	DESCRIPTION
15.3*	Consent Letter from Gustavson Associates
99.1*	Third Party Report on Reserves Prepared by GLJ Petroleum Consultants, Effective December 31, 2017
99.2*	Reserve Estimate and Financial Forecast as to DXI Energy’s Interests in the Kokopelli Field Area, Garfield County, Colorado, Prepared by Gustavson Associates, Effective January 1, 2018

(1)	Incorporated by reference to the Registrant’s registration statement on Form S-8, filed on February 16, 2012.
(2)	Incorporated by reference to the Registrant’s registration statement on Form 6-K, filed on October 28, 2015.
(3)	Incorporated by reference to the Registrant’s registration statement on Form 20-F for the 2012 fiscal year, filed on April 29, 2013.
(4)	Incorporated by reference to the Registrant’s registration statement on Form 20-F for the 2013 fiscal year, filed on April 29, 2014.
(5)	Incorporated by reference to the Registrant’s registration statement on Form 6-K, filed on September 12, 2014.
(6)	Incorporated by reference to the Registrant’s registration statement on Form 6-K, filed on March 19, 2015.
(7)	Incorporated by reference to the Registrant’s registration statement on Form 6-K, filed on May 26, 2015.
(8)	Incorporated by reference to the Registrant’s registration statement on Form 6-K, filed on July 29, 2015.
(9)	Incorporated by reference to the Registrant’s registration statement on Form 6-K, filed on October 23, 2015.
(10)	Incorporated by reference to the Registrant’s registration statement on Schedule 13D filed on January 6, 2016.
(11)	Incorporated by reference to the Registrant’s registration statement on Form 6-K filed on April 18, 2016.
(12)	Incorporated by reference to the Registrant’s registration statement on Form 6-K filed on September 8, 2017.
(13)	Incorporated by reference to the Registrant’s registration statement on Form 6-K filed on February 1, 2018.
*	Filed herewith

78

SIGNATURES

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.

		DXI Energy Inc.
Dated:	April 16, 2018	/s/ Robert L. Hodgkinson
		Robert L. Hodgkinson
		Chairman & CEO

79

CONSOLIDATED FINANCIAL STATEMENTS (AUDITED)

December 31, 2017

F-1

F-2

F-3

DXI ENERGY INC.

CONSOLIDATED BALANCE SHEETS

(Expressed in Canadian Dollars)

		December 31,		December 31,
(thousands of Canadian dollars)	Notes	2017		2016
		$		$
ASSETS
Current
Cash and cash equivalents		1,010		141
Accounts receivable		388		672
Prepaids and deposits		29		19
Current Assets		1,427		832
Non-current
Deposits		212		246
Exploration and evaluation assets	5	8		970
Property and equipment	6	17,162		19,212
Total Assets		18,809		21,260
LIABILITIES
Current
Accounts payable and accrued liabilities		1,291		2,165
Loans from related parties	8	1,458		2,363
Flow-through shares liability	9	93		-
Derivative liability		-		153
Financial contract liability	11	6,752		7,226
Current Liabilities		9,594		11,907
Non-current
Loans from related parties	8	3,150		4,031
Decommissioning liability	10	3,971		3,776
Total Liabilities		16,715		19,714
SHAREHOLDERS' EQUITY
Share capital	12	101,715		98,111
Contributed surplus		13,752		10,626
Deficit		(115,845	)	(110,636	)
Accumulated other comprehensive income		2,472		3,445
Total Shareholders' Equity		2,094		1,546
Total Liabilities and Shareholders' Equity		18,809		21,260

Approved on behalf of the Board:

"signed"	"signed"
Robert Hodgkinson - Director	Stan Page - Director

The accompanying notes are an integral part of these consolidated financial statements. F-4

DXI ENERGY INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(Expressed in Canadian dollars)

		Year ended December 31
(thousands of Canadian dollars, except per share amounts)	Notes	2017		2016		2015
		$		$		$
REVENUES
Gross revenues		2,816		4,808		8,579
Royalties		(336	)	(735	)	(1,483	)
Total Revenues, net of royalties	18	2,480		4,073		7,096
EXPENSES
Operating and transportation		2,085		2,971		3,843
Amortization, depletion and impairment losses	7	2,628		4,493		4,189
General and administrative		1,671		1,571		2,246
Financing expenses		1,039		1,579		1,117
Stock based compensation		8		188		771
Foreign exchange (gain) loss		(486	)	(212	)	288
Loss on disposal of E&E assets		-		175		-
Loss on disposal of property and equipment		2		-		6
Change in fair value of warrant liability		-		-		(754	)
Change in fair value of derivative liability		(153	)	(1,073	)	(2,245	)
Loss on debt extinguishment	8	918		-		1,398
(Gain) loss on financial contract liability	11	-		(63	)	3,348
Total Expenses		7,712		9,629		14,207
Loss before income taxes and other items		(5,232	)	(5,556	)	(7,111	)
Other income		23		70		3
Loss for the year		(5,209	)	(5,486	)	(7,108	)
Other Comprehensive Income (Loss)
Items that may be subsequently reclassified to profit or loss:
Foreign currency translation adjustment		(973	)	(673	)	2,497
Comprehensive loss		(6,182	)	(6,159	)	(4,611	)
Loss per common share - basic and diluted	14	(0.08	)	(0.13	)	(0.19	)

The accompanying notes are an integral part of these consolidated financial statements. F-5

DXI ENERGY INC.

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Expressed in Canadian Dollars)

		Number		Share		Contributed
(thousands of Canadian dollars, except number of shares)	Notes	of Shares		Capital		Surplus		Deficit		AOCI(L)*		Total
				$		$		$		$		$
Balance as at January 1, 2017		44,808,286		98,111		10,626		(110,636	)	3,445		1,546
Shares issued via private placements, net of issuance costs	12	58,797,802		3,718		-		-		-		3,718
Flow-through share liability	9	-		(114	)	-		-		-		(114	)
Contributed surplus related to value of conversion feature on loans from related parties	8	-		-		3,118		-		-		3,118
Stock-based compensation		-		-		8		-		-		8
Loss		-		-		-		(5,209	)	-		(5,209	)
Foreign currency translation adjustment		-		-		-		-		(973	)	(973	)
Balance as at December 31, 2017		103,606,088		101,715		13,752		(115,845	)	2,472		2,094
Balance as at January 1, 2016		36,509,953		97,162		10,438		(105,150	)	4,118		6,568
Shares issued via private placements, net of issuance costs		8,298,333		949		-		-		-		949
Stock-based compensation		-		-		188		-		-		188
Loss		-		-		-		(5,486	)	-		(5,486	)
Foreign currency translation adjustment		-		-		-		-		(673	)	(673	)
Balance as at December 31, 2016		44,808,286		98,111		10,626		(110,636	)	3,445		1,546
Balance as at January 1, 2015		36,480,427		97,132		9,674		(98,042	)	1,621		10,385
Issue of shares on exercise of options		29,898		23		-		-		-		23
Contributed surplus reallocated on exercise of options		-		7		(7	)	-		-		-
Stock-based compensation		-		-		771		-		-		771
Loss		-		-		-		(7,108	)	-		(7,108	)
Foreign currency translation adjustment		-		-		-		-		2,497		2,497
Adjustment due to fractional rounding		(372	)	-		-		-		-		-
Balance as at December 31, 2015		36,509,953		97,162		10,438		(105,150	)	4,118		6,568

* Accumulated other comprehensive income (loss)

The accompanying notes are an integral part of these consolidated financial statements. F-6

DXI ENERGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Expressed in Canadian Dollars)

		Year ended December 31
(thousands of Canadian dollars)	Notes	2017		2016		2015
		$		$		$
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES
Loss for the year		(5,209	)	(5,486	)	(7,108	)
Adjustment for items not affecting cash:
Amortization, depletion and impairment losses		2,628		4,493		4,189
Stock based compensation		8		188		771
Non-cash financing expenses		530		961		661
Non-cash foreign exchange on financial contract liability	11	(474	)	(212	)	594
Miscellaneous non-cash items		(25	)	-		6
Loss on disposal of E&E assets		-		175		-
Change in fair value of warrant liability		-		-		(754	)
Change in fair value of derivative liability		(153	)	(1,073	)	(2,245	)
Loss on debt extinguishment	8	918		-		1,398
(Gain) loss on financial contract liability		-		(63	)	3,348
Cash flows from (used in) operations		(1,777	)	(1,017	)	860
Changes in operating working capital	14	219		667		204
Total Cash Flows from (used in) Operating Activities		(1,558	)	(350	)	1,064
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES
Deposits		34		48		2
E&E expenditures		(7	)	(2	)	(106	)
Additions to property and equipment	6	(449	)	(528	)	(5,632	)
Proceeds from sale of E&E assets		-		84		-
Reclamation expenditures		(3	)	(53	)	-
Changes in investing working capital	14	32		178		(2,289	)
Total Cash Flows used in Investing Activities		(393	)	(273	)	(8,025	)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES
Repayment of bank credit facility		-		(147	)	(1,807	)
Advance of loans from related parties	8	450		350		7,500
Repayment of loans from related parties		-		(300	)	-
Shares issued on exercise of warrants and options		-		-		23
Shares issued for cash, net of share issue costs		2,332		884		-
Changes in financing working capital	14	38		(61	)	68
Total Cash Flows from Financing Activities		2,820		726		5,784
CHANGE IN CASH AND CASH EQUIVALENTS		869		103		(1,177	)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR		141		38		1,215
CASH AND CASH EQUIVALENTS, END OF YEAR		1,010		141		38

Supplemental cash flow information - Note 14

The accompanying notes are an integral part of these consolidated financial statements. F-7

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 1 – CORPORATE INFORMATION

DXI Energy Inc. (the “Company”) is a public company trading on the Toronto Stock Exchange (“TSX”) under the symbol “DXI” in Canada and the OTCQB (“OTCQB”) under the symbol “DXIEF” in the United States. The Company is in the business of exploring and developing energy properties with a focus on oil and gas in North America. The address of its registered office is 520 – 999 Canada Place, Vancouver, British Columbia.

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Dejour Energy (USA) Corp. (“Dejour USA”), incorporated in Nevada, Dejour Energy (Alberta) Ltd. (“DEAL”), incorporated in Alberta, and 0855524 B.C. Ltd., incorporated in British Columbia. All intercompany transactions are eliminated upon consolidation.

The consolidated financial statements are presented in Canadian dollars, which is also the functional currency of the parent company. These consolidated financial statements were authorized and approved for issuance by the Board of Directors on March 8, 2018.

NOTE 2 – BASIS OF PRESENTATION

(a) Basis of presentation

The consolidated financial statements (the “financial statements”) are presented under International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) and the International Financial Reporting Interpretations Committee (“IFRIC”). A summary of the Company’s significant accounting policies under IFRS is presented in note 3.

(b) Going concern

The financial statements were prepared on a going concern basis. The going concern basis assumes that the Company will continue in operation for the foreseeable future and will be able to realize its assets and discharge its liabilities and commitments in the normal course of business. The Company has a working capital deficiency of $8.2 million and an accumulated deficit of $115.8 million. Of this amount, $6.8 million is represented by a financial contract liability of Dejour USA, which was due on September 30, 2016. The current status of this instrument is described in note 11 below.

The Company’s ability to continue as a going concern is dependent upon attaining profitable operations and the continued financial support of the non-arm’s length lenders who have provided the Company with sufficient capital to meet capital expenditure commitments and continue exploration and development activities. There is no assurance that these activities will be successful. These material uncertainties cast substantial doubt upon the Company’s ability to continue as a going concern. These consolidated financial statements do not reflect the adjustments to the carrying values of assets and liabilities, the reported revenues and expenses, and the balance sheet classifications used that would be necessary if the going concern assumptions were not appropriate.

(c) Basis of measurement

The consolidated financial statements have been prepared on the historical cost basis except for certain financial liabilities are measured at fair value, as explained in the accounting policies in note 3.

(d) Use of estimates and judgments

The preparation of consolidated financial statements in compliance with IFRS requires management to make certain critical accounting estimates. It also requires management to exercise judgment in applying the Company’s accounting policies. The areas involving a higher degree of judgment or complexity, or areas where assumptions and estimates are significant to the financial statements are disclosed in note 4.

F-8

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 2 – BASIS OF PRESENTATION (continued)

(e) Functional and presentation currency

Subsidiaries measure items using the currency of the primary economic environment in which the entity operates with entities having a functional currency different from the parent company, translated into Canadian dollars.

NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The accounting policies set out below have been applied consistently to all periods presented in these consolidated financial statements and have been applied consistently by the Company’s entities.

(a) Basis of consolidation

The consolidated financial statements include the financial statements of the Company and subsidiaries controlled by the Company. Subsidiaries are fully consolidated from the date of acquisition, being the date on which the Company obtains control, and continue to be consolidated until the date that such control ceases. All intra-group balances, transactions, income and expenses are eliminated in full on consolidation.

The financial statements of the subsidiaries are prepared using the same reporting period as the parent company, using consistent accounting policies.

Exploration, development, and production activities may be conducted jointly with others and accordingly, the Company accounts for the assets, liabilities, revenues and expenses related to its interest in the joint operations from the date that joint control commences until the date that it ceases.

(b) Foreign currency

The financial statements of entities within the consolidated group that have a functional currency different from that of the Company (“foreign operations”) are translated into Canadian dollars as follows: assets and liabilities – at the closing rate as at the balance sheet date, and income and expenses – at the average rate of the period (as this is considered a reasonable approximation to actual rates). All resulting changes are recognized in other comprehensive loss as cumulative translation differences.

When the Company disposes of its entire interests in a foreign operation, or loses control, joint control, or significant influence over a foreign operation, the foreign currency gains or losses accumulated in other comprehensive loss related to the foreign operation are recognized in profit or loss. If an entity disposes of part of an interest in a foreign operation which remains a subsidiary, a proportionate amount of foreign currency gains or losses accumulated in other comprehensive income related to the subsidiary are reallocated between controlling and non-controlling interests.

Transactions in foreign currencies are translated into the functional currency at exchange rates at the date of the transactions. Foreign currency differences arising on translation are recognized in profit or loss. Foreign currency monetary assets and liabilities are translated at the functional currency exchange rate at the balance sheet date. Non- monetary items that are measured at historical cost in a foreign currency are translated using the exchange rates as at the dates of the initial transactions. Non-monetary items measured at fair value in a foreign currency are translated using the exchange rates at the date when the fair value was determined.

Exchange differences recognized in the profit or loss statement of the Company’s entities’ separate financial statements on the translation of monetary items forming part of the Company’s net investment in the foreign operation are reclassified to foreign exchange reserve on consolidation.

F-9

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

(c) Cash and cash equivalents

Cash and cash equivalents consist of cash and highly liquid investments having maturity dates of three months or less from the date of acquisition that are readily convertible to cash.

(d) Resource properties

Exploration and evaluation (“E&E”) costs

Pre-license costs are expensed in the period in which they are incurred.

E&E costs are initially capitalized as either tangible or intangible E&E assets according to the nature of the assets acquired. Intangible E&E assets may include costs of license acquisition, technical services and studies, seismic acquisition, exploration drilling and testing, and directly attributable overhead and administration expenses. The costs are accumulated in cost centers by well, field or exploration area pending determination of technical feasibility and commercial viability.

E&E assets are assessed for impairment if sufficient data exists to determine technical feasibility and commercial viability or facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For purposes of impairment testing, E&E assets are assessed at the individual asset level. If it is not possible to estimate the recoverable amount of the individual asset, exploration and evaluation assets are allocated to cash-generating units (“CGU’s”). Such CGU’s are not larger than an operating segment.

Exploration assets are not depleted and are carried forward until technical feasibility and commercial viability of extracting a mineral resource is considered to be determinable or sufficient/continued progress is made in assessing the commercial viability of the E&E assets. The technical feasibility and commercial viability of extracting a mineral resource is considered to be determinable when proven reserves are determined to exist. A review of each exploration license or field is carried out, at least annually, to confirm whether the Company intends further appraisal activity or to otherwise extract value from the property. When this is no longer the case, the costs are written off. Upon determination of proven reserves, E&E assets attributable to those reserves are first tested for impairment and then reclassified from E&E assets to oil and natural gas properties.

The Company may occasionally enter into arrangements, whereby the Company will transfer part of an oil and gas interest, as consideration, for an agreement by the transferee to meet certain E&E expenditures which would have otherwise been undertaken by the Company. The Company does not record any expenditures made by the transferee. Any cash consideration received from the agreement is credited against the costs previously capitalized to the oil and gas interest given up by the Company, with any excess cash accounted for as a gain on disposal.

Oil and gas properties and other property and equipment costs

Items of property and equipment, which include oil and gas development and production assets, are measured at cost less accumulated depletion and depreciation and accumulated impairment losses.

The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of the decommissioning obligation and, for qualifying assets, borrowing costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset. When significant parts of an item of property and equipment, including oil and natural gas interests, have different useful lives, they are accounted for as separate items (major components).

F-10

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

(d) Resource properties (continued)

Depletion and Depreciation

Oil and gas development and production assets are depreciated, by significant component, on a unit-of-production basis over proved and probable reserve volumes, taking into account estimated future development costs necessary to bring those reserves into production. Future development costs are estimated by taking into account the level of development required to produce the reserves. These estimates are reviewed by independent reserve engineers at least annually. Changes in reserve estimates are dealt with prospectively. Proved and probable reserves are estimated using independent reserve engineer reports and represent the estimated quantities of oil, natural gas and gas liquids.

Other property and equipment are depreciated based on a declining balance basis, which approximates the estimated useful lives of the asset, at the following rates:

Office furniture and equipment	20%
Computer equipment	45%
Vehicle	30%
Leasehold improvements	term of lease

Depreciation methods, useful lives and residual values are reviewed at each reporting date. Other property and equipment are allocated to each of the Company’s primary cash-generating units, based on estimated future net revenue, consistent with the recoverable values applied in the most recent impairment test.

Derecognition

The carrying amount of an item of property and equipment is derecognized on disposal, when no beneficial interest is retained, or when no future economic benefits are expected from its use or disposal. The gain or loss arising from derecognition is included in profit or loss when the item is derecognized and is measured as the difference between the net disposal proceeds, if any, and the carrying amount of the item. The date of disposal is the date when the Company is no longer subject to the risks of ownership and is no longer the beneficiary of the rewards of ownership. Where the asset is derecognized, the date of disposal coincides with the date the revenue from the sale of the asset is recognized.

On the disposition of an undivided interest in a property, where an economic benefit remains, the Company recognizes the farm out only on the receipt of consideration by reducing the carrying amount of the related property with any excess recognized in profit or loss of the period.

Major maintenance and repairs

The costs of day-to-day servicing are expensed as incurred. These primarily include the costs of labor, consumables and small parts. Material costs of replaced parts, turnarounds and major inspections are capitalized as it is probable that future economic benefits will be received. The carrying value of a replaced part is derecognized in accordance with the derecognition principles above.

Jointly controlled operations

The Company conducts its oil and gas development and production activities through jointly controlled operations and the accounts reflect only its interest in such activities. A joint arrangement exists where the parties take their share of the output and is accounted for by recognizing the Company’s share of assets and liabilities jointly owned and incurred, and the recognition of its share of revenue and expenses of the joint operation. At December 31, 2017, the Company’s material joint operation in Canada is Drake/Woodrush. The principal activity is oil and gas production and the ownership percentage is 99% (December 31, 2016 – 99%).

F-11

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

(e) Provisions

A provision is recognized if, as a result of a past event, the Company 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. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risk specific to the liability.

Decommissioning liability

A decommissioning liability is recognized when the Company has a present legal or constructive obligation as a result of past events, it is probable that an outflow of resources will be required to settle the obligation, and a reliable estimate of the amount of obligation can be made. A corresponding amount equivalent to the provision is also recognized as part of the cost of the related asset. The amount recognized is management’s estimated cost of decommissioning, discounted to its present value using a risk free rate. Changes in the estimated timing of decommissioning or decommissioning cost estimates are dealt with prospectively by recording an adjustment to the provision and a corresponding adjustment to the related asset unless the change arises from production. The unwinding of the discount on the decommissioning provision is included as a finance cost. Actual costs incurred upon settlement of the decommissioning liability are charged against the provision to the extent the provision was established.

(f) Earnings (loss) per share

Basic earnings (loss) per share figures have been calculated using the weighted average number of common shares outstanding during the respective periods.

Diluted earnings (loss) per common share is calculated by dividing the profit or loss applicable to common shares by the sum of the weighted average number of common shares issued and outstanding and all additional common shares that would have been outstanding if potentially dilutive instruments were converted. The diluted earnings (loss) per share figure is equal to that of basic earnings (loss) per share since the effects of options and warrants have been excluded as they are anti-dilutive.

(g) Share based payments

Where equity-settled share options are awarded to employees, the fair value of the options at the date of grant is charged to profit or loss over the vesting period. Performance vesting conditions are taken into account by adjusting the number of equity instruments expected to vest at each reporting date so that, ultimately, the cumulative amount recognized over the vesting period is based on the number of options that will eventually vest. Where equity instruments are granted to employees, they are recorded at the instruments grant date fair value.

Where the terms and conditions of options are modified before they vest, the increase in the fair value of the options, measured immediately before and after the modification, is also charged to profit or loss over the remaining vesting period.

Where equity instruments are granted to non-employees, they are recorded at the fair value of the goods or services received in profit or loss, unless they are related to the issuance of shares. Amounts related to the issuance of shares are recorded as a reduction of share capital.

When the value of goods or services received in exchange for the share-based payment to non-employees cannot be reliably estimated, the fair value of the share-based payment is measured by use of a valuation model to measure the value of the equity instruments issued. The expected life used in the model is adjusted, based on management’s best estimate, for the effects of non-transferability, exercise restrictions, and behavioural considerations.

All equity-settled share based payments are reflected in contributed surplus, until exercised. Upon exercise, shares are issued from treasury and the amount reflected in contributed surplus is credited to share capital along with any consideration received.

F-12

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

(g) Share based payments (continued)

Where a grant of options is cancelled or settled during the vesting period, excluding forfeitures when vesting conditions are not satisfied, the Company immediately accounts for the cancellation as an acceleration of vesting and recognizes the amount that otherwise would have been recognized for services received over the remainder of the vesting period. Any payment made to the employee on the cancellation is accounted for as the repurchase of an equity interest except to the extent the payment exceeds the fair value of the equity instrument granted, measured at the repurchase date. Any such excess is recognized as an expense.

(h) Revenue recognition

Revenue from the sale of oil and petroleum products is recognized when the significant risks and rewards of ownership have been transferred, which is when title passes to the customer. This generally occurs when the product is physically transferred into a vessel, pipe or other delivery mechanism. Revenue is stated after deducting sales taxes, excise duties and similar levies.

Revenue from the production of oil and natural gas in which the Company has an interest with other producers is recognized based on the Company’s working interest and the terms of the relevant production sharing contracts.

(i) Financial instruments

Financial assets

Financial assets are classified as one of the following categories. All transactions related to financial instruments are recorded on a trade date basis. The Company's accounting policy for each category is as follows:

Loans and receivables

These assets are non-derivative financial assets resulting from the delivery of cash or other assets by a lender to a borrower in return for a promise to repay on a specified date or dates, or on demand. They are initially recognized at fair value plus transaction costs that are directly attributable to their acquisition or issue and subsequently carried at amortized cost, using the effective interest rate method, less any impairment losses. Amortized cost is calculated taking into account any discount or premium on acquisition and includes fees that are an integral part of the effective interest rate and transaction costs. Gains and losses are recognized in profit or loss when the loans and receivables are derecognized or impaired, as well as through the amortization process. The Company’s loans and receivables comprise cash and cash equivalents and accounts and other receivables.

Held-to-maturity investments

Held to maturity investments are initially measured at fair value and are subsequently measured at amortized cost using the effective interest rate method, less any impairment losses. The Company does not currently have any held-to-maturity investments.

Available-for-sale assets

Available-for-sale assets are measured at fair value, with unrealized gains and losses recorded in other comprehensive income (loss) until the asset is realized or impairment is viewed as other than temporary, at which time they will be recorded in profit or loss. The Company does not currently have any available-for-sale assets.

F-13

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

(i) Financial instruments (continued)

Financial assets at fair value through profit or loss

An instrument is classified at fair value through profit or loss if it is held for trading or is designated as such upon initial recognition. Financial instruments are designated at fair value through profit or loss if the Company manages such investments and makes purchase and sale decisions based on their fair value in accordance with the Company’s risk management or investment strategy. Upon initial recognition, attributable transaction costs are recognized in profit or loss when incurred. Financial instruments at fair value through profit or loss are measured at fair value, and changes therein are recognized in profit or loss. The Company does not have any financial assets at fair value through profit or loss.

Financial liabilities

Financial liabilities are classified as either fair value through profit or loss or other financial liabilities, based on the purpose for which the liability was incurred.

The Company’s other financial liabilities comprise accounts payable and accrued liabilities, bank credit facility, loans from related parties and financial contract liability. These liabilities are initially recognized at fair value, net of any transaction costs directly attributable to the issuance of the instrument and subsequently carried at amortized cost using the effective interest rate method, which ensures that any financing expense over the period of repayment is at a constant rate on the balance of the liability carried in the balance sheet. Interest expense in this context includes initial transaction costs and premiums payable on redemption, as well as any interest or coupon payable while the liability is outstanding. Any revision to the amount or timing of cash flows related to an instrument is reflected in its carrying amount by computing the present value of the revised cash flows at the instrument’s initial effective interest rate. The change in carrying amount is reflected in profit or loss of the period. Accounts payable represent liabilities for goods and services provided to the Company prior to the end of the period which are unpaid. Accounts payable amounts are unsecured and are usually paid within 30 days from receipt of invoice.

Financial liabilities are classified as held-for-trading if they are acquired for the purpose of selling in the near term. Derivatives are also categorized as held for trading unless they are designated as hedges.

The Company has derivative financial instruments in the form of warrants issued in US dollars, or with certain adjustment provisions, and contracts entered into to manage its exposure to volatility in commodity prices. Commodity contracts are not used for trading or other speculative purposes. Such derivative financial instruments are initially recognized at fair value at the date at which the derivatives are issued and are subsequently re-measured at fair value. These derivatives do not qualify for hedge accounting and changes in fair value are recognized immediately in profit and loss.

For outstanding warrants at each reporting period, the change in the fair value of the liability between reporting periods is recorded in the consolidated statement of comprehensive income (loss). As warrants are exercised, immediately before exercise, the liability on these exercised warrants is re-measured and the valuation change is recorded in the consolidated statement of comprehensive income (loss). Upon exercise, the re-measured warrant liability on these exercised warrants is eliminated and there is an offsetting entry to share capital.

Financial instrument measurement

If the market value for a financial instrument is not an active market the Company establishes fair value by using a valuation technique. Valuation techniques include using recent arm’s length market transaction between knowledgeable, willing parties, if available, reference to the current fair value of another instrument that is substantially the same, discounted cash flow analysis and option pricing models. The fair value of a financial instrument will be based on one or more factors that may include the time value of money, credit risk, commodity prices, equity prices, volatility, servicing costs and other factors.

F-14

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

(j) Impairment

Impairment of financial assets

At each reporting date, the Company assesses whether there is objective evidence that a financial asset is impaired. If such evidence exists, the Company recognizes an impairment loss, as follows:

Financial assets are carried at amortized cost. The loss is the difference between the amortized cost of the loan or receivable and the present value of the estimated future cash flows, discounted using the instrument’s original effective interest rate. The carrying amount of the asset is reduced by this amount either directly or indirectly through the use of an allowance account.

Impairment losses on financial assets carried at amortized cost are reversed in subsequent periods if the amount of the loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognized.

Non-financial assets

For the purpose of impairment testing, assets are grouped together in CGUs, which are the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets. The carrying value of long-term assets is reviewed at each period for indicators that the carrying value of an asset or a CGU may not be recoverable. The Company uses geographical proximity, geological similarities, analysis of shared infrastructure, commodity type, assessment of exposure to market risks and materiality to define its CGUs. If indicators of impairment exist, the recoverable amount of the asset or CGU is estimated. If the carrying value of the asset or CGU exceeds the recoverable amount, the asset or CGU is written down with an impairment recognized in profit or loss.

The recoverable amount of an asset or CGU is the greater of its value in use and its fair value less costs to sell. Fair value is determined to be the amount for which the asset could be sold in an arm’s length transaction. For resource properties, fair value less costs to sell may be determined by using discounted future net cash flows of proved and probable reserves using forecast prices and costs. Value in use is determined by estimating the net present value of future net cash flows expected from the continued use of the asset or CGU.

Impairment losses recognized in prior years are assessed at each reporting date for any indication that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimate used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation, if no impairment loss had been recognized.

(k) Taxes

Income taxes

Income tax expense comprises current and deferred tax. Income tax expense is recognized in profit or loss except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity.

Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.

F-15

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

(k) Taxes (continued)

Deferred tax is recognized for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on temporary differences on the initial recognition of assets or liabilities in a transaction that is not a business combination and affects neither accounting profit nor taxable profit. In addition, deferred tax is not recognized for taxable temporary differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when the asset is realized or the liability is settled, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, when they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously.

A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

Production taxes

Royalties, resource rent taxes and revenue-based taxes are accounted for under International Accounting Standards (‘IAS’) 12 when they have characteristics of an income tax. This is considered to be the case when they are imposed under Government authority and the amount is payable based on taxable income, rather than based on quantity produced or as a percentage of revenue, after adjustment for temporary differences. For such arrangements, current and deferred tax is provided on the same basis as described above for other forms of taxation. Obligations arising from royalty arrangements that do not satisfy these criteria are recognized as a reduction of revenues.

(l) Share capital

The Company’s common shares, stock options, share purchase warrants and flow-through shares are classified as equity instruments only to the extent that they do not meet the definition of a financial liability or financial asset. Incremental costs directly attributable to the issue of equity instruments are shown in equity as a deduction, net of tax, from the proceeds.

(m) Flow-through shares

The Company will from time to time, issue flow-through common shares to finance a portion of its exploration program. Pursuant to the terms of the flow-through share agreements, these shares transfer the tax deductibility of qualifying resource expenditures to investors. On issuance, the Company separates the flow-through share into i) a flow-through share premium, equal to the estimated premium, if any, investors pay for the flow-through feature, which is recognized as a liability and; ii) share capital. Upon expenditures being incurred, the Company derecognizes the liability and recognizes a deferred income tax recovery for the amount of tax reduction renounced to the shareholders.

(n) Adoption of new and amended standards

There were no new or amended accounting standards or interpretations that had a significant impact on the Company’s consolidated financial statements during the year ended December 31, 2017.

F-16

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

(o) Future accounting pronouncements

Certain pronouncements were issued by “IASB” or “IFRIC” that are mandatory for accounting periods beginning after January 1, 2018 or later periods. The following new accounting standards, amendments to accounting standards and interpretations, have not been early adopted in these consolidated financial statements:

IFRS 9, “Financial Instruments”: In July 2014, the IASB completed the final phase of its project to replace IAS 39, the current standard on the recognition and measurement of financial instruments. IFRS 9 is now the new standard which sets out the recognition and measurement requirements for financial instruments and some contracts to buy or sell non-financial items. IFRS 9 provides a single model of classifying and measuring financial assets and liabilities and provides for only two classification categories: amortized cost and fair value. Hedge accounting requirements have also been updated in the new standard and are now more aligned with the risk management activities of an entity. IFRS 9 is effective for annual periods beginning on or after January 1, 2018. Early adoption is permitted; however, if an entity elects to apply this standard early, it must disclose that fact and apply all of the requirements in this standard at the same time. The Company has determined that there will not be any material impact on its consolidated financial statements as a result of the adoption of IFRS 9.

IFRS 15, “Revenue from Contracts with Customers”: the standard was issued in May 2014 and amended in April 2016. IFRS 15 applies to contracts with customers, excluding, most notably, insurance and leasing contracts. IFRS 15 prescribes a framework in accounting for revenues from contracts within its scope, including (a) identifying the contract, (b) identify separate performance obligations in the contract, (c) determine the transaction price of the contract, (d) allocate the transaction price to the performance obligations and (e) recognize revenues when each performance obligation is satisfied. IFRS 15 also prescribes additional financial statement presentations and disclosures. The Company currently expects to adopt IFRS 15 as of January 1, 2018, under the modified retrospective method where the cumulative effect is recognized at the date of initial application. The Company has completed the evaluation of IFRS 15. It has been concluded that the adoption of IFRS 15 will not have a material effect on the Company’s consolidated financial statements.

IFRS 16, “Leases”: In January 2016, the IASB issued the standard to replace IAS 17 “Leases”. For lessees applying IFRS 16, a single recognition and measurement model for leases would apply, with required recognition of assets and liabilities for most leases. The standard will come into effect for annual periods beginning on or after January 1, 2019, with earlier adoption permitted. It is anticipated that the adoption of IFRS 16 will have impact on the Company’s consolidated balance sheet due to the operating lease commitments as disclosed in note 17.

NOTE 4 - CRITICAL ACCOUNTING ESTIMATES AND JUDGMENTS

The preparation of financial statements in accordance with IFRS requires management to make estimates and judgments that affect reported assets, liabilities, revenues, expenses, gains, and losses. These estimates and judgments are subject to change based on experience and new information. The financial statement areas that require significant estimates and judgments are as follows:

Decommissioning liability

The Company recognizes decommissioning liabilities for its exploration and evaluation assets and property and equipment. Measurement of the decommissioning liabilities involves estimates and judgements as to the cost and timing of incurrence of future decommissioning programs. It also involves assessment of appropriate discount rates, rates of inflation applicable to future costs and the rate used to measure the accretion charge for each reporting period. Measurement of the liability also reflects current engineering methodologies as well as current and expected future environmental legislation and standards. Actual decommissioning costs will ultimately depend on future market prices for the decommissioning costs which will reflect the market conditions at the time the decommissioning costs are actually incurred. The final cost of the currently recognized decommissioning provisions may be higher or lower than currently provided for.

F-17

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 4 - CRITICAL ACCOUNTING ESTIMATES AND JUDGMENTS (continued)

Exploration and evaluation expenditures

The application of the Company’s accounting policy for exploration and evaluation expenditures requires judgment in determining whether it is likely that future economic benefits will flow to the Company, which is based on assumptions about future events or circumstances. Estimates and assumptions made may change if new information becomes available. If, after the expenditure is capitalized, information becomes available suggesting that the recovery of the expenditure is unlikely, the amount capitalized is written off in profit or loss in the period in which the new information becomes available.

Share-based payment transactions

The Company measures the cost of equity-settled transactions with employees by reference to the fair value of the equity instruments at the date at which they are granted. Management uses judgment to determine the most appropriate valuation model to estimate the fair value for share-based payment transactions. The inputs to the valuation model, including the expected life of the share option, volatility and dividend yield, require judgment for determination.

Financial contract liability

The application of the Company’s accounting policy for financial liabilities requires the Company to adjust the carrying amounts of the financial liabilities in the event it revises its payments or receipts to reflect actual and revised estimated cash flows. The Company’s financial contract liability was originally recognized at fair value using the effective interest method which ensures that any interest expense over the period of repayment is at a constant rate on the balance of the liability carried in the balance sheet. Effective June 30, 2014, the Company’s financial contract liability was reduced by the residual reserve value of its working interest in the wellbores at September 30, 2016.

At December 31, 2017, the financial contract liability was adjusted to reflect the present value of the amount outstanding at year-end, net of the present value of the residual reserves of its working interest in the wellbores.

Impairment

Management applies judgment in assessing the existence of impairment and impairment reversal indicators based on various internal and external factors.

The recoverable amounts of CGUs and individual assets have been determined based on the higher of fair value less costs to sell or value-in-use. The key estimates the Company applies in determining the recoverable amount normally include anticipated future commodity prices, expected production volumes, future operating and development costs, and discount rates. Changes to these assumptions will affect the recoverable amounts of CGUs and individual assets and may then require a material adjustment to their related carrying value. At December 31, 2017, the Company has one CGU in Canada (Drake/Woodrush) and one CGU in the United States (Kokopelli) – Note 6.

Financial instruments

When estimating the fair value of financial instruments, the Company uses valuation methodologies that utilize observable market data where available. In addition to market information, the Company incorporates transaction specific details that market participants would utilize in a fair value measurement, including the impact of non-performance risk. See note 9 for the basis of valuation of loans from related parties and warrants issued in the year.

F-18

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 4 - CRITICAL ACCOUNTING ESTIMATES AND JUDGMENTS (continued)

Reserves

The estimate of reserves is used in forecasting the recoverability and economic viability of the Company’s oil and gas properties, and in the depletion and impairment calculations. The process of estimating reserves is complex and requires significant interpretation and judgment. It is affected by economic conditions, production, operating and development activities, and is performed using available geological, geophysical, engineering, and economic data. Reserves are evaluated at least annually by the Company’s independent reserve evaluators and updates to those reserves, if any, are estimated internally. Future development costs are estimated using assumptions as to the number of wells required to produce the commercial reserves, the cost of such wells and associated production facilities and other capital costs.

NOTE 5 – EXPLORATION AND EVALUATION (“E&E”) ASSETS

	Canadian Oil	United States
	and Gas	Oil and Gas
	Properties	Properties		Total
	$	$		$
Cost:
Balance at January 1, 2016	281	18,982		19,263
Additions	2	-		2
Change in decommissioning provision	13	-		13
Disposals	-	(772	)	(772	)
Foreign currency translation and other	-	(768	)	(768	)
Balance at December 31, 2016	296	17,442		17,738
Additions	4	3		7
Change in decommissioning provision	56	-		56
Disposals	-	-		-
Foreign currency translation and other	-	(1,174	)	(1,174	)
Balance at December 31, 2017	356	16,271		16,627

	Canadian Oil		United States
	and Gas		Oil and Gas
	Properties		Properties		Total
	$		$		$
Accumulated impairment losses:
Balance at January 1, 2016	-		(16,041	)	(16,041	)
Impairment losses	-		(1,790	)	(1,790	)
Disposals	-		513		513
Foreign currency translation and other	-		550		550
Balance at December 31, 2016	-		(16,768	)	(16,768	)
Impairment losses (Note 7)	(350	)	(621	)	(971	)
Disposals	-		-		-
Foreign currency translation and other	-		1,120		1,120
Balance at December 31, 2017	(350	)	(16,269	)	(16,619	)

F-19

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 5 – EXPLORATION AND EVALUATION (“E&E”) ASSETS (continued)

	Canadian Oil	United States
	and Gas	Oil and Gas
	Properties	Properties	Total
	$	$	$
Carrying amounts:
At December 31, 2016	296	674	970
At December 31, 2017	6	2	8

Exploration and evaluation (“E&E”) assets consist of the Company’s exploration projects which are pending the determination of proven reserves.

United States Exploration and Evaluation Properties

As at December 31, 2017, the Company holds oil and gas leases in the Piceance, Paradox and Uinta Basins in the US Rocky Mountains, of which a portion was classified as E&E assets.

The E&E asset impairment is $621,000 and $1,790,000 for the year ended December 31, 2017 and December 31, 2016, respectively. The impairment was recognized upon a review of each exploration license or field, carried out, at least annually, to confirm whether the Company intends further appraisal activity or to otherwise extract value from the property.

NOTE 6 – PROPERTY AND EQUIPMENT

	Canadian Oil		United States
	and Gas		Oil and Gas		Corporate and
	Properties		Properties		Other Assets		Total
	$		$		$		$
Cost:
Balance at January 1, 2016	33,376		16,653		179		50,208
Additions	300		225		3		528
Change in decommissioning provision	(48	)	(4	)	-		(52	)
Foreign currency translation and other	-		(502	)	-		(502	)
Balance at December 31, 2016	33,628		16,372		182		50,182
Additions	405		39		5		449
Change in decommissioning provision	94		(3	)	-		91
Disposals	-		-		(29	)	(29	)
Foreign currency translation and other	-		(1,060	)	-		(1,060	)
Balance at December 31, 2017	34,127		15,348		158		49,633

F-20

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 6 – PROPERTY AND EQUIPMENT (continued)

	Canadian Oil		United States
	and Gas		Oil and Gas		Corporate and
	Properties		Properties		Other Assets		Total
	$		$		$		$
Accumulated amortization, depletion and impairment
losses:
Balance at January 1, 2016	(26,774	)	(1,375	)	(160	)	(28,309	)
Amortization and depletion	(1,248	)	(380	)	(5	)	(1,633	)
Impairment losses	(1,070	)	-		-		(1,070	)
Foreign currency translation and other	-		41		1		42
Balance at December 31, 2016	(29,092	)	(1,714	)	(164	)	(30,970	)
Amortization and depletion (Note 7)	(561	)	(223	)	(3	)	(787	)
Impairment losses (Note 7)	(870	)	-		-		(870	)
Disposals	-		-		25		25
Foreign currency translation and other	-		131		-		131
Balance at December 31, 2017	(30,523	)	(1,806	)	(142	)	(32,471	)

	Canadian Oil	United States
	and Gas	Oil and Gas	Corporate and
	Properties	Properties	Other Assets	Total
	$	$	$	$
Carrying amounts:
At December 31, 2016	4,536	14,658	18	19,212
At December 31, 2017	3,604	13,542	16	17,162

Canadian Oil and Gas Properties

Amortization and depletion is computed using the unit of production method by reference to the total production for the CGU over the estimated net proved and probable reserves of oil and gas for the CGU determined by independent consultants. The calculation of amortization and depletion for the year ended December 31, 2017 included estimated future development costs of $Nil (December 31, 2016 - nil; December 31, 2015 - $nil) as estimated by the Company’s external reserves evaluator.

During the year ended December 31, 2017, the Company capitalized $7,000 (December 31, 2016 – $104,000) of general and administrative costs related to its Canadian oil and gas interests.

In accordance with IFRS, impairment tests were conducted at December 31, 2017 on each of the Company’s CGUs. The estimated recoverable amounts were determined using fair value less cost to sell. In determining the recoverability of oil and gas interests and making these evaluations, the Company used the net present value of the cash flows from proved plus probable oil and gas reserves of each CGU as estimated by the Company’s independent reserve evaluator.

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

a)	Reserves – Assumptions that are valid at the time of reserve estimation may change significantly when new information becomes available. Changes in forward price estimates, production costs or recovery rates may change the economic status of reserves and may ultimately result in reserves being restated.
b)	Crude oil and natural gas prices – Forward price estimates of the crude oil and natural gas prices are used in the cash flow model. Commodity prices have fluctuated widely in recent years due to global and regional factors including supply and demand fundamentals, inventory levels, exchange rates, weather, economic and geopolitical factors.
c)	Discount rate – The discount rate used to calculate the net present value of cash flows is 14.4% post tax.

F-21

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 6 – PROPERTY AND EQUIPMENT (continued)

Below are the following forward commodity price estimates used in the December 31, 2017 impairment test:

	Natural gas	NGL	Crude oil
	(AECO)	(Edmonton Pentanes Plus)	(Edmonton Par)
	Cdn $ / mmbtu	Cdn $ / bbl	Cdn $ / bbl
2018	2.20	76.42	70.25
2019	2.54	74.68	70.25
2020	2.88	74.38	70.31
2021	3.24	77.16	72.84
2022	3.47	79.88	75.61
2023	3.58	82.53	78.31
2024	3.66	86.14	81.93
2025	3.73	89.76	85.54
2026	3.80	92.57	88.35
2027	3.88	94.43	90.22
Each benchmark price increased on average approximately 2% thereafter

For the year ended December 31, 2017, the Company recorded an impairment of $870,000 (December 31, 2016 - $940,000) on its Drake/Woodrush CGU. The impairment was recognized because the carrying value exceeded the recoverable amount. The fair value less cost to sell values used to determine the recoverable amounts of the impaired PP&E assets are classified as Level 3 fair value measurements.

On December 22, 2017, the Company signed a “Funding and Participation Agreement” (“the Agreement”) with a private U.S. based investment firm to underwrite 50% of the capital costs of at least one exploration well at Woodrush, currently scheduled to commence in the first quarter of 2018. Under the terms of the Agreement, the investment firm will pay approximately two-thirds of the total cost of the first well of the 2018 program, through tie in, to earn a 15% Gross Overriding Royalty (“GORR”).

The investment firm has the right to elect to participate in the drilling and completion of a 2^nd and subsequent wells, if any, by paying 50% of the capital costs to earn a 15% GORR in the well spacing unit on a well-by-well basis.

United States Oil and Gas Properties

Amortization and depletion is computed using the unit of production method by reference to the total production for the CGU over the estimated net proved and probable reserves of oil and gas for the CGU determined by independent consultants. The calculation of amortization and depletion for the year ended December 31, 2017 included estimated future development costs of $83.7 million (December 31, 2016 - $84.0 million; December 31, 2015 - $86.4 million) as estimated by the Company’s external reserves evaluator.

During the year ended December 31, 2017, the Company capitalized $12,000 (December 31, 2016 – $14,000) of general and administrative costs related to its US oil and gas interests.

At December 31, 2017 and December 31, 2016, the Company evaluated its oil and gas interests for indicators of any impairment or related recovery. The Company determined the recoverable amount of the CGU based on the cash flows from oil and gas reserves, using a discount rate of 14.3% (post tax) and determined there was no impairment at December 31, 2017 and December 31, 2016. The key inputs used included forward prices from NYMEX futures (adjusted for an inflationary factor), a discount rate of 14.3% (post tax) which was applied to the discounted cash flows and the reserves that were estimated.

F-22

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 7 – AMORTIZATION, DEPLETION AND IMPAIRMENT LOSSES

	Year ended December 31
	2017	2016	2015
	$	$	$
Exploration and Evaluation Assets (E & E assets)
Impairment losses (Note 5)	971	1,790	534
Property and Equipment (D & P assets)
Amortization and depletion (Note 6)	787	1,633	2,655
Impairment losses (Note 6)	870	1,070	1,000
	2,628	4,493	4,189

NOTE 8 – LOANS FROM RELATED PARTIES

(a) Loan from Hodgkinson Equity Corporation (“HEC”)

On March 12, 2015, as amended on May 6, 2015, June 22, 2015, September 28, 2015, November 18, 2015 and June 5, 2017, the Company issued a promissory note for $4,500,000 to HEC, a private company controlled by the CEO of the Company. The promissory note is secured by all assets of Dejour USA and a negative pledge by the Company not to further encumber DEAL’s oil and gas properties without HEC’s prior approval. The principal and interest at Canadian prime rate plus 5% per annum was repayable by the earlier of (i) within 10 business days of receipt of written demand from HEC for the repayment and (ii) June 10, 2015 or such later date to which the term of the promissory note may be extended. On May 6, 2015, the due date of the loan was extended to September 30, 2015. On September 28, 2015, the due date of the loan was further extended to December 31, 2015. On November 18, 2015, the Company extended the due date of the loan from December 31, 2015 to November 30, 2018. Additionally, a monthly principal repayment of $114,230 was due on the 1^st day of each month commencing June 1, 2016. HEC agreed to waive the requirement of the Company to repay the total monthly principal repayments of $1,371,000 until the loan was restructured on June 5, 2017.

In consideration for the extension, the Company issued HEC 9,000,000 Warrants. Each Warrant entitles the holder to acquire one common share at a price of C$0.45/US$ 0.35 per share any time prior to December 4, 2020. Shares acquired through the exercise of Warrants prior to April 5, 2016 were restricted from sale through the facilities of the stock exchanges for four months. On February 19, 2016, the Company rescinded the negative pledge security agreement and issued a first mortgage in favour of HEC on DEAL’s oil and gas properties. The first mortgage security so issued ranked “pari passu” with HVI’s first mortgage security interest (note 8(b)).

On June 5, 2017, the Company restructured the term of the loan with extension of the due date from November 30, 2018 to June 5, 2022; reduction of the interest rate to Canadian prime rate plus 1% per annum; and the right to convert the entire outstanding amount into 58,441,558 common shares of the Company at a price of $0.077 per share. In exchange for the modification, HEC agreed to cancel the 9,000,000 warrants described above. The fair value of the amended loan was determined by applying a risk-adjusted rate of 20% to discount the contractual cash flows over the 5-year life of the loan. The fair value of the liability component of $2,346,000 is then deducted from the face value of the amended loan ($4.5 million), with the balance being taken directly to equity.

As a result of the loan restructure in June 2017, a loss on extinguishment is recognized as follows:

	$
Face value of amended loan	2,346
Conversion feature	2,158
Carrying value of old loan before restructure	(3,976	)
Loss on extinguishment	528

⁽¹⁾ $3,903,000 (carrying value at March 31, 2017) + $127,000 (accretion) - $54,000 (cash interest) = $3,976,000

F-23

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 8 – LOANS FROM RELATED PARTIES (continued)

(a) Loan from Hodgkinson Equity Corporation (“HEC”) (continued)

As at December 31, 2017, the carrying value of the loan liability is as follows:

	$
Balance upon initial recognition	2,337
Accretion expense	265
Cash interest	(104	)
Balance at December 31, 2017	2,498
Current portion	(317	)
Non-current portion	2,181

Other terms of the loan are:

• the Company may repay the loan at any time without penalty;

• the Company, through DEAL, must receive HEC’s approval to further encumber DEAL’s Canadian oil and gas properties; and

• In the event of default, all the indebtedness secured by the promissory note becomes due and payable and the interest rate is immediately increased to Canadian prime rate plus 4.5% per annum.

(b) Loan from Hodgkinson Ventures Inc. (“HVI”)

On June 22, 2015, as amended on September 28, 2015, November 18, 2015 and June 5,2017, the Company issued a promissory note for $2,000,000 to HVI, a private company associated with the CEO of the Company, on a “pari passu” basis with the loan from HEC (note 8(a)). The promissory note is secured by all assets of Dejour USA and a negative pledge by the Company not to further encumber DEAL’s oil and gas properties without HVI’s prior approval. The principal and interest at Canadian prime rate plus 5% per annum were repayable on or before September 30, 2015. On September 28, 2015, the due date of the loan was extended to December 31, 2015. On November 18, 2015, the Company extended the due date of the loan from December 31, 2015 to November 30, 2018. Additionally, a monthly principal repayment of $50,769 was due on the 1^st day of each month commencing June 1, 2016. HVI agreed to waive the requirement of the Company to repay the total monthly principal repayments of $660,000 until the loan was restructured on June 5, 2017.

In consideration for the extension, the Company issued HVI 4,000,000 Warrants. Each Warrant entitles the holder to acquire one common share at a price of C$0.45/US$ 0.35 per share any time prior to December 4, 2020. Shares acquired through the exercise of Warrants prior to April 5, 2016 were restricted from sale through the facilities of the stock exchanges for four months. On February 19, 2016, the Company rescinded the negative pledge security agreement and issued a first mortgage in favour of HVI on DEAL’s oil and gas properties. The first mortgage security so issued ranked “pari passu” with HEC’s first mortgage security interest (note 8(a)).

On June 5, 2017, the Company restructured the term of the loan with extension of the due date from November 30, 2018 to June 5, 2022; reduction of the interest rate to Canadian prime rate plus 1% per annum; and the right to convert the entire outstanding amount into 25,974,025 common shares of the Company at a price of $0.077 per share. In exchange for the modification, HVI agreed to cancel the 4,000,000 warrants described above.

The fair value of the amended loan was determined by applying a risk-adjusted rate of 20% to discount the contractual cash flows over the 5-year life of the loan. The fair value of the liability component of $1,043,000 is then deducted from the face value of the amended loan ($2.0 million), with the balance being taken directly to equity.

F-24

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 8 – LOANS FROM RELATED PARTIES (continued)

(b) Loan from Hodgkinson Ventures Inc. (“HVI”) (continued)

As a result of the loan restructure in June 2017, a loss on extinguishment is recognized as follows:

	$
Face value of amended loan	1,043
Conversion feature	960
Carrying value of old loan before restructure	(1,613	)
Loss on extinguishment	390

⁽¹⁾ $1,560,000 (carrying value at March 31, 2017) + $77,000 (accretion) - $24,000 (cash interest) = $1,613,000

As at December 31, 2017, the carrying value of the loan liability and derivative liability are as follows:

	$
Balance upon initial recognition	1,039
Accretion expense	117
Cash interest	(46	)
Balance at December 31, 2017	1,110
Current portion	(141	)
Non-current portion	969

Other terms of the loan are:

• the Company may repay the loan at any time without penalty;

• the Company, through DEAL, must receive HVI’s approval to further encumber DEAL’s Canadian oil and gas properties; and

• In the event of default, all the indebtedness secured by the promissory note becomes due and payable and the interest rate is immediately increased to Canadian prime rate plus 4.5% per annum.

(c) Loan from a director and officer of the Company and his spouse

On September 15, 2015, as amended on January 11, 2016, March 31, 2016, June 2, 2016, September 30, 2016, December 31, 2016 and June 30, 2017, the Company issued a grid promissory note of up to $1,000,000 to a director and officer of the Company and his spouse (the “Lenders”). The promissory note bears interest at 12% per annum. The principal and interest accrued on the loan were repayable on or before December 31, 2015. On January 11, 2016, the Company issued an additional grid promissory note of up to $200,000 to a director and officer of the Company and his spouse and the due date of the loan was extended to March 31, 2016. On March 31, 2016, the due date of the loan was further extended to September 30, 2016.

On June 2, 2016, the Company increased the maximum amount of the non-revolving loan from $1,200,000 to $1,500,000. The interest rate was also reduced from 12% to 10% per annum. Additionally, the Company issued a 2^nd mortgage in favour of the Lenders on DEAL’s oil and gas properties to a maximum of $1,500,000 as partial security for the loan. On September 30, 2016, the due date of the loan was extended to December 31, 2016. On December 31, 2016, the due date of the loan was extended to June 30, 2017. On June 30, 2017, the due date of the loan was further extended to June 30, 2018. The maximum loan amount available at December 31, 2017 was $1,500,000 (December 31, 2016 - $1,500,000). During the year ended December 31, 2017, $450,000 was borrowed (2016 - $50,000) and $500,000 was repaid via issuance of the Company’s common shares (2016 - $Nil) leaving a balance outstanding of $1,000,000 at December 31, 2017 (December 31, 2016 - $1,050,000).

F-25

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 9 – FLOW-THROUGH SHARES LIABILITY

The following is a continuity schedule of the liability portion of the flow-through shares issuances:

	Issued in		Issued in
	October		December	Total
	2017		2017
	$		$	$
Balance at January 1, 2017	-		-	-
Liability incurred on flow-through shares issued	21		93	114
Settlement of flow-through share liability on incurring expenditures	(21	)	-	(21	)
Balance at December 31, 2017	-		93	93

NOTE 10 – DECOMMISSIONING LIABILITY

	Canadian		United States
	Oil and Gas		Oil and Gas
	Properties (1)		Properties (1)		Total
	$		$		$
Balance at January 1, 2016	3,679		146		3,825
Change in estimated future cash flows	(36	)	(4	)	(40	)
Actual costs incurred and other	(53	)	(5	)	(58	)
Unwinding of discount	46		3		49
Balance at December 31, 2016	3,636		140		3,776
Change in estimated future cash flows	146		(3	)	143
Actual costs incurred and other	(3	)	(8	)	(11	)
Unwinding of discount	60		3		63
Balance at December 31, 2017	3,839		132		3,971

⁽¹⁾ relates to property and equipment (note 6)

The present value of the decommissioning liability was calculated using the following weighted average inputs:

	Canadian Oil	United States
	and Gas	Oil and Gas
	Properties	Properties
As at December 31, 2017:
Discount rate	1.94%	2.20%
Inflation rate	2.00%	2.00%
As at December 31, 2016:
Discount rate	1.60%	2.34%
Inflation rate	2.00%	2.00%

F-26

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 11 – FINANCIAL CONTRACT LIABILITY

On December 31, 2012, Dejour USA entered into a financial contract with a U.S. oil and gas drilling fund (“Drilling Fund”) to fund the drilling of up to three wells and the completion of up to four wells in the State of Colorado. The total amount contributed by the Drilling Fund was US$7,000,000.

The financial contract contains a provision whereby Dejour USA must purchase the Drilling Funds’ working interest in the four wells funded by the US$7,000,000 if the Drilling Fund fails to obtain a certain minimum return on investment by September 30, 2016. A subsequent amendment limited Dejour USA’s cash exposure to a potential “put” by the Drilling Fund to US$3,000,000, with the difference to be settled by an assignment of working interests in certain P&NG properties owned by Dejour USA. The Company is not a party to the financial contract.

On September 30, 2016, the Drilling Fund served notice to Dejour USA requiring Dejour USA to purchase the Drilling Funds’ working interest in the 4 wellbores in accordance with the contract. However, prior to serving such notice, the Drilling Fund executed certain assignments transferring ownership of its working interests in the 4 wellbores to another entity and the assignee mortgaged its interest therein. Dejour USA and its attorneys are reviewing the impact of the Drilling Fund’s actions on the validity of the financial contract between the parties.

As at December 31, 2017, Dejour USA has recorded a liability owing to the Drilling Fund of $6,752,000, as follows:

	$
Balance at January 1, 2016 (US$5,207)	7,207
Accretion expense (US$222)	296
Foreign exchange gain	(214	)
Adjustment to financial contract liability (US$47)	(63	)
Balance at December 31, 2016 (US$5,382)	7,226
Foreign exchange gain	(474	)
Balance at December 31, 2017 (US$5,382)	6,752

This amount, if any, is subject to a resolution of the financial contract between the parties. Dejour USA has received no formal communication from the Drilling Fund since the “put” notice date of September 30, 2016.

NOTE 12 – SHARE CAPITAL

Authorized

The Company is authorized to issue an unlimited number of common voting shares, an unlimited number of first preferred shares issuable in series, and an unlimited number of second preferred shares issuable in series. No preferred shares have been issued and the terms of preferred shares have not been defined.

In January 2018, the Company renounced $523,000 flow-through funds to investors, using the look-back rule. The Company expects to fully spend the flow-through funds during 2018 and a deferred income tax recovery of $93,000 will be recognized on settlement of flow-through shares liability.

In December 2017, the Company renounced $149,000 flow-through funds to investors, using the general rule. The flow-through funds had been fully spent by December 31, 2017. As a result of renunciation, a deferred income tax recovery of $21,000 was recognized on settlement of the flow-through shares liability.

In December 2017, the Company completed a private placement and 8,633,166 common shares were issued at a price of $0.075 per share for gross proceeds of $647,000 and an additional 5,738,665 flow-through shares were issued for gross proceeds of $523,000 (5,091,165 at $0.09 per share and 647,500 at $0.10 per share). The Company paid finders’ fees of $51,000 and other costs of $24,000 related to this offering. 946,667 of the common shares were issued at $0.075 per share to certain creditors of the Company to settle the amounts owing to them.

F-27

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 12 – SHARE CAPITAL (continued)

In October 2017, the Company completed a private placement and 42,297,400 common shares were issued at a price of $0.06 per share for gross proceeds of $2,538,000 and additional 2,128,571 flow-through shares were issued at a price of $0.07 per share for gross proceeds of $149,000. The Company paid finders’ fees of $41,000 and other costs of $23,000 related to this offering. 21,924,067 of the common shares were issued at $0.06 per share to Directors and Officers of the Company (17,967,644) and certain creditors of the Company (3,956,423) to settle the amounts owing to them.

In June and July 2016, the Company completed a dual tranche private placement and 8,298,333 common shares were issued at a price of $0.12 per share for total gross proceeds of $995,800. The Company paid finders’ fees of $18,000 and other costs of $29,000 related to this offering. Directors and Officers of the Company purchased 3,600,000 common shares of this offering.

NOTE 13 – STOCK OPTIONS AND SHARE PURCHASE WARRANTS

(a) Stock Options

The Stock Option Plan (the “Plan”) is a 10% “rolling” plan pursuant to which the number of common shares reserved for issuance is 10% of the Company’s issued and outstanding common shares as constituted on the date of any grant of options.

The Plan provides for the grant of options to purchase common shares to eligible directors, senior officers, employees and consultants of the Company (“Participants”). The exercise periods and vesting periods of options granted under the Plan are to be determined by the Company with approval from the Board of Directors. The expiration of any option will be accelerated if the participant’s employment or other relationship with the Company terminates. The exercise price of an option is to be set by the Company at the time of grant but shall not be lower than the market price (as defined in the Plan) at the time of grant.

The following table summarizes information about outstanding stock option transactions:

			Weighted
	Number of		average
	options		exercise price
			$
Balance at January 1, 2016	140,738		1.20
Options granted	3,400,000		0.16
Options cancelled	(52,818	)	1.26
Options forfeited	(87,920	)	1.16
Balance at December 31, 2016 and December 31, 2017	3,400,000		0.16

Details of the stock options as at December 31, 2017 are as follows:

	Outstanding			Exercisable
		Weighted average			Weighted average
	Number	exercise	contractual	Number	exercise	contractual
	of options	price	life (years)	of options	price	life (years)
		$			$
$0.16	3,400,000	0.16	3.43	3,400,000	0.16	3.43

During the year ended December 31, 2017, the Company did not grant any stock options (2016 – 3,400,000). The fair value of the options issued during the year ended December 31, 2016 was estimated using the Black Scholes option pricing model with the following weighted average inputs:

F-28

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 13 – STOCK OPTIONS AND SHARE PURCHASE WARRANTS (continued)

(a) Stock Options (continued)

For the year ended December 31		2016
Fair value at grant date	$	0.06
Expected volatility		80.35%
Expected option life		1.37 years
Dividends		0.0%
Risk-free interest rate		0.54%
Estimated forfeiture rate		6.85%

Expected volatility is based on historical volatility and average weekly stock prices were used to calculate volatility. Management believes that the annualized weekly average of volatility is the best measure of expected volatility.

(b) Share Purchase Warrants

The following table summarizes information about warrant transactions:

	Number of		Weighted average
	warrants		exercise price
			$
Balance at January 1, 2016 and December 31, 2016	15,719,540		0.85
Warrants cancelled	(13,000,000	)	0.45
Warrants expired	(2,719,540	)	2.59
Balance at December 31, 2017	-		-

NOTE 14 – SUPPLEMENTAL INFORMATION

(a) Changes in working capital consisted of the following:

	Year ended December 31
	2017		2016		2015
	$		$		$
Changes in working capital:
Accounts receivable	284		1,530		(1,597	)
Prepaids and deposits	(10	)	12		110
Accounts payable and accrued liabilities	15		(758	)	(530	)
	289		784		(2,017	)
Comprised of:
Operating activities	219		667		204
Investing activities	32		178		(2,289	)
Financing activities	38		(61	)	68
	289		784		(2,017	)
Other cash flow information:
Cash paid for interest	480		596		417
Income taxes paid	-		-		-

F-29

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 14 – SUPPLEMENTAL INFORMATION (continued)

(b) Per share amounts:

Basic loss per share amounts has been calculated by dividing the net loss for the year attributable to the shareholders’ of the Company by the weighted average number of common shares outstanding. Stock options and share purchase warrants were excluded from the calculation. The basic and diluted net loss per share is the same as the stock options and share purchase warrants were anti-dilutive. The following table summarizes the common shares used in calculating basic and diluted net loss per common share:

	Year ended December 31,
	2017	2016	2015
Weighted average common shares outstanding
Basic	61,682,462	42,095,366	36,492,207
Diluted	61,682,462	42,095,366	36,492,207

NOTE 15 – RELATED PARTY TRANSACTIONS

During the years ended December 31, 2017, 2016 and 2015 and in addition to the loans from related parties (note 9), the Company entered into the following transactions with related parties:

(a)

Compensation awarded to key management included a total of salaries and consulting fees of $466,000 (2016 - $470,000 and 2015 - $473,000) and non-cash stock-based compensation of $Nil (2016 - $80,000 and 2015 - $464,000). Key management includes the Company’s officers and directors. The salaries and consulting fees are included in general and administrative expenses. Included in accounts payable and accrued liabilities at December 31, 2017 is $131,000 (December 31, 2016 - $262,000 and December 31, 2015 - $200,000) owing to the two officers of the Company.

(b)

Interest expenses of $370,000 (2016 - $595,000 and 2015 - $343,000) related to the loans from related parties were paid in cash to the CEO of the Company and his spouse or the companies controlled by or associated with the CEO of the Company. And, interest expenses of $139,000 (2016 - $Nil and 2015 - $Nil) related to the loans from related parties were paid via issuance of the Company’s shares to the companies controlled by or associated with the CEO of the Company.

NOTE 16 – INCOME TAXES

The actual income tax provisions differ from the expected amounts calculated by applying the Canadian combined federal and provincial corporate income tax rates to the Company’s loss before income taxes. The components of these differences are as follows:

	2017		2016		2015
	$		$		$
Loss before income taxes	(5,232	)	(5,486	)	(7,108	)
Corporate tax rate	26.44%		26.59%		26.00%
Expected tax recovery	(1,383	)	(1,459	)	(1,848	)
Increase (decrease) resulting from:
Differences in foreign tax rates and change in statutory tax rates	6,381		(231	)	(989	)
Impact of foreign exchange rate changes	1,277		506		(3,005	)
Change in unrecognized deferred tax assets	(6,507	)	1,290		4,509
Stock based compensation and expiry of losses	33		198		509
Non taxable/deductible amounts	199		(304	)	824
Deferred income tax recovery	-		-		-

F-30

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 16 – INCOME TAXES (continued)

On December 22, 2017, the United States government enacted the US Tax Cuts and Jobs Act (“Act”). The Act includes a range of legislative changes including a reduction of the US federal corporate income tax rate from 35% to 21% effective January 1, 2018. As a result of these legislative changes, the Company is required to revalue its United States deferred income tax assets and liabilities based on the rates they are expected to reverse at in the future, which is 21% for federal tax purposes. The impact for the Company’s 2017 financial statements is a reduction in deferred income tax assets of $6.38 million.

No deferred tax asset has been recognized in respect of the following losses and deductible temporary differences as it is not considered probable that sufficient future taxable profit will allow the deferred tax assets to be recovered.

	2017	2016	2015
	$	$	$
Deferred income tax assets
Non-capital losses available	20,998	26,679	26,547
Capital losses available	1,113	1,072	1,072
Resource tax pools in excess of net book value	5,279	4,846	3,726
Share issue costs and others	654	1,171	1,133
Unrecognized deferred tax assets	28,044	33,768	32,478

The Company has the approximate amounts of tax pools available as follows:

As at December 31	2017	2016	2015
	$	$	$
Canada:
Exploration and development expenditures	17,100	16,750	16,657
Unamortized share issue costs	261	292	455
Capital losses	8,242	8,242	8,242
Non-capital losses	33,120	30,783	29,148
	58,723	56,067	54,502
United States:
Exploration and development expenditures	15,883	17,149	18,560
Undeducted expenses	2,760	2,954	2,737
Non-capital losses	53,733	58,247	57,400
	72,376	78,350	78,697
Total	131,099	134,417	133,199

The exploration and development expenditures at December 31, 2017 can be carried forward to reduce future income taxes indefinitely. The non-capital losses for income tax purposes expire as follows:

F-31

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 16 – INCOME TAXES (continued)

	Canada	United States	Total
	$	$	$
2026	24	2,531	2,555
2027	3,606	3,374	6,980
2028	4,674	253	4,927
2029	3,780	3,266	7,046
2030	2,068	2,775	4,843
2031	2,408	2,794	5,202
2032	4,372	7,606	11,978
2033	2,167	16,215	18,382
2034	3,966	12,665	16,631
2035	2,292	543	2,835
2036	1,815	1,639	3,454
2037	1,948	72	2,020
	33,120	53,733	86,853

The Company does not recognize deferred tax assets related to the foregoing tax pools because it is not probable that future taxable profit will be available against which the tax pools can be utilized.

NOTE 17 – COMMITMENTS

The following is a summary of the Company’s undiscounted contractual obligations and commitments as at December 31, 2017:

		Payments Due by Period
	1 Year	2-3 Years	4-5 Years	Total
	$	$	$	$
Debt repayments(1)	1,000	-	6,500	7,500
Interest payments(2)	50	-	-	50
Operating leases	88	92	-	180
Financial contract liability	6,752	-	-	6,752
	7,890	92	6,500	14,482

(1)	Short-term and long-term loans from related parties
(2)	Fixed interest payments on loan from related parties of $1,000,000

NOTE 18 – OPERATING SEGMENTS

Segment information is provided on the basis of geographic segments as the Company manages its business through two geographic regions – Canada and the United States. The two geographic segments presented reflect the way in which the Company’s management reviews business performance. The Company’s revenue and losses of each geographic segment are as follows:

	Canada						United States						Total
	2017		2016		2015		2017		2016		2015		2017		2016		2015
	$		$		$		$		$		$		$		$		$
Year ended December 31
Revenues, net of royalties	1,814		3,190		6,606		666		883		490		2,480		4,073		7,096
Segmented loss	(4,948	)	(3,279	)	(1,769	)	(261	)	(2,207	)	(5,339	)	(5,209	)	(5,486	)	(7,108	)
Amortization, depletion and impairment losses	1,784		2,324		3,441		844		2,169		748		2,628		4,493		4,189
Interest expense	950		1,236		500		-		294		525		950		1,530		1,025
Capital expenditures	414		305		1,168		42		225		4,570		456		530		5,738

F-32

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 19 – DETERMINATION OF FAIR VALUES

A number of the Company’s accounting policies and disclosures require the determination of fair value. Fair values have been determined for measurement and/or disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes specific to that financial asset or financial liability. Due to the use of subjective judgments and uncertainties in the determination of these fair values the values should not be interpreted as being realizable in an immediate settlement of the financial instruments.

The Company classifies the fair value of financial instruments according to the following hierarchy based on the amount of observable inputs used to value the instruments:

• Level 1: Values based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities.

• Level 2: Values based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability.

• Level 3: Values based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement.

At December 31, 2017 and December 31, 2016, the derivative liability is measured using an option pricing model with significant unobservable inputs (Level 3). The financial contract liability is measured at the initial transaction price, which is deemed to be fair value, and subsequently measured based on netbacks in accordance with the Joint Operating Agreement. This model also has significant unobservable inputs (Level 3).

The following tables provide fair value measurement information for financial assets and liabilities as at December 31, 2017 and December 31, 2016:

			Quoted Prices in	Significant Other	Significant
	Carrying	Fair	Active Markets	Observable Inputs	Unobservable
December 31, 2017	Amount	Value	(Level 1)	(Level 2)	Inputs (Level 3)
	$	$	$	$	$
Financial Assets:
Cash and cash equivalents	1,010	1,010	1,010	-	-
Accounts receivable	388	388	388	-	-
Financial Liabilities:
Accounts payable and accrued liabilities	1,291	1,291	1,291	-	-
Loans from related parties	4,608	4,608	-	-	4,608
Financial contract liability	6,752	6,752	-	-	6,752

F-33

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 19 – DETERMINATION OF FAIR VALUES (continued)

			Quoted Prices in	Significant Other	Significant
	Carrying	Fair	Active Markets	Observable Inputs	Unobservable
December 31, 2016	Amount	Value	(Level 1)	(Level 2)	Inputs (Level 3)
	$	$	$	$	$
Financial Assets:
Cash and cash equivalents	141	141	141	-	-
Accounts receivable	672	672	672	-	-
Financial Liabilities:
Accounts payable and accrued liabilities	2,165	2,165	2,165	-	-
Loans from related parties	6,394	6,394	-	-	6,394
Derivative liability	153	153	-	-	153
Financial contract liability	7,226	7,226	-	-	7,226

NOTE 20 – FINANCIAL INSTRUMENTS AND CAPITAL MANAGEMENT

The Company operates in the United States, giving rise to exposure to market risks from changes in foreign currency rates. Currently, the Company does not use derivative instruments to reduce its exposure to foreign currency risk.

The Company also has exposure to a number of risks from its use of financial instruments including: credit risk, liquidity risk, and market risk. This note presents information about the Company’s exposure to each of these risks and the Company’s objectives, policies and processes for measuring and managing risk, and the Company’s management of capital.

(a) Credit Risk

Credit risk arises from credit exposure to receivables due from joint operating partners and marketers included in accounts receivable. The maximum exposure to credit risk is equal to the carrying value of the financial assets.

The Company is exposed to third party credit risk through its contractual arrangements with its current or future joint operating partners, marketers of its petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to the Company, such failures may have a material adverse effect on the Company’s business, financial condition, and results of operations.

The objective of managing the third party credit risk is to minimize losses in financial assets. The Company assesses the credit quality of the partners, taking into account their financial position, past experience, and other factors. The Company mitigates the risk of non-collection of certain amounts by obtaining the joint operating partners’ share of capital expenditures in advance of a project and by monitoring accounts receivable on a regular basis. As at December 31, 2017 and 2016, no accounts receivable has been deemed uncollectible or written off during the year.

As at December 31, 2017, the Company’s receivables consist of $196,000 (2016 - $244,000) from joint operating partners, $121,000 (2016 - $276,000) from oil and natural gas marketers and $71,000 (2016 - $152,000) from other trade receivables. The Company considers all amounts outstanding for more than 90 days as past due. Currently, there is no indication that amounts are non-collectable; thus a provision for doubtful accounts has not been set up. As at December 31, 2017, $Nil (2016 - $Nil) of accounts receivable are past due.

F-34

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 20 – FINANCIAL INSTRUMENTS AND CAPITAL MANAGEMENT (continued)

(b) Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they are due. The nature of the oil and gas industry is capital intensive and the Company maintains and monitors a certain level of cash flow to finance operating and capital expenditures.

The Company’s ongoing liquidity and cash flow are impacted by various events and conditions. These events and conditions include but are not limited to commodity price fluctuations, general credit and market conditions, operation and regulatory factors, such as government permits, the availability of drilling and other equipment, lands and pipeline access, weather, and reservoir quality.

To mitigate the liquidity risk, the Company closely monitors its credit facility, production level and capital expenditures to ensure that it has adequate liquidity to satisfy its financial obligations.

(c) Market Risk

Market risk is the risk that changes in market prices, such as foreign exchange rates, commodity prices, and interest rates will affect the Company’s net earnings. The objective of market risk management is to manage and control market risk exposures within acceptable limits, while maximizing returns. The Company utilizes financial derivatives to manage certain market risks. All such transactions are conducted in accordance with the risk management policy that has been approved by the Board of Directors.

(i) Foreign Currency Exchange Risk

Foreign currency exchange rate risk is the risk that the fair value of financial instruments or future cash flows will fluctuate as a result of changes in foreign exchange rates. Although substantially all of the Company’s oil and natural gas sales are denominated in Canadian dollars, the underlying market prices in Canada for oil and natural gas are impacted by changes in the exchange rate between the Canadian and United States dollars. Given that changes in exchange rate have an indirect influence, the impact of changing exchange rates cannot be accurately quantified. The Company had no forward exchange rate contracts in place as at or during the year ended December 31, 2017 and 2016.

The Company was exposed to the following foreign currency risk at December 31:

	2017		2016
Expressed in foreign currencies	CND$		CND$
Cash and cash equivalents	30		1
Accounts receivable	228		282
Accounts payable and accrued liabilities	(213	)	(312	)
Balance sheet exposure	45		(29	)

The following foreign exchange rates applied for the year ended and as at December 31:

	2017	2016
December 31, reporting date rate	1.2545	1.3427
YTD average USD to CAD	1.2986	1.3253

The Company has performed a sensitivity analysis on its foreign currency denominated financial instruments. Based on the Company’s foreign currency exposure noted above and assuming that all other variables remain constant, a 10% appreciation of the US dollar against the Canadian dollar would result in the decrease of net loss of $5,000 at December 31, 2017 (2016 – increase of net loss of $3,000). For a 10% depreciation of the above foreign currencies against the Canadian dollar, assuming all other variables remain constant, there would be an equal and opposite impact on net loss.

F-35

DXI ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31, 2017 and 2016

(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)

NOTE 20 – FINANCIAL INSTRUMENTS AND CAPITAL MANAGEMENT (continued)

(c) Market Risk (continued)

(ii) Interest Rate Risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. At December 31, 2017, the Company was exposed to interest rate fluctuations on the loans from related parties which bore a floating rate of interest. Assuming all other variables remain constant, an increase or decrease of 1% in market interest rate at December 31, 2017 would have increased or decreased net loss by $65,000. The Company had no interest rate swap contracts in place at or during the year ended December 31, 2017 and 2016.

(iii) Commodity Price Risk

Revenues and consequently cash flows fluctuate with commodity prices and the US/Canadian dollar exchange rate. Commodity prices are determined on a global basis and circumstances that occur in various parts of the world are outside of the control of the Company. The Company may protect itself from fluctuations in prices by using the financial derivative sales contracts. The Company may enter into commodity price contracts to manage the risks associated with price volatility and thereby protect its cash flows used to fund its capital program. Assuming all other variables remain constant, an increase or decrease of oil price of $1 per bbl and gas price of $0.01 per mcf at December 31, 2017 would have decreased or increased net loss by $34,000. The Company had no commodity contracts in place at December 31, 2017.

(d) Capital Management Strategy

The Company’s policy on capital management is to maintain a prudent capital structure so as to maintain financial flexibility, preserve access to capital markets, maintain investor, creditor and market confidence, and to allow the Company to fund future developments. The Company considers its capital structure to include share capital, cash and cash equivalents, and working capital. In order to maintain or adjust capital structure, the Company may from time to time issue shares or enter into debt agreements and adjust its capital spending to manage current and projected operating cash flows and debt levels.

The Company’s share capital is not subject to any external restrictions. The Company has not paid or declared any dividends, nor are any contemplated in the foreseeable future. There have been no changes to the Company’s capital management strategy during the year ended December 31, 2017.

F-36

SUPPLEMENTARY OIL AND GAS RESERVE ESTIMATION AND DISCLOSURES – ASC 932 (UNAUDITED)

Select supplementary oil and gas reserve estimation and disclosure are provided in accordance with U.S. disclosure requirements. The standards of the SEC require that proved reserves be estimated using existing economic conditions (constant pricing). Based on this methodology, the Company’s results have been calculated utilizing the 12-month average price for each of the years presented within this supplementary disclosure.

The Company’s 2017, 2016 and 2015 financial results were prepared in accordance with IFRS.

The Company reports in Canadian currency and therefore the Reserves Data pertaining to the Company’s reserves in the United States set forth in the tables below has been converted to Canadian dollars at the prevailing conversion rate at December 31, 2017. The conversion rate used per Bank of Canada is 1.2545.

(a) Net proved oil and gas reserves

As at December 31, 2017, the Company’s oil and gas reserves are located in both Canada and the United States.

GLJ Petroleum Consultants (“GLJ”) of Calgary, Alberta, independent petroleum engineering consultants based in Calgary, Alberta were retained by the Company to evaluate the Canadian properties of the Company. Their report, titled “Reserves Assessment and Evaluation of Oil and Gas Properties, Dejour Energy (Alberta) Ltd.”, is dated February 27, 2018 and has an effective date of December 31, 2017.

Gustavson Associates (“Gustavson”), an independent petroleum engineering consultants based in Denver, Colorado were retained by the Company to evaluate the US properties of the Company. Their report, titled “Reserve Estimate and Financial Forecast as to Dejour’s Interests in the Kokopelli Field Area, Garfield County, Colorado” is dated March 20, 2018 and has an effective date of January 1, 2018.

In accordance with the US Securities and Exchange Commission’s (“SEC”) definitions and guidelines, GLJ and Gustavson, have used constant prices and costs in estimating the reserves and future net cash flows contained in their reports. 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.

The tables in this section set forth oil and gas information prepared by the Company in accordance with U.S. disclosure standards, including Accounting Standards Codification 932 (“ASC 932”). Reserves have been estimated in accordance with the US Securities and Exchange Commission’s (“SEC”) definitions and guidelines. The changes in our net proved reserve quantities are outlined below.

Net reserves are DXI Energy royalty and working interest remaining reserves, less all Crown, freehold, and overriding royalties and interests that are not owned by DXI Energy.

Proved reserves are those estimated quantities of crude oil, natural gas and natural gas liquids that can be estimated with a high degree of certainty to be economically recoverable under existing economic and operating conditions. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

Proved 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. Developed reserves may be subdivided into producing and non-producing.

Proved undeveloped reserves are those reserves that are 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.

The Company cautions users of this information as the process of estimating crude oil and natural gas reserves is subject to a level of uncertainty. The reserves are based on economic and operating conditions; therefore, changes can be made to future assessments as a result of a number of factors, which can include new technology, changing economic conditions and development activity.

(a) CONSTANT PRICES AND COSTS - YEAR ENDED DECEMBER 31, 2017

Net Proved Developed and
Proved Undeveloped Reserves
	Canada								United States								Total
	Light and		Natural Gas				Barrels of Oil				Natural Gas				Barrels of Oil		Light and				Natural Gas				Barrels of Oil
	Medium Oil		Liquids		Natural Gas		Equivalent		Condensate		Liquids		Natural Gas		Equivalent		Medium Oil		Condensate		Liquids		Natural Gas		Equivalent
	(Mbbl)		(Mbbl)		(MMcf)		(Mboe)		(Mbbl)		(Mbbl)		(MMcf)		(Mboe)		(Mbbl)		(Mbbl)		(Mbbl)		(MMcf)		(Mboe)
December 31, 2016	47		1		500		131		7		40		917		200		47		7		41		1,417		331
Extensions and Improved Recovery	-		-		-		-		-		-		-		-		-		-		-		-		-
Technical Revisions	34		-		(30	)	29		1		1		93		17		34		1		1		63		46
Acquisitions	-		-		-		-		-		-		-		-		-		-		-		-		-
Dispositions	-		-		-		-		-		-		-		-		-		-		-		-		-
Economic Factors	-		-		-		-		236		1,083		26,767		5,780		-		236		1,083		26,768		5,780
Production	(22	)	(1	)	(254	)	(65	)	(1	)	(7	)	(170	)	(36	)	(22	)	(1	)	(8	)	(424	)	(101	)
December 31, 2017	59		-		216		95		243		1,117		27,607		5,961		59		243		1,117		27,824		6,056
Developed Producing	59		-		154		85		6		31		774		166		59		6		31		928		251
Developed Non-producing	-		-		63		10		2		8		203		44		-		2		8		266		54
Undeveloped	-		-		-		-		235		1,078		26,630		5,751		-		235		1,078		26,630		5,751
Total	59		-		217		95		243		1,117		27,607		5,961		59		243		1,117		27,824		6,056

(1)	Canada – Increase in Total Proved Oil Reserves of 12 Mbbls:
	During the year ended December 31, 2017, the slight increase in light and medium oil reserves was primarily due to lower operating expenses as this helps the economic limit lending to the positive technical revisions.
(2)	United States – Increase in Total Proved Oil and Natural Gas Reserves of 5,761 Mboe:
	During the year ended December 31, 2017, the increase in total proved reserves was mainly a result of a higher 12-month average trailing oil and natural gas prices.

CONSTANT PRICES AND COSTS - YEAR ENDED DECEMBER 31, 2016

(1)	Canada – Decrease in Total Proved Oil Reserves of 82 Mbbls and Increase in Total Proved Natural Gas Reserves of 74 MMcf:
	During the year ended December 31, 2016, the reduction in light and medium oil reserves was primarily a result of a lower 12-month average trailing oil and natural gas prices. The increase in natural gas reserves was due to the slower-than-expected decline in reserves for one of the natural gas wells at Woodrush.
(2)	United States – Decrease in Total Proved Natural Gas Reserves of 565 MMcf:
	During the year ended December 31, 2016, the reduction in natural gas reserves was mainly attributed to the higher than normal decline in production and a result of a lower 12-month average trailing oil and natural gas prices.

(b) Capitalized Costs

	December 31,		December 31,		December 31,
(CA$ thousands)	2017		2016		2015
			$		$
Canada
Proved oil and gas properties	34,127		33,628		33,377
Unproved oil and gas properties	356		296		281
Total capital costs	34,483		33,924		33,658
Accumulated depletion and depreciation	(17,283	)	(16,722	)	(15,473	)
Accumulated impairment	(13,590	)	(12,370	)	(11,300	)
Net capitalized costs	3,610		4,832		6,885
United States
Proved oil and gas properties	15,348		16,372		16,650
Unproved oil and gas properties	16,271		17,442		18,980
Total capital costs	31,619		33,814		35,630
Accumulated depletion and depreciation	(1,156	)	(1,714	)	(639	)
Accumulated impairment	(16,919	)	(16,768	)	(16,775	)
Net capitalized costs	13,544		15,332		18,216
Total
Proved oil and gas properties	49,475		50,000		50,027
Unproved oil and gas properties	16,627		17,738		19,261
Total capital costs	66,102		67,738		69,288
Accumulated depletion and depreciation	(18,439	)	(18,436	)	(16,112	)
Accumulated impairment	(30,509	)	(29,138	)	(28,075	)
Net capitalized costs	17,154		20,164		25,101

(c) Costs Incurred

	December 31,	December 31,	December 31,
(CA$ thousands)	2017	2016	2015
	$	$	$
Canada
Property acquisition costs (1)
Proved oil and gas properties	53	39	41
Unproved oil and gas properties	-	-	-
Exploration costs (2)	5	2	3
Development costs (3)	351	265	1,123
Capital Expenditures	409	306	1,167
United States
Property acquisition costs (1)
Proved oil and gas properties	-	4	4
Unproved oil and gas properties	-	-	31
Exploration costs (2)	3	-	72
Development costs (3)	39	220	4,463
Capital Expenditures	42	224	4,570
Total
Property acquisition costs (1)
Proved oil and gas properties	53	43	45
Unproved oil and gas properties	-	-	31
Exploration costs (2)	8	2	75
Development costs (3)	390	485	5,586
Capital Expenditures	451	530	5,737

(1)	Acquisitions are not net of disposition of properties.
(2)	Geological and geophysical capital expenditures and drilling costs for exploraton wells drilled
(3)	Includes equipping and facilities capital expenditures

(d) Results of Operations of Producing Activities

	For the years ended December 31,
(CA$ thousands)	2017		2016		2015
	$		$		$
Canada
Oil and gas sales, net of royalties	1,814		3,190		6,606
Operating costs and capital taxes	(1,395	)	(1,789	)	(2,576	)
Transportation costs	(218	)	(478	)	(681	)
Depletion and depreciation	(561	)	(1,250	)	(2,434	)
Income taxes (1)	-		-		-
Results of operations	(360	)	(327	)	915
United States
Oil and gas sales, net of royalties	666		883		490
Operating costs and capital taxes	(472	)	(704	)	(586	)
Transportation costs	-		-		-
Depletion and depreciation	(223	)	(380	)	(213	)
Income taxes (1)	-		-		-
Results of operations	(29	)	(201	)	(309	)
Total
Oil and gas sales, net of royalties	2,480		4,073		7,096
Operating costs and capital taxes	(1,867	)	(2,493	)	(3,162	)
Transportation costs	(218	)	(478	)	(681	)
Depletion and depreciation	(784	)	(1,630	)	(2,647	)
Income taxes (1)	-		-		-
Results of operations	(389	)	(528	)	606

⁽¹⁾ DXI Energy is currently not taxable.

(e) Standardized Measure of Discounted Future Net Cash Flows and Changes Therein

The standardized measure of discounted future net cash flows is based on estimates made by GLJ and Gustavson of net proved reserves. Future cash inflows are computed based on the average of the first day constant prices in each of the 12 months for the year ended December 31, 2017 and cost assumptions applied against annual future production from proved crude oil and natural gas reserves. Future development and production costs are computed based on the average of the first day constant prices in each of the 12 months for the year ended December 31, 2017 and assume the continuation of existing economic conditions. Future income taxes are calculated by applying statutory income tax rates. The Company is currently not taxable. The standardized measure of discounted future net cash flows is computed using a 10 percent discount factor.

The Company cautions users of this information that the discounted future net cash flows relating to the proved oil and gas reserves are neither an indication of the fair market value of our oil and gas properties, nor of the future net cash flows expected to be generated from such properties. The discounted future cash flows do not include the fair market value of exploratory properties and probable or possible oil and gas reserves, nor is consideration given to the effect of anticipated future changes in crude oil and natural gas prices, development, asset retirement and production costs and possible changes to tax and royalty regulations. The prescribed discount rate of 10 percent is arbitrary and may not appropriately reflect future interest rates.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows relating to our estimated proved reserves as of December 31, 2017 is presented below:

As at December 31, 2017
(CA$ thousands)	Canada		USA		Total
	$		$		$
Future cash from revenues after royalties	3,462		170,360		173,822
Future production, abandon and salvage costs	(3,418	)	(88,944	)	(92,362	)
Future development costs	-		(52,172	)	(52,172	)
Future income taxes	-		(7,360	)	(7,360	)
Future net cash flows	44		21,884		21,928
Less: 10% annual discount factor	190		(19,233	)	(19,043	)
Standardized measure of discounted future net cash flow	234		2,651		2,885

The standardized measure of discounted future net cash flows relating to our estimated proved reserves as of December 31, 2016 is presented below:

(f) Changes in Standardized Measure of Discounted Future Net Cash Flows

The principal sources of changes in the standardized measure of the future net cash flows for the year ended December 31, 2017 are presented below:

For the Year Ended December 31, 2017
(CA$ thousands)	Canada		USA		Total
	$		$		$
Beginning Balance, January 1, 2017	(71	)	733		662
Sales and transfers of oil and gas produced, net of production costs	(200	)	(188	)	(388	)
Net changes in sales and transfer prices, net of production costs and royalties	717		(53	)	664
Extensions, discoveries, and improved recovery, less estimated costs	80		28,259		28,339
Changes in estimated future development costs	-		(51,513	)	(51,513	)
Revisions of quantity estimates and timing of estimated production	-		28,209		28,209
Accretion of discount	(7	)	353		346
Net change in income taxes	-		(6,873	)	(6,873	)
Other	(285	)	3,724		3,439
Ending Balance, December 31, 2017	234		2,651		2,885

The principal sources of changes in the standardized measure of the future net cash flows for the year ended December 31, 2016 are presented below:

For the Year Ended December 31, 2016
(CA$ thousands)	Canada		USA		Total
	$		$		$
Beginning Balance, January 1, 2016	2,499		1,476		3,975
Sales and transfers of oil and gas produced, net of production costs	(923	)	(181	)	(1,104	)
Net changes in sales and transfer prices, net of production costs and royalties	(775	)	(1,164	)	(1,939	)
Extensions, discoveries, and improved recovery, less estimated costs	319		(566	)	(247	)
Changes in estimated future development costs	(32	)	-		(32	)
Development costs incurred	-		308		308
Accretion of discount	250		186		436
Net change in income taxes	-		(366	)	(366	)
Other	(1,409	)	1,040		(369	)
Ending Balance, December 31, 2016	(71	)	733		662

EX-8.1

ORGANIZATIONAL CHART

520 – 999 Canada Place, Vancouver, BC V6C 3E1
Tel: 604.638.5050 Fax: 604.638.5051
www.dxienergy.com

EX-12.1

Exhibit 12.1

CERTIFICATION

I, Robert L. Hodgkinson, certify that:

1.          I have reviewed this annual report on Form 20-F of DXI Energy Inc.;

2.          Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.          Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;

4.          The company’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with International Financial Reporting Standards;

(c) Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and

5.          The company’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting.

Date: April 16, 2018	/s/ Robert L. Hodgkinson
	Robert L. Hodgkinson
	Chairman and Chief Executive Officer
	Principal Executive Officer

80

EX-12.2

Exhibit 12.2

CERTIFICATION

I, David Matheson, certify that:

1.          I have reviewed this annual report on Form 20-F of DXI Energy Inc.;

2.          Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.          Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;

4.          The company’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with International Financial Reporting Standards;

(c) Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and

5.          The company’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting.

Date: April 16, 2018	/s/ David Matheson
	David Matheson
	Chief Financial Officer
	Principal Accounting and Financial Officer

81

EX-13.1

Exhibit 13.1

CERTIFICATION PURSUANT TO

18 U.S.C. §1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of DXI Energy Inc. (the “Company”) on Form 20-F for the fiscal year ended December 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert Hodgkinson, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1)          The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)          The information contained in this Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/Robert Hodgkinson

Robert Hodgkinson

Chief Executive Officer

Principal Executive Officer

April 16, 2018

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request. The foregoing certification is being furnished solely pursuant to 18 U.S.C. §1350 and is not being filed as part of the annual report or as a separate disclosure document.

82

EX-13.2

Exhibit 13.2

CERTIFICATION PURSUANT TO

18 U.S.C. §1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of DXI Energy Inc. (the “Company”) on Form 20-F for the fiscal year ended December 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David Matheson, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1)          The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)          The information contained in this Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ David Matheson

David Matheson

Chief Financial Officer

Principal Accounting and Financial Officer

April 16, 2018

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request. The foregoing certification is being furnished solely pursuant to 18 U.S.C. §1350 and is not being filed as part of the annual report or as a separate disclosure document.

83

EX-15.1

Consent of Independent Registered Chartered Professional Accountants

We hereby consent to (i) the inclusion in DXI Energy Inc.’s Annual Report on Form 20-F for the year ended December 31, 2017; and (ii) the incorporation by reference in DXI Energy Inc.’s Registration Statement on Form F-3 (File No. 333-183587); and (iii) the incorporation by reference in DXI Energy Inc.’s Registration Statements on Form S-8 (Files No. 333-179540 and 333-156772) of our Auditor’s Report dated March 14, 2018 relating to the DXI Energy Inc. Consolidated Financial Statements as at December 31, 2017, and December 31, 2016, and for the years then ended. Our report contains an explanatory paragraph regarding the Company’s ability to continue as a going concern.
 

Calgary, Canada	/s/ BDO Canada LLP
April 17, 2018	INDEPENDENT REGISTERED CHARTERED PROFESSIONAL ACCOUNTANTS

EX-15.2

DXI Energy Inc.

520-999 Canada Place

Vancouver, BC V6C 3E1

Consent of Independent Petroleum Engineers

We hereby consent to the use and reference to our name and reports evaluating a portion of DXI Energy Inc.’s petroleum and natural gas reserves as of December 31, 2017, and the information derived from our reports, as described or incorporated by reference in: ( i)DXI Energy Inc.’s Annual Report on Form 20-F for the year ended December 31, 2017, (ii)DXI Energy Inc.’s Registration Statement on Form F-3 ( File No.333-183587), and ( iii)DXI Energy Inc.’s Registration Statements on Form S-8 (Files No. 333-179540 and 333-156772), filed with the United States Securities and Exchange Commission.

Yours truly,

GLJ PETROLEUM CONSULTANTS LTD.

Chad P. Lemke, P. Eng.

Vice President

Dated: April 17, 2018

Calgary, Alberta

CANADA

EX-15.3

April 17, 2018

DXI Energy Inc.

520-999 Canada Place

Vancouver, BC

V6C 3E1

Consent of Independent Petroleum Engineers

We hereby consent to the use and reference to our name and reports evaluating a portion of DXI Energy Inc.’s petroleum and natural gas reserves as of December 31, 2017, and the information derived from our reports, as described or incorporated by reference in: (i) DXI Energy Inc.’s Annual Report on Form 20-F for the year ended December 31, 2017, (ii) DXI Energy Inc.’s Registration Statement on Form F-3 (File No. 333-183587), and (iii) DXI Energy Inc.’s Registration Statements on Form S-8 (Files No. 333-179540 and 333-156772), filed with the United States Securities and Exchange Commission.

Sincerely,

GUSTAVSON ASSOCIATES, LLC

Letha C. Lencioni, P.E.

Vice-President, Petroleum Engineering

EX-99.1

EX-99.2

March 20, 2018

Mr. David Matheson

Chief Financial Officer, CFO

Dejour Energy (USA) Corp.

520, 999 Canada Place

Vancouver, BC

V6C 3E1

Canada

Subject: Reserve Estimate and Financial Forecast as to Dejour’s Interests in the Kokopelli Field Area, Garfield County, Colorado.

Dear David:

As you requested, Gustavson Associates has completed reserves and economics as to Dejour Energy’s interests in future oil and gas production associated with the Kokopelli Field Area located in Garfield County. Reserves have been estimated based on analysis of analogous well production data. Estimates and projections have been made as of January 1, 2018. Reserves have been estimated in accordance with the US Securities and Exchange Commission’s (SEC) definitions and guidelines, and the report was prepared for the purpose of inclusion as an exhibit in a filing made with the SEC.

In general, Proved Developed Producing (PDP) reserves were assigned to 11 producing wells (shown in Table 2). Proved Developed Non-Producing (PDNP) reserves have been assigned to the Federal 14/15-7-21 well. There are plans to recomplete this well, which is currently producing out of the Mancos shale, in the Williams Fork member of the Mesaverde formation in July 2018. Proved Undeveloped (PUD) reserves have been assigned to 131 well locations. Gustavson is of the opinion that no current regulations, and no anticipated changes to regulations, would inhibit the ability of Dejour to recover the estimated reserves in the manner projected herein. It is our understanding that the reserves estimated herein represent all of Dejour’s US reserves.

The estimated net reserves volumes and associated net cash flow estimates are summarized in Table 1 below.

5757 Central Ave. Suite D Boulder, Co. 80301 USA 1-303-443-2209 FAX 1-303-443-3156 http://www.gustavson.com

Mr. David Matheson

March 20, 2018

Page 2

Table 1 Summary of Net Reserves and Projected Before Tax Cash Flow

Reserves Category	Net Gas Reserves, MMcf	Net Oil Reserves (MBO)	Net NGL Reserves (MBO)	Before Tax Net Present Value, thousands of US$ Discounted at
				0%	10%
Proved Developed Producing	774.3	5.7	31.3	$1,435	$954
Proved Developed Non-Producing	203.3	1.8	8.2	$352	$195
Proved Undeveloped	26,629.6	235.0	1,077.6	$21,525	$1,463
Total Proved	27,607.2	242.5	1,117.1	$23,312	$2,612

The portion of the Company’s total reserves represented by the reserves included in this report is shown below.

LocationofReserves Country	Area	Gas (MMCF)	Condensate (MBBL)	NGL (MBBL)	OilEquivalent (MBOE)	Proportionof Oil Equiv. Reserves
UnitedStates	Colorado	27,607.20	242.5	1117.1	5,960.80	98%
TotalCompany					6,055.80	100%

Gustavson Associates has performed an evaluation of the reserves associated with both developed and undeveloped locations located in the Kokopelli Field Project Area, Garfield County, Colorado. Proved Developed Producing (PDP) Reserves have been assigned to 11 wells (shown in Table 2). The first four wells began producing in July and August of 2013 and next eight wells began producing in September 2015. All these wells are completed in the Williams Fork member of the Mesaverde formation except for one of the new wells, the Federal 14/15-7-21, which is completed in the Mancos shale.

Proved Developed Non-Producing (PDNP) reserves were assigned to the Federal 14-15-7-21 well. There are plans to recomplete this well, which is currently producing out of the Mancos shale, in the Williams Fork member of the Mesaverde formation in July 2018.

The PDP locations are displayed in Figure 1 and Figure 2. The property has additional upside which has not been included in this report. Under current economic conditions, drilling of offset locations in the Williams Fork or Mancos formation does not generate positive economics; therefore, no PUD reserves have been assigned.

Mr. David Matheson

March 20, 2018

Page 3

Table 2 Summary of PDP Wells

Well Name	Working Interest	Revenue Interest	Producing Formation
1. Federal 6/7-16-21	5.5573%	4.4458%	Williams Fork
2. Federal 6/7-15-21	7.778%	6.6624%	Williams Fork
3. Federal 6/7-14-21	7.778%	6.6624%	Williams Fork
4. Federal 6/7-13-21	7.778%	6.6624%	Williams Fork
5. Federal 14/15-1-21	25.00%	20.00%	Williams Fork
6. Federal 14/15-2-21	25.00%	20.00%	Williams Fork
7. Federal 14/15-3-21	25.00%	20.00%	Williams Fork
8. Federal 14/15-4-21	25.00%	20.00%	Williams Fork
9. Federal 14/15-5-21	25.00%	20.00%	Williams Fork
10. Federal 14/15-6-21	25.00%	20.00%	Williams Fork
11. Federal 14/15-7-21	25.00%	20.00%	Mancos
12. Federal 14/15-8-21	25.00%	20.00%	Williams Fork

Figure 1 Map of Dejour Williams Fork Wells

Mr. David Matheson

March 20, 2018

Page 4

Figure 2 Map of Dejour Mancos PDP Location

Oil and Gas Pricing

In order to determine the flat pricing in accordance with SEC guidelines, the Dejour’s revenue statements were analyzed. For all wells, a differential was calculated based on the price that Dejour was paid versus the West Texas Intermediate (WTI) and Henry Hub (HH) spot prices averaged for that given month. These differentials were then applied to the WTI and HH spot prices for the first day of each month in 2017 in order to estimate prices for Dejour’s products on the first day of the month, per SEC guidelines. These values were averaged and applied in the cash flows presented herein.

For Williams Fork wells, the wellhead gas price was estimated at 103.6% of NYMEX Henry Hub gas and the NGL price was found to be a factor of 11.76 times the Henry Hub gas price. The Williams Fork wellhead condensate prices were determined to be 12.4% lower than WTI prices. The utilized flat hydrocarbon pricings for Williams Fork can be found in Table 3.

Mr. David Matheson

March 20, 2018

Page 5

Table 3 Flat Pricing for Williams Fork Wells

Flat Pricing for Effective Data January 1, 2018
Local Price Differentials Included
2017 Avg. WTI	2017 Avg. HH	Wellhead Oil	Wellhead Gas	NGL
$/B	$/mcf	$/B	$/mcf	$/B
51.34	2.99	44.95	3.10	35.18

Expenses

Operating costs are expected to be $2,800 per well per month. This is based on information provided by the Dejour and is consistent with our experience with similar wells in the area. The drilling and completion costs reflects economies of scale and contractual advantages expected to be gained when a large drilling program is executed. Severance tax is deducted at the rate of 1.04% of revenue. County ad valorem tax was estimated at approximately 3.91% of revenue after discussion with Garfield County personnel. Conservation tax was estimated at 0.072% and the annual property tax was estimated as 0.557% of net revenue. Note that Conservation tax rate and property tax are lumped together with Severance tax and Ad Valorem tax in the economics evaluation, respectively For Williams Fork Wells only, an NGL yield of approximately 38 Bbl/mmcf was applied for both Williams Fork and Mancos wells, based on actual data from late 2017 following changes in gas processing. A condensate/gas ratio of 8.3 Bbl/MMCF was applied based on actual 2017 sales. Contractual gas transportation, gathering, and processing fees of $0.71/MCF were deducted as operating costs for both Williams Fork and Mancos wells. Condensate trucking fee of $1.50/Bbl was also applied to the Williams Fork wells. Abandonment costs of $15,000 per well were estimated. All costs were held flat.

Dejour expects the Federal 14-15-7-21 well, currently producing out of the Mancos shale, to be recompleted in the Williams Fork in July 2018. This operation will cost $500,000 US, which Gustavson finds to be reasonable based on estimates from the client and experience in the area.

Detailed cash flow projections are shown in Tables 4 and 5 below. Note that the NGL volumes shown in these tables represent total NGL sales as expected based on the revenue statements provided by the Client.¹

Limiting Conditions and Disclaimers

The accuracy of any reserve report or resource evaluation is a function of available data and of engineering and geologic interpretation and judgment. While the evaluation presented herein is believed to be reasonable, it should be viewed with the understanding that subsequent reservoir performance or changes in pricing structure, market demand, or other economic parameters may justify its revision. The assumptions, data, methods, and procedures used are appropriate for the
_________________________________

¹ In some previous reports, ethane and heavier NGLs were reported separately. Here they are reported together.

Mr. David Matheson

March 20, 2018

Page 6

purpose served by the report. Gustavson has used all methods and procedures as we considered necessary under the circumstances to prepare the report.

Gustavson Associates, LLC, holds neither direct nor indirect financial interest in the subject property, the company operating the subject acreage, or in any other affiliated companies.

All data and work files utilized in the preparation of this report are available for examination in our offices. Please contact us if we can be of assistance. We appreciate the opportunity to be of service and look forward to further serving Dejour Energy (USA) Corp.

Sincerely,

Letha C. Lencioni, P.E.

GUSTAVSON ASSOCIATES, LLC.

Vice-President, Petroleum Engineering

Registered Professional Engineer, State of Colorado, # 29506

Table 4 Summary Cash Flow Forecast, Proved Developed Producing Reserves

TOTAL PROVED DEVELOPED PRODUCING	DATE	: 02/26/2018
KOKOPELLI FIELD	TIME	: 14:44:39
GARFIELD COUNTY, COLORADO	DBS	: Dejour_YE2017
TO THE INTERESTS OF DEJOUR ENERGY	SETTINGS : Dejour
	SCENARIO: Dejour flat

R E S E R V E S A N D E C O N O M I C S

EFF DATE: 01/2018
PW DATE: 01/2018

--END--	GROSS OIL	GROSS GAS	GROSS NGL	NET OIL	NET GAS	NET NGL	NET OIL	NET GAS	NET NGL	TOTAL
MO-YEAR	PRODUCTION	PRODUCTION	PRODUCTION	PRODUCTION	PRODUCTION	PRODUCTION	REVENUE	REVENUE	REVENUE	REVENUE
-------	---MBBLS---	----MMCF---	---MBBLS---	---MBBLS--	----MMCF--	---MBBLS--	---M$---	---M$---	---M$---	----M$---
12-2018	4.070	580.658	22.223	0.658	92.279	3.728	29.565	286.121	131.128	446.813
12-2019	3.317	467.759	17.903	0.527	73.171	2.956	23.703	226.875	103.984	354.562
12-2020	2.858	399.241	15.280	0.450	61.870	2.500	20.241	191.833	87.930	300.005
12-2021	2.529	350.811	13.427	0.396	53.992	2.181	17.797	167.407	76.738	261.941
12-2022	2.279	314.448	12.035	0.355	48.139	1.945	15.963	149.262	68.424	233.648
12-2023	2.082	285.973	10.945	0.323	43.596	1.762	14.528	135.174	61.968	211.669
12-2024	1.922	262.972	10.065	0.297	39.951	1.614	13.369	123.873	56.789	194.031
12-2025	1.788	243.942	9.337	0.276	36.953	1.493	12.411	114.577	52.529	179.517
12-2026	1.675	227.895	8.722	0.258	34.438	1.392	11.603	106.778	48.954	167.335
12-2027	1.578	214.147	8.196	0.243	32.292	1.305	10.911	100.125	45.906	156.942
12-2028	1.404	191.497	7.329	0.224	29.807	1.205	10.060	92.419	42.372	144.850
12-2029	1.195	164.882	6.311	0.204	27.300	1.103	9.182	84.647	38.807	132.636
12-2030	1.071	148.779	5.694	0.191	25.572	1.033	8.598	79.290	36.351	124.240
12-2031	1.019	141.288	5.408	0.182	24.284	0.981	8.176	75.294	34.520	117.990
12-2032	0.969	134.294	5.140	0.173	23.083	0.933	7.779	71.570	32.813	112.162
S TOT	29.756	4128.585	158.015	4.758	646.726	26.131	213.884	2005.244	919.214	3138.343
AFTER	5.499	750.346	28.719	0.972	127.566	5.156	43.679	395.532	181.363	620.573
TOTAL	35.255	4878.931	186.734	5.729	774.292	31.287	257.563	2400.776	1100.577	3758.916

--END--	NET OIL	NET GAS	NET NGL	SEVERANCE	AD VALOREM	NET OPER	OPERATING	EQUITY	UNDISC NET	DISC NET
MO-YEAR	PRICE	PRICE	PRICE	TAXES	TAXES	EXPENSES	CASH FLOW	INVESTMENT	CASH FLOW	CASH FLOW
-------	---M$---	---M$---	---M$---	-----M$----	-----M$----	----M$----	----M$----	----M$----	-----M$----	-----M$----
12-2018	44.95	3.10	35.18	4.955	19.747	155.838	266.273	3.750	262.523	250.284
12-2019	44.95	3.10	35.18	3.932	15.670	134.435	200.525	0.000	200.525	173.812
12-2020	44.95	3.10	35.18	3.327	13.259	124.261	159.158	0.000	159.158	125.414
12-2021	44.95	3.10	35.18	2.905	11.576	117.167	130.293	0.000	130.293	93.335
12-2022	44.95	3.10	35.18	2.591	10.326	111.897	108.834	0.000	108.834	70.876
12-2023	44.95	3.10	35.18	2.347	9.355	107.805	92.162	0.000	92.162	54.563
12-2024	44.95	3.10	35.18	2.152	8.575	104.522	78.782	0.000	78.782	42.401
12-2025	44.95	3.10	35.18	1.991	7.934	101.821	67.772	0.000	67.772	33.159
12-2026	44.95	3.10	35.18	1.856	7.395	99.555	58.529	0.000	58.529	26.034
12-2027	44.95	3.10	35.18	1.740	6.936	97.622	50.643	0.000	50.643	20.478
12-2028	44.95	3.10	35.18	1.606	6.402	92.985	43.858	2.333	41.524	15.260
12-2029	44.95	3.10	35.18	1.471	5.862	87.270	38.033	0.834	37.200	12.434
12-2030	44.95	3.10	35.18	1.378	5.491	84.467	32.904	0.000	32.904	9.996
12-2031	44.95	3.10	35.18	1.309	5.215	83.306	28.161	0.000	28.161	7.778
12-2032	44.95	3.10	35.18	1.244	4.957	82.224	23.738	0.000	23.738	5.960
S TOT	44.95	3.10	35.18	34.804	138.697	1585.175	1379.666	6.917	1372.749	941.783
AFTER	44.95	3.10	35.18	6.882	27.426	500.473	85.793	23.667	62.126	12.144
TOTAL	44.95	3.10	35.18	41.686	166.123	2085.648	1465.458	30.584	1434.875	953.927

	OIL	GAS			P.W. %	P.W., M$
	---------	---------			------	--------
GROSS WELLS	0.0	12.0	LIFE, YRS.	28.25	5.00	1143.235
GROSS ULT., MB & MMF	56.424	8875.085	DISCOUNT %	10.00	9.00	986.127
GROSS CUM., MB & MMF	21.169	3996.155	UNDISCOUNTED PAYOUT, YRS.	0.01	10.00	953.927
GROSS RES., MB & MMF	35.255	4878.931	DISCOUNTED PAYOUT, YRS.	0.01	15.00	822.860
NET RES., MB & MMF	5.729	774.292	UNDISCOUNTED NET/INVEST.	47.92	20.00	727.243
NET REVENUE, M$	257.563	2400.776	DISCOUNTED NET/INVEST.	118.12	25.00	654.511
INITIAL PRICE, $	44.955	3.101	RATE-OF-RETURN, PCT.	90.00	35.00	551.083
INITIAL N.I., PCT.	14.598	15.106	INITIAL W.I., PCT.	21.060	50.00	453.381
					70.00	374.330
					90.00	323.649

Table 5 Summary Cash Flow Forecast, Proved Developed Non-Producing Reserves

TOTAL PROVED DEVELOPED NON-PRODUCING	DATE	: 02/26/2018
KOKOPELLI FIELD	TIME	: 14:44:40
GARFIELD COUNTY, COLORADO	DBS	: Dejour_YE2017
TO THE INTERESTS OF DEJOUR ENERGY	SETTINGS : Dejour
	SCENARIO : Dejour flat

R E S E R V E S A N D E C O N O M I C S

EFF DATE: 01/2018
PW DATE: 01/2018

--END--	GROSS OIL	GROSS GAS	GROSS NGL	NET OIL	NET GAS	NET NGL	NET OIL	NET GAS	NET NGL	TOTAL
MO-YEAR	PRODUCTION	PRODUCTION	PRODUCTION	PRODUCTION	PRODUCTION	PRODUCTION	REVENUE	REVENUE	REVENUE	REVENUE
-------	---MBBLS---	----MMCF---	---MBBLS---	---MBBLS--	----MMCF--	---MBBLS--	---M$---	---M$---	---M$---	----M$---
12-2018	1.215	145.516	5.570	0.243	27.529	1.114	10.922	85.356	39.187	135.465
12-2019	1.104	132.275	5.063	0.221	25.024	1.013	9.928	77.589	35.621	123.138
12-2020	0.688	82.412	3.155	0.138	15.591	0.631	6.186	48.341	22.193	76.720
12-2021	0.521	62.441	2.390	0.104	11.813	0.478	4.687	36.626	16.815	58.128
12-2022	0.427	51.202	1.960	0.085	9.686	0.392	3.843	30.034	13.788	47.665
12-2023	0.366	43.857	1.679	0.073	8.297	0.336	3.292	25.726	11.811	40.828
12-2024	0.322	38.625	1.478	0.064	7.307	0.296	2.899	22.656	10.401	35.957
12-2025	0.289	34.679	1.327	0.058	6.561	0.265	2.603	20.342	9.339	32.283
12-2026	0.264	31.581	1.209	0.053	5.974	0.242	2.370	18.524	8.505	29.399
12-2027	0.243	29.074	1.113	0.049	5.500	0.223	2.182	17.054	7.829	27.066
12-2028	0.225	26.997	1.033	0.045	5.107	0.207	2.026	15.836	7.270	25.132
12-2029	0.211	25.244	0.966	0.042	4.776	0.193	1.895	14.808	6.798	23.501
12-2030	0.198	23.742	0.909	0.040	4.492	0.182	1.782	13.927	6.394	22.102
12-2031	0.187	22.438	0.859	0.037	4.245	0.172	1.684	13.162	6.043	20.888
12-2032	0.179	21.413	0.820	0.036	4.051	0.164	1.607	12.560	5.766	19.934
S TOT	6.440	771.497	29.531	1.288	145.952	5.906	57.906	452.539	207.760	718.205
AFTER	2.530	303.018	11.599	0.506	57.325	2.320	22.744	177.742	81.601	282.087
TOTAL	8.970	1074.515	41.129	1.794	203.277	8.226	80.650	630.282	289.361	1000.292

--END--	NET OIL	NET GAS	NET NGL	SEVERANCE	AD VALOREM	NET OPER	OPERATING	EQUITY	UNDISC NET	DISC NET
MO-YEAR	PRICE	PRICE	PRICE	TAXES	TAXES	EXPENSES	CASH FLOW	INVESTMENT	CASH FLOW	CASH FLOW
-------	---M$---	---M$---	---M$---	-----M$----	-----M$----	----M$----	----M$----	----M$----	-----M$----	-----M$----
12-2018	44.95	3.10	35.18	1.502	5.987	29.087	98.888	125.000	-26.112	-26.805
12-2019	44.95	3.10	35.18	1.366	5.442	31.023	85.308	0.000	85.308	73.943
12-2020	44.95	3.10	35.18	0.851	3.391	22.495	49.983	0.000	49.983	39.386
12-2021	44.95	3.10	35.18	0.645	2.569	19.079	35.835	0.000	35.835	25.671
12-2022	44.95	3.10	35.18	0.529	2.107	17.157	27.873	0.000	27.873	18.152
12-2023	44.95	3.10	35.18	0.453	1.804	15.901	22.670	0.000	22.670	13.421
12-2024	44.95	3.10	35.18	0.399	1.589	15.006	18.963	0.000	18.963	10.206
12-2025	44.95	3.10	35.18	0.358	1.427	14.331	16.168	0.000	16.168	7.910
12-2026	44.95	3.10	35.18	0.326	1.299	13.801	13.973	0.000	13.973	6.215
12-2027	44.95	3.10	35.18	0.300	1.196	13.372	12.197	0.000	12.197	4.932
12-2028	44.95	3.10	35.18	0.279	1.111	13.017	10.726	0.000	10.726	3.943
12-2029	44.95	3.10	35.18	0.261	1.039	12.718	9.484	0.000	9.484	3.169
12-2030	44.95	3.10	35.18	0.245	0.977	12.461	8.420	0.000	8.420	2.558
12-2031	44.95	3.10	35.18	0.232	0.923	12.238	7.496	0.000	7.496	2.070
12-2032	44.95	3.10	35.18	0.221	0.881	12.062	6.769	0.000	6.769	1.700
S TOT	44.95	3.10	35.18	7.965	31.741	253.747	424.753	125.000	299.753	186.471
AFTER	44.95	3.10	35.18	3.128	12.467	210.724	55.767	3.750	52.017	8.005
TOTAL	44.95	3.10	35.18	11.093	44.207	464.472	480.520	128.750	351.770	194.477

	OIL	GAS			P.W. %	P.W., M$
	---------	---------			------	--------
GROSS WELLS	0.0	1.0	LIFE, YRS.	33.92	5.00	252.271
GROSS ULT., MB & MMF	8.970	1074.515	DISCOUNT %	10.00	9.00	203.994
GROSS CUM., MB & MMF	0.000	0.000	UNDISCOUNTED PAYOUT, YRS.	1.31	10.00	194.477
GROSS RES., MB & MMF	8.970	1074.515	DISCOUNTED PAYOUT, YRS.	1.36	15.00	156.785
NET RES., MB & MMF	1.794	203.277	UNDISCOUNTED NET/INVEST.	3.73	20.00	130.079
NET REVENUE, M$	80.650	630.281	DISCOUNTED NET/INVEST.	2.60	25.00	110.024
INITIAL PRICE, $	44.955	3.101	RATE-OF-RETURN, PCT.	90.00	35.00	81.666
INITIAL N.I., PCT.	20.000	20.000	INITIAL W.I., PCT.	25.000	50.00	54.932
					70.00	33.462
					90.00	19.976

Table 6 Summary Cash Flow Forecast, Proved Undeveloped Reserves

TOTAL PROVED UNDEVELOPED	DATE	: 02/26/2018
KOKOPELLI FIELD	TIME	: 14:45:54
GARFIELD COUNTY, COLORADO	DBS	: Dejour_YE2017
TO THE INTERESTS OF DEJOUR ENERGY	SETTINGS : Dejour
	SCENARIO : Dejour flat

R E S E R V E S A N D E C O N O M I C S

EFF DATE: 01/2018
PW DATE: 01/2018

--END--	GROSS OIL	GROSS GAS	GROSS NGL	NET OIL	NET GAS	NET NGL	NET OIL	NET GAS	NET NGL	TOTAL
MO-YEAR	PRODUCTION	PRODUCTION	PRODUCTION	PRODUCTION	PRODUCTION	PRODUCTION	REVENUE	REVENUE	REVENUE	REVENUE
-------	---MBBLS---	----MMCF---	---MBBLS---	---MBBLS--	----MMCF--	---MBBLS--	---M$---	---M$---	---M$---	----M$---
12-2018	50.817	6087.375	233.007	10.163	1151.609	46.601	456.898	3570.691	1639.297	5666.889
12-2019	129.523	15515.408	593.885	25.905	2935.204	118.777	1164.536	9100.924	4178.219	14443.682
12-2020	138.621	16605.336	635.604	27.724	3141.395	127.121	1246.342	9740.243	4471.729	15458.315
12-2021	88.459	10596.429	405.600	17.692	2004.630	81.120	795.332	6215.578	2853.560	9864.468
12-2022	66.484	7964.086	304.842	13.297	1506.646	60.968	597.758	4671.517	2144.686	7413.961
12-2023	54.602	6540.689	250.359	10.920	1237.367	50.072	490.923	3836.593	1761.373	6088.895
12-2024	46.888	5616.728	214.992	9.378	1062.572	42.998	421.573	3294.623	1512.554	5228.753
12-2025	41.392	4958.282	189.789	8.278	938.008	37.958	372.153	2908.397	1335.239	4615.788
12-2026	37.238	4460.725	170.744	7.448	843.880	34.149	334.808	2616.544	1201.249	4152.599
12-2027	33.969	4069.116	155.754	6.794	769.795	31.151	305.415	2386.835	1095.791	3788.041
12-2028	31.317	3751.468	143.595	6.263	709.703	28.719	281.573	2200.510	1010.251	3492.336
12-2029	29.116	3487.753	133.501	5.823	659.813	26.700	261.779	2045.823	939.233	3246.834
12-2030	27.254	3264.718	124.964	5.451	617.620	24.993	245.039	1914.996	879.172	3039.208
12-2031	25.655	3073.216	117.634	5.131	581.391	23.527	230.666	1802.668	827.601	2860.933
12-2032	24.307	2911.698	111.451	4.861	550.835	22.290	218.543	1707.924	784.105	2710.570
S TOT	825.642	98903.031	3785.721	165.128	18710.469	757.144	7423.338	58013.863	26634.059	92071.273
AFTER	349.450	41860.371	1602.294	69.890	7919.147	320.459	3141.904	24554.176	11272.777	38968.863
TOTAL	1175.093	140763.406	5388.015	235.019	26629.615	1077.603	10565.243	82568.039	37906.836	131040.133

--END--	NET OIL	NET GAS	NET NGL	SEVERANCE	AD VALOREM	NET OPER	OPERATING	EQUITY	UNDISC NET	DISC NET
MO-YEAR	PRICE	PRICE	PRICE	TAXES	TAXES	EXPENSES	CASH FLOW	INVESTMENT	CASH FLOW	CASH FLOW
-------	---M$---	---M$---	---M$---	-----M$----	-----M$----	----M$----	----M$----	----M$----	-----M$----	-----M$----
12-2018	44.95	3.10	35.18	62.846	250.444	1210.510	4143.088	19687.500	-15544.414	-14790.343
12-2019	44.95	3.10	35.18	160.180	637.503	3340.264	10305.725	15625.000	-5319.271	-4669.978
12-2020	44.95	3.10	35.18	171.433	682.526	3892.769	10711.575	5625.000	5086.575	3846.666
12-2021	44.95	3.10	35.18	109.397	435.542	2912.680	6406.850	0.000	6406.850	4589.550
12-2022	44.95	3.10	35.18	82.221	327.340	2462.481	4541.923	0.000	4541.923	2957.829
12-2023	44.95	3.10	35.18	67.526	268.835	2219.041	3533.489	0.000	3533.489	2091.915
12-2024	44.95	3.10	35.18	57.987	230.858	2061.015	2878.888	0.000	2878.888	1549.432
12-2025	44.95	3.10	35.18	51.189	203.795	1948.404	2412.400	0.000	2412.400	1180.333
12-2026	44.95	3.10	35.18	46.052	183.345	1863.308	2059.895	0.000	2059.895	916.236
12-2027	44.95	3.10	35.18	42.009	167.249	1796.332	1782.451	0.000	1782.451	720.754
12-2028	44.95	3.10	35.18	38.730	154.193	1742.005	1557.406	0.000	1557.406	572.504
12-2029	44.95	3.10	35.18	36.007	143.354	1696.902	1370.571	0.000	1370.571	458.021
12-2030	44.95	3.10	35.18	33.705	134.187	1658.758	1212.558	0.000	1212.558	368.378
12-2031	44.95	3.10	35.18	31.728	126.316	1626.006	1076.885	0.000	1076.885	297.418
12-2032	44.95	3.10	35.18	30.060	119.677	1598.381	962.452	0.000	962.452	241.649
S TOT	44.95	3.10	35.18	1021.070	4065.163	32028.859	54956.160	40937.500	14018.660	330.366
AFTER	44.95	3.10	35.18	432.165	1720.535	28818.686	7997.475	491.250	7506.225	1132.351
TOTAL	44.95	3.10	35.18	1453.235	5785.698	60847.543	62953.637	41428.754	21524.885	1462.716

	OIL	GAS			P.W. %	P.W., M$
	---------	---------			------	--------
GROSS WELLS	0.0	131.0	LIFE, YRS.	35.83	5.00	8504.717
GROSS ULT., MB & MMF	1175.093	140763.406	DISCOUNT %	10.00	9.00	2583.066
GROSS CUM., MB & MMF	0.000	0.000	UNDISCOUNTED PAYOUT, YRS.	6.45	10.00	1462.713
GROSS RES., MB & MMF	1175.093	140763.406	DISCOUNTED PAYOUT, YRS.	13.70	15.00	-2764.967
NET RES., MB & MMF	235.019	26629.615	UNDISCOUNTED NET/INVEST.	1.52	20.00	-5495.125
NET REVENUE, M$	10565.244	82568.055	DISCOUNTED NET/INVEST.	1.04	25.00	-7347.006
INITIAL PRICE, $	44.955	3.101	RATE-OF-RETURN, PCT.	11.73	35.00	-9573.115
INITIAL N.I., PCT.	20.000	20.000	INITIAL W.I., PCT.	25.000	50.00	-11089.390
					70.00	-11719.011
					90.00	-11737.975

XML

Document and Entity Information - shares	12 Months Ended
	Dec. 31, 2017	Apr. 16, 2018
Statement [Line Items]
Document Type	20-F
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Trading Symbol	dxi
Entity Registrant Name	DXI Energy Inc.
Entity Central Index Key	0001323838
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		103,606,088
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well Known Seasoned Issuer	No
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY

XML

CONSOLIDATED BALANCE SHEETS - CAD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current
Cash and cash equivalents	$ 1,010	$ 141
Accounts receivable	388	672
Prepaids and deposits	29	19
Current Assets	1,427	832
Non-current
Deposits	212	246
Exploration and evaluation assets	8	970
Property and equipment	17,162	19,212
Total Assets	18,809	21,260
Current
Accounts payable and accrued liabilities	1,291	2,165
Loans from related parties	1,458	2,363
Flow-through shares liability	93	0
Derivative liability	0	153
Financial contract liability	6,752	7,226
Current Liabilities	9,594	11,907
Non-current
Loans from related parties	3,150	4,031
Decommissioning liability	3,971	3,776
Total liabilities	16,715	19,714
SHAREHOLDERS' EQUITY
Share capital	101,715	98,111
Contributed surplus	13,752	10,626
Deficit	(115,845)	(110,636)
Accumulated other comprehensive income	2,472	3,445
Total Shareholders' Equity	2,094	1,546
Total Liabilities and Shareholders' Equity	$ 18,809	$ 21,260

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
REVENUES
Gross revenues	$ 2,816	$ 4,808	$ 8,579
Royalties	(336)	(735)	(1,483)
Total Revenues, net of royalties	2,480	4,073	7,096
EXPENSES
Operating and transportation	2,085	2,971	3,843
Amortization, depletion and impairment losses	2,628	4,493	4,189
General and administrative	1,671	1,571	2,246
Financing expenses	1,039	1,579	1,117
Stock based compensation	8	188	771
Foreign exchange (gain) loss	(486)	(212)	288
Loss on disposal of E&E assets	0	175	0
Loss on disposal of property and equipment	2	0	6
Change in fair value of warrant liability	0	0	(754)
Change in fair value of derivative liability	(153)	(1,073)	(2,245)
Loss on debt extinguishment	918	0	1,398
(Gain) loss on financial contract liability	0	(63)	3,348
Total Expenses	7,712	9,629	14,207
Loss before income taxes and other items	(5,232)	(5,556)	(7,111)
Other income	23	70	3
Loss for the year	(5,209)	(5,486)	(7,108)
Items that may be subsequently reclassified to profit or loss:
Foreign currency translation adjustment	(973)	(673)	2,497
Comprehensive loss	$ (6,182)	$ (6,159)	$ (4,611)
Loss per common share - basic and diluted	$ (0.08)	$ (0.13)	$ (0.19)

XML

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS EQUITY - CAD ($) $ in Thousands	Total	Share Capital [Member]	Contributed Surplus [Member]	Deficit [Member]	Accumulated other comprehensive income (loss) [Member]
Beginning Balance at Dec. 31, 2014	$ 10,385	$ 97,132	$ 9,674	$ (98,042)	$ 1,621
Beginning Balance (Shares) at Dec. 31, 2014	36,480,427
Statement [Line Items]
Issue of shares on exercise of options	$ 23	23
Issue of shares on exercise of options (Shares)	29,898
Contributed surplus reallocated on exercise of options		7	(7)
Stock-based compensation	$ 771		771
Loss	(7,108)			(7,108)
Foreign currency translation adjustment	$ 2,497				2,497
Adjustment due to fractional rounding (Shares)	(372)
Ending Balance at Dec. 31, 2015	$ 6,568	97,162	10,438	(105,150)	4,118
Ending Balance (Shares) at Dec. 31, 2015	36,509,953
Statement [Line Items]
Shares issued via private placements, net of issuance costs	$ 949	949
Shares issued via private placements, net of issuance costs (Shares)	8,298,333
Stock-based compensation	$ 188		188
Loss	(5,486)			(5,486)
Foreign currency translation adjustment	(673)				(673)
Ending Balance at Dec. 31, 2016	$ 1,546	98,111	10,626	(110,636)	3,445
Ending Balance (Shares) at Dec. 31, 2016	44,808,286
Statement [Line Items]
Shares issued via private placements, net of issuance costs	$ 3,718	3,718
Shares issued via private placements, net of issuance costs (Shares)	58,797,802
Flow-through share liability	$ (114)	(114)
Contributed surplus related to value of conversion feature on loans from related parties	3,118		3,118
Stock-based compensation	8		8
Loss	(5,209)			(5,209)
Foreign currency translation adjustment	(973)				(973)
Ending Balance at Dec. 31, 2017	$ 2,094	$ 101,715	$ 13,752	$ (115,845)	$ 2,472
Ending Balance (Shares) at Dec. 31, 2017	103,606,088

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - CAD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES
Loss for the year	$ (5,209)	$ (5,486)	$ (7,108)
Adjustment for items not affecting cash:
Amortization, depletion and impairment losses	2,628	4,493	4,189
Stock based compensation	8	188	771
Non-cash financing expenses	530	961	661
Non-cash foreign exchange on financial contract liability	(474)	(212)	594
Miscellaneous non-cash items	(25)	0	6
Loss on disposal of E&E assets	0	175	0
Change in fair value of warrant liability	0	0	(754)
Change in fair value of derivative liability	(153)	(1,073)	(2,245)
Loss on debt extinguishment	918	0	1,398
(Gain) loss on financial contract liability	0	(63)	3,348
Cash flows from (used in) operations	(1,777)	(1,017)	860
Changes in operating working capital	219	667	204
Total Cash Flows from (used in) Operating Activities	(1,558)	(350)	1,064
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES
Deposits	34	48	2
E&E expenditures	(7)	(2)	(106)
Additions to property and equipment	(449)	(528)	(5,632)
Proceeds from sale of E&E assets	0	84	0
Reclamation expenditures	(3)	(53)	0
Changes in investing working capital	32	178	(2,289)
Total Cash Flows used in Investing Activities	(393)	(273)	(8,025)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES
Repayment of bank credit facility	0	(147)	(1,807)
Advance of loans from related parties	450	350	7,500
Repayment of loans from related parties	0	(300)	0
Shares issued on exercise of warrants and options	0	0	23
Shares issued for cash, net of share issue costs	2,332	884	0
Changes in financing working capital	38	(61)	68
Total Cash Flows from Financing Activities	2,820	726	5,784
CHANGE IN CASH AND CASH EQUIVALENTS	869	103	(1,177)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	141	38	1,215
CASH AND CASH EQUIVALENTS, END OF YEAR	$ 1,010	$ 141	$ 38

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CORPORATE INFORMATION

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

CORPORATE INFORMATION [Text Block]

NOTE 1 – CORPORATE INFORMATION

DXI Energy Inc. (the “Company”) is a public company trading on the Toronto Stock Exchange (“TSX”) under the symbol “DXI” in Canada and the OTCQB (“OTCQB”) under the symbol “DXIEF” in the United States. The Company is in the business of exploring and developing energy properties with a focus on oil and gas in North America. The address of its registered office is 520 – 999 Canada Place, Vancouver, British Columbia.

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Dejour Energy (USA) Corp. (“Dejour USA”), incorporated in Nevada, Dejour Energy (Alberta) Ltd. (“DEAL”), incorporated in Alberta, and 0855524 B.C. Ltd., incorporated in British Columbia. All intercompany transactions are eliminated upon consolidation.

The consolidated financial statements are presented in Canadian dollars, which is also the functional currency of the parent company. These consolidated financial statements were authorized and approved for issuance by the Board of Directors on March 8, 2018.

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BASIS OF PRESENTATION

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

BASIS OF PRESENTATION [Text Block]

NOTE 2 – BASIS OF PRESENTATION

(a) Basis of presentation

The consolidated financial statements (the “financial statements”) are presented under International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) and the International Financial Reporting Interpretations Committee (“IFRIC”). A summary of the Company’s significant accounting policies under IFRS is presented in note 3.

(b) Going concern

The financial statements were prepared on a going concern basis. The going concern basis assumes that the Company will continue in operation for the foreseeable future and will be able to realize its assets and discharge its liabilities and commitments in the normal course of business. The Company has a working capital deficiency of $8.2 million and an accumulated deficit of $115.8 million. Of this amount, $6.8 million is represented by a financial contract liability of Dejour USA, which was due on September 30, 2016. The current status of this instrument is described in note 11 below.

The Company’s ability to continue as a going concern is dependent upon attaining profitable operations and the continued financial support of the non-arm’s length lenders who have provided the Company with sufficient capital to meet capital expenditure commitments and continue exploration and development activities. There is no assurance that these activities will be successful. These material uncertainties cast substantial doubt upon the Company’s ability to continue as a going concern. These consolidated financial statements do not reflect the adjustments to the carrying values of assets and liabilities, the reported revenues and expenses, and the balance sheet classifications used that would be necessary if the going concern assumptions were not appropriate.

(c) Basis of measurement

The consolidated financial statements have been prepared on the historical cost basis except for certain financial liabilities are measured at fair value, as explained in the accounting policies in note 3.

(d) Use of estimates and judgments

The preparation of consolidated financial statements in compliance with IFRS requires management to make certain critical accounting estimates. It also requires management to exercise judgment in applying the Company’s accounting policies. The areas involving a higher degree of judgment or complexity, or areas where assumptions and estimates are significant to the financial statements are disclosed in note 4.

(e) Functional and presentation currency

Subsidiaries measure items using the currency of the primary economic environment in which the entity operates with entities having a functional currency different from the parent company, translated into Canadian dollars.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Text Block]

NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The accounting policies set out below have been applied consistently to all periods presented in these consolidated financial statements and have been applied consistently by the Company’s entities.

(a) Basis of consolidation

The consolidated financial statements include the financial statements of the Company and subsidiaries controlled by the Company. Subsidiaries are fully consolidated from the date of acquisition, being the date on which the Company obtains control, and continue to be consolidated until the date that such control ceases. All intra-group balances, transactions, income and expenses are eliminated in full on consolidation.

The financial statements of the subsidiaries are prepared using the same reporting period as the parent company, using consistent accounting policies.

Exploration, development, and production activities may be conducted jointly with others and accordingly, the Company accounts for the assets, liabilities, revenues and expenses related to its interest in the joint operations from the date that joint control commences until the date that it ceases.

(b) Foreign currency

The financial statements of entities within the consolidated group that have a functional currency different from that of the Company (“foreign operations”) are translated into Canadian dollars as follows: assets and liabilities – at the closing rate as at the balance sheet date, and income and expenses – at the average rate of the period (as this is considered a reasonable approximation to actual rates). All resulting changes are recognized in other comprehensive loss as cumulative translation differences.

When the Company disposes of its entire interests in a foreign operation, or loses control, joint control, or significant influence over a foreign operation, the foreign currency gains or losses accumulated in other comprehensive loss related to the foreign operation are recognized in profit or loss. If an entity disposes of part of an interest in a foreign operation which remains a subsidiary, a proportionate amount of foreign currency gains or losses accumulated in other comprehensive income related to the subsidiary are reallocated between controlling and non-controlling interests.

Transactions in foreign currencies are translated into the functional currency at exchange rates at the date of the transactions. Foreign currency differences arising on translation are recognized in profit or loss. Foreign currency monetary assets and liabilities are translated at the functional currency exchange rate at the balance sheet date. Non- monetary items that are measured at historical cost in a foreign currency are translated using the exchange rates as at the dates of the initial transactions. Non-monetary items measured at fair value in a foreign currency are translated using the exchange rates at the date when the fair value was determined.

Exchange differences recognized in the profit or loss statement of the Company’s entities’ separate financial statements on the translation of monetary items forming part of the Company’s net investment in the foreign operation are reclassified to foreign exchange reserve on consolidation.

(c) Cash and cash equivalents

Cash and cash equivalents consist of cash and highly liquid investments having maturity dates of three months or less from the date of acquisition that are readily convertible to cash.

(d) Resource properties

Exploration and evaluation (“E&E”) costs

Pre-license costs are expensed in the period in which they are incurred.

E&E costs are initially capitalized as either tangible or intangible E&E assets according to the nature of the assets acquired. Intangible E&E assets may include costs of license acquisition, technical services and studies, seismic acquisition, exploration drilling and testing, and directly attributable overhead and administration expenses. The costs are accumulated in cost centers by well, field or exploration area pending determination of technical feasibility and commercial viability.

E&E assets are assessed for impairment if sufficient data exists to determine technical feasibility and commercial viability or facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For purposes of impairment testing, E&E assets are assessed at the individual asset level. If it is not possible to estimate the recoverable amount of the individual asset, exploration and evaluation assets are allocated to cash-generating units (“CGU’s”). Such CGU’s are not larger than an operating segment.

Exploration assets are not depleted and are carried forward until technical feasibility and commercial viability of extracting a mineral resource is considered to be determinable or sufficient/continued progress is made in assessing the commercial viability of the E&E assets. The technical feasibility and commercial viability of extracting a mineral resource is considered to be determinable when proven reserves are determined to exist. A review of each exploration license or field is carried out, at least annually, to confirm whether the Company intends further appraisal activity or to otherwise extract value from the property. When this is no longer the case, the costs are written off. Upon determination of proven reserves, E&E assets attributable to those reserves are first tested for impairment and then reclassified from E&E assets to oil and natural gas properties.

The Company may occasionally enter into arrangements, whereby the Company will transfer part of an oil and gas interest, as consideration, for an agreement by the transferee to meet certain E&E expenditures which would have otherwise been undertaken by the Company. The Company does not record any expenditures made by the transferee. Any cash consideration received from the agreement is credited against the costs previously capitalized to the oil and gas interest given up by the Company, with any excess cash accounted for as a gain on disposal.

Oil and gas properties and other property and equipment costs

Items of property and equipment, which include oil and gas development and production assets, are measured at cost less accumulated depletion and depreciation and accumulated impairment losses.

The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of the decommissioning obligation and, for qualifying assets, borrowing costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset. When significant parts of an item of property and equipment, including oil and natural gas interests, have different useful lives, they are accounted for as separate items (major components).

Depletion and Depreciation

Oil and gas development and production assets are depreciated, by significant component, on a unit-of-production basis over proved and probable reserve volumes, taking into account estimated future development costs necessary to bring those reserves into production. Future development costs are estimated by taking into account the level of development required to produce the reserves. These estimates are reviewed by independent reserve engineers at least annually. Changes in reserve estimates are dealt with prospectively. Proved and probable reserves are estimated using independent reserve engineer reports and represent the estimated quantities of oil, natural gas and gas liquids.

Other property and equipment are depreciated based on a declining balance basis, which approximates the estimated useful lives of the asset, at the following rates:

Office furniture and equipment	20%
Computer equipment	45%
Vehicle	30%
Leasehold improvements	term of lease

Depreciation methods, useful lives and residual values are reviewed at each reporting date. Other property and equipment are allocated to each of the Company’s primary cash-generating units, based on estimated future net revenue, consistent with the recoverable values applied in the most recent impairment test.

Derecognition

The carrying amount of an item of property and equipment is derecognized on disposal, when no beneficial interest is retained, or when no future economic benefits are expected from its use or disposal. The gain or loss arising from derecognition is included in profit or loss when the item is derecognized and is measured as the difference between the net disposal proceeds, if any, and the carrying amount of the item. The date of disposal is the date when the Company is no longer subject to the risks of ownership and is no longer the beneficiary of the rewards of ownership. Where the asset is derecognized, the date of disposal coincides with the date the revenue from the sale of the asset is recognized.

On the disposition of an undivided interest in a property, where an economic benefit remains, the Company recognizes the farm out only on the receipt of consideration by reducing the carrying amount of the related property with any excess recognized in profit or loss of the period.

Major maintenance and repairs

The costs of day-to-day servicing are expensed as incurred. These primarily include the costs of labor, consumables and small parts. Material costs of replaced parts, turnarounds and major inspections are capitalized as it is probable that future economic benefits will be received. The carrying value of a replaced part is derecognized in accordance with the derecognition principles above.

Jointly controlled operations

The Company conducts its oil and gas development and production activities through jointly controlled operations and the accounts reflect only its interest in such activities. A joint arrangement exists where the parties take their share of the output and is accounted for by recognizing the Company’s share of assets and liabilities jointly owned and incurred, and the recognition of its share of revenue and expenses of the joint operation. At December 31, 2017, the Company’s material joint operation in Canada is Drake/Woodrush. The principal activity is oil and gas production and the ownership percentage is 99% (December 31, 2016 – 99%).

(e) Provisions

A provision is recognized if, as a result of a past event, the Company 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. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risk specific to the liability.

Decommissioning liability

A decommissioning liability is recognized when the Company has a present legal or constructive obligation as a result of past events, it is probable that an outflow of resources will be required to settle the obligation, and a reliable estimate of the amount of obligation can be made. A corresponding amount equivalent to the provision is also recognized as part of the cost of the related asset. The amount recognized is management’s estimated cost of decommissioning, discounted to its present value using a risk free rate. Changes in the estimated timing of decommissioning or decommissioning cost estimates are dealt with prospectively by recording an adjustment to the provision and a corresponding adjustment to the related asset unless the change arises from production. The unwinding of the discount on the decommissioning provision is included as a finance cost. Actual costs incurred upon settlement of the decommissioning liability are charged against the provision to the extent the provision was established.

(f) Earnings (loss) per share

Basic earnings (loss) per share figures have been calculated using the weighted average number of common shares outstanding during the respective periods.

Diluted earnings (loss) per common share is calculated by dividing the profit or loss applicable to common shares by the sum of the weighted average number of common shares issued and outstanding and all additional common shares that would have been outstanding if potentially dilutive instruments were converted. The diluted earnings (loss) per share figure is equal to that of basic earnings (loss) per share since the effects of options and warrants have been excluded as they are anti-dilutive.

(g) Share based payments

Where equity-settled share options are awarded to employees, the fair value of the options at the date of grant is charged to profit or loss over the vesting period. Performance vesting conditions are taken into account by adjusting the number of equity instruments expected to vest at each reporting date so that, ultimately, the cumulative amount recognized over the vesting period is based on the number of options that will eventually vest. Where equity instruments are granted to employees, they are recorded at the instruments grant date fair value.

Where the terms and conditions of options are modified before they vest, the increase in the fair value of the options, measured immediately before and after the modification, is also charged to profit or loss over the remaining vesting period.

Where equity instruments are granted to non-employees, they are recorded at the fair value of the goods or services received in profit or loss, unless they are related to the issuance of shares. Amounts related to the issuance of shares are recorded as a reduction of share capital.

When the value of goods or services received in exchange for the share-based payment to non-employees cannot be reliably estimated, the fair value of the share-based payment is measured by use of a valuation model to measure the value of the equity instruments issued. The expected life used in the model is adjusted, based on management’s best estimate, for the effects of non-transferability, exercise restrictions, and behavioural considerations.

All equity-settled share based payments are reflected in contributed surplus, until exercised. Upon exercise, shares are issued from treasury and the amount reflected in contributed surplus is credited to share capital along with any consideration received.

Where a grant of options is cancelled or settled during the vesting period, excluding forfeitures when vesting conditions are not satisfied, the Company immediately accounts for the cancellation as an acceleration of vesting and recognizes the amount that otherwise would have been recognized for services received over the remainder of the vesting period. Any payment made to the employee on the cancellation is accounted for as the repurchase of an equity interest except to the extent the payment exceeds the fair value of the equity instrument granted, measured at the repurchase date. Any such excess is recognized as an expense.

(h) Revenue recognition

Revenue from the sale of oil and petroleum products is recognized when the significant risks and rewards of ownership have been transferred, which is when title passes to the customer. This generally occurs when the product is physically transferred into a vessel, pipe or other delivery mechanism. Revenue is stated after deducting sales taxes, excise duties and similar levies.

Revenue from the production of oil and natural gas in which the Company has an interest with other producers is recognized based on the Company’s working interest and the terms of the relevant production sharing contracts.

(i) Financial instruments

Financial assets

Financial assets are classified as one of the following categories. All transactions related to financial instruments are recorded on a trade date basis. The Company's accounting policy for each category is as follows:

Loans and receivables

These assets are non-derivative financial assets resulting from the delivery of cash or other assets by a lender to a borrower in return for a promise to repay on a specified date or dates, or on demand. They are initially recognized at fair value plus transaction costs that are directly attributable to their acquisition or issue and subsequently carried at amortized cost, using the effective interest rate method, less any impairment losses. Amortized cost is calculated taking into account any discount or premium on acquisition and includes fees that are an integral part of the effective interest rate and transaction costs. Gains and losses are recognized in profit or loss when the loans and receivables are derecognized or impaired, as well as through the amortization process. The Company’s loans and receivables comprise cash and cash equivalents and accounts and other receivables.

Held-to-maturity investments

Held to maturity investments are initially measured at fair value and are subsequently measured at amortized cost using the effective interest rate method, less any impairment losses. The Company does not currently have any held-to-maturity investments.

Available-for-sale assets

Available-for-sale assets are measured at fair value, with unrealized gains and losses recorded in other comprehensive income (loss) until the asset is realized or impairment is viewed as other than temporary, at which time they will be recorded in profit or loss. The Company does not currently have any available-for-sale assets.

Financial assets at fair value through profit or loss

An instrument is classified at fair value through profit or loss if it is held for trading or is designated as such upon initial recognition. Financial instruments are designated at fair value through profit or loss if the Company manages such investments and makes purchase and sale decisions based on their fair value in accordance with the Company’s risk management or investment strategy. Upon initial recognition, attributable transaction costs are recognized in profit or loss when incurred. Financial instruments at fair value through profit or loss are measured at fair value, and changes therein are recognized in profit or loss. The Company does not have any financial assets at fair value through profit or loss.

Financial liabilities

Financial liabilities are classified as either fair value through profit or loss or other financial liabilities, based on the purpose for which the liability was incurred.

The Company’s other financial liabilities comprise accounts payable and accrued liabilities, bank credit facility, loans from related parties and financial contract liability. These liabilities are initially recognized at fair value, net of any transaction costs directly attributable to the issuance of the instrument and subsequently carried at amortized cost using the effective interest rate method, which ensures that any financing expense over the period of repayment is at a constant rate on the balance of the liability carried in the balance sheet. Interest expense in this context includes initial transaction costs and premiums payable on redemption, as well as any interest or coupon payable while the liability is outstanding. Any revision to the amount or timing of cash flows related to an instrument is reflected in its carrying amount by computing the present value of the revised cash flows at the instrument’s initial effective interest rate. The change in carrying amount is reflected in profit or loss of the period. Accounts payable represent liabilities for goods and services provided to the Company prior to the end of the period which are unpaid. Accounts payable amounts are unsecured and are usually paid within 30 days from receipt of invoice.

Financial liabilities are classified as held-for-trading if they are acquired for the purpose of selling in the near term. Derivatives are also categorized as held for trading unless they are designated as hedges.

The Company has derivative financial instruments in the form of warrants issued in US dollars, or with certain adjustment provisions, and contracts entered into to manage its exposure to volatility in commodity prices. Commodity contracts are not used for trading or other speculative purposes. Such derivative financial instruments are initially recognized at fair value at the date at which the derivatives are issued and are subsequently re-measured at fair value. These derivatives do not qualify for hedge accounting and changes in fair value are recognized immediately in profit and loss.

For outstanding warrants at each reporting period, the change in the fair value of the liability between reporting periods is recorded in the consolidated statement of comprehensive income (loss). As warrants are exercised, immediately before exercise, the liability on these exercised warrants is re-measured and the valuation change is recorded in the consolidated statement of comprehensive income (loss). Upon exercise, the re-measured warrant liability on these exercised warrants is eliminated and there is an offsetting entry to share capital.

Financial instrument measurement

If the market value for a financial instrument is not an active market the Company establishes fair value by using a valuation technique. Valuation techniques include using recent arm’s length market transaction between knowledgeable, willing parties, if available, reference to the current fair value of another instrument that is substantially the same, discounted cash flow analysis and option pricing models. The fair value of a financial instrument will be based on one or more factors that may include the time value of money, credit risk, commodity prices, equity prices, volatility, servicing costs and other factors.

(j) Impairment

Impairment of financial assets

At each reporting date, the Company assesses whether there is objective evidence that a financial asset is impaired. If such evidence exists, the Company recognizes an impairment loss, as follows:

Financial assets are carried at amortized cost. The loss is the difference between the amortized cost of the loan or receivable and the present value of the estimated future cash flows, discounted using the instrument’s original effective interest rate. The carrying amount of the asset is reduced by this amount either directly or indirectly through the use of an allowance account.

Impairment losses on financial assets carried at amortized cost are reversed in subsequent periods if the amount of the loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognized.

Non-financial assets

For the purpose of impairment testing, assets are grouped together in CGUs, which are the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets. The carrying value of long-term assets is reviewed at each period for indicators that the carrying value of an asset or a CGU may not be recoverable. The Company uses geographical proximity, geological similarities, analysis of shared infrastructure, commodity type, assessment of exposure to market risks and materiality to define its CGUs. If indicators of impairment exist, the recoverable amount of the asset or CGU is estimated. If the carrying value of the asset or CGU exceeds the recoverable amount, the asset or CGU is written down with an impairment recognized in profit or loss.

The recoverable amount of an asset or CGU is the greater of its value in use and its fair value less costs to sell. Fair value is determined to be the amount for which the asset could be sold in an arm’s length transaction. For resource properties, fair value less costs to sell may be determined by using discounted future net cash flows of proved and probable reserves using forecast prices and costs. Value in use is determined by estimating the net present value of future net cash flows expected from the continued use of the asset or CGU.

Impairment losses recognized in prior years are assessed at each reporting date for any indication that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimate used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation, if no impairment loss had been recognized.

(k) Taxes

Income taxes

Income tax expense comprises current and deferred tax. Income tax expense is recognized in profit or loss except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity.

Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.

Deferred tax is recognized for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on temporary differences on the initial recognition of assets or liabilities in a transaction that is not a business combination and affects neither accounting profit nor taxable profit. In addition, deferred tax is not recognized for taxable temporary differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when the asset is realized or the liability is settled, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, when they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously.

A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

Production taxes

Royalties, resource rent taxes and revenue-based taxes are accounted for under International Accounting Standards (‘IAS’) 12 when they have characteristics of an income tax. This is considered to be the case when they are imposed under Government authority and the amount is payable based on taxable income, rather than based on quantity produced or as a percentage of revenue, after adjustment for temporary differences. For such arrangements, current and deferred tax is provided on the same basis as described above for other forms of taxation. Obligations arising from royalty arrangements that do not satisfy these criteria are recognized as a reduction of revenues.

(l) Share capital

The Company’s common shares, stock options, share purchase warrants and flow-through shares are classified as equity instruments only to the extent that they do not meet the definition of a financial liability or financial asset. Incremental costs directly attributable to the issue of equity instruments are shown in equity as a deduction, net of tax, from the proceeds.

(m) Flow-through shares

The Company will from time to time, issue flow-through common shares to finance a portion of its exploration program. Pursuant to the terms of the flow-through share agreements, these shares transfer the tax deductibility of qualifying resource expenditures to investors. On issuance, the Company separates the flow-through share into i) a flow-through share premium, equal to the estimated premium, if any, investors pay for the flow-through feature, which is recognized as a liability and; ii) share capital. Upon expenditures being incurred, the Company derecognizes the liability and recognizes a deferred income tax recovery for the amount of tax reduction renounced to the shareholders.

(n) Adoption of new and amended standards

There were no new or amended accounting standards or interpretations that had a significant impact on the Company’s consolidated financial statements during the year ended December 31, 2017.

(o) Future accounting pronouncements

Certain pronouncements were issued by “IASB” or “IFRIC” that are mandatory for accounting periods beginning after January 1, 2018 or later periods. The following new accounting standards, amendments to accounting standards and interpretations, have not been early adopted in these consolidated financial statements:

IFRS 9, “Financial Instruments”: In July 2014, the IASB completed the final phase of its project to replace IAS 39, the current standard on the recognition and measurement of financial instruments. IFRS 9 is now the new standard which sets out the recognition and measurement requirements for financial instruments and some contracts to buy or sell non-financial items. IFRS 9 provides a single model of classifying and measuring financial assets and liabilities and provides for only two classification categories: amortized cost and fair value. Hedge accounting requirements have also been updated in the new standard and are now more aligned with the risk management activities of an entity. IFRS 9 is effective for annual periods beginning on or after January 1, 2018. Early adoption is permitted; however, if an entity elects to apply this standard early, it must disclose that fact and apply all of the requirements in this standard at the same time. The Company has determined that there will not be any material impact on its consolidated financial statements as a result of the adoption of IFRS 9.

IFRS 15, “Revenue from Contracts with Customers”: the standard was issued in May 2014 and amended in April 2016. IFRS 15 applies to contracts with customers, excluding, most notably, insurance and leasing contracts. IFRS 15 prescribes a framework in accounting for revenues from contracts within its scope, including (a) identifying the contract, (b) identify separate performance obligations in the contract, (c) determine the transaction price of the contract, (d) allocate the transaction price to the performance obligations and (e) recognize revenues when each performance obligation is satisfied. IFRS 15 also prescribes additional financial statement presentations and disclosures. The Company currently expects to adopt IFRS 15 as of January 1, 2018, under the modified retrospective method where the cumulative effect is recognized at the date of initial application. The Company has completed the evaluation of IFRS 15. It has been concluded that the adoption of IFRS 15 will not have a material effect on the Company’s consolidated financial statements.

IFRS 16, “Leases”: In January 2016, the IASB issued the standard to replace IAS 17 “Leases”. For lessees applying IFRS 16, a single recognition and measurement model for leases would apply, with required recognition of assets and liabilities for most leases. The standard will come into effect for annual periods beginning on or after January 1, 2019, with earlier adoption permitted. It is anticipated that the adoption of IFRS 16 will have impact on the Company’s consolidated balance sheet due to the operating lease commitments as disclosed in note 17.

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CRITICAL ACCOUNTING ESTIMATES AND JUDGMENTS

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

CRITICAL ACCOUNTING ESTIMATES AND JUDGMENTS [Text Block]

NOTE 4 - CRITICAL ACCOUNTING ESTIMATES AND JUDGMENTS

The preparation of financial statements in accordance with IFRS requires management to make estimates and judgments that affect reported assets, liabilities, revenues, expenses, gains, and losses. These estimates and judgments are subject to change based on experience and new information. The financial statement areas that require significant estimates and judgments are as follows:

Decommissioning liability

The Company recognizes decommissioning liabilities for its exploration and evaluation assets and property and equipment. Measurement of the decommissioning liabilities involves estimates and judgements as to the cost and timing of incurrence of future decommissioning programs. It also involves assessment of appropriate discount rates, rates of inflation applicable to future costs and the rate used to measure the accretion charge for each reporting period. Measurement of the liability also reflects current engineering methodologies as well as current and expected future environmental legislation and standards. Actual decommissioning costs will ultimately depend on future market prices for the decommissioning costs which will reflect the market conditions at the time the decommissioning costs are actually incurred. The final cost of the currently recognized decommissioning provisions may be higher or lower than currently provided for.

Exploration and evaluation expenditures

The application of the Company’s accounting policy for exploration and evaluation expenditures requires judgment in determining whether it is likely that future economic benefits will flow to the Company, which is based on assumptions about future events or circumstances. Estimates and assumptions made may change if new information becomes available. If, after the expenditure is capitalized, information becomes available suggesting that the recovery of the expenditure is unlikely, the amount capitalized is written off in profit or loss in the period in which the new information becomes available.

Share-based payment transactions

The Company measures the cost of equity-settled transactions with employees by reference to the fair value of the equity instruments at the date at which they are granted. Management uses judgment to determine the most appropriate valuation model to estimate the fair value for share-based payment transactions. The inputs to the valuation model, including the expected life of the share option, volatility and dividend yield, require judgment for determination.

Financial contract liability

The application of the Company’s accounting policy for financial liabilities requires the Company to adjust the carrying amounts of the financial liabilities in the event it revises its payments or receipts to reflect actual and revised estimated cash flows. The Company’s financial contract liability was originally recognized at fair value using the effective interest method which ensures that any interest expense over the period of repayment is at a constant rate on the balance of the liability carried in the balance sheet. Effective June 30, 2014, the Company’s financial contract liability was reduced by the residual reserve value of its working interest in the wellbores at September 30, 2016.

At December 31, 2017, the financial contract liability was adjusted to reflect the present value of the amount outstanding at year-end, net of the present value of the residual reserves of its working interest in the wellbores.

Impairment

Management applies judgment in assessing the existence of impairment and impairment reversal indicators based on various internal and external factors.

The recoverable amounts of CGUs and individual assets have been determined based on the higher of fair value less costs to sell or value-in-use. The key estimates the Company applies in determining the recoverable amount normally include anticipated future commodity prices, expected production volumes, future operating and development costs, and discount rates. Changes to these assumptions will affect the recoverable amounts of CGUs and individual assets and may then require a material adjustment to their related carrying value. At December 31, 2017, the Company has one CGU in Canada (Drake/Woodrush) and one CGU in the United States (Kokopelli) – Note 6.

Financial instruments

When estimating the fair value of financial instruments, the Company uses valuation methodologies that utilize observable market data where available. In addition to market information, the Company incorporates transaction specific details that market participants would utilize in a fair value measurement, including the impact of non-performance risk. See note 9 for the basis of valuation of loans from related parties and warrants issued in the year.

Reserves

The estimate of reserves is used in forecasting the recoverability and economic viability of the Company’s oil and gas properties, and in the depletion and impairment calculations. The process of estimating reserves is complex and requires significant interpretation and judgment. It is affected by economic conditions, production, operating and development activities, and is performed using available geological, geophysical, engineering, and economic data. Reserves are evaluated at least annually by the Company’s independent reserve evaluators and updates to those reserves, if any, are estimated internally. Future development costs are estimated using assumptions as to the number of wells required to produce the commercial reserves, the cost of such wells and associated production facilities and other capital costs.

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EXPLORATION AND EVALUATION (E&E) ASSETS

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

EXPLORATION AND EVALUATION (E&E) ASSETS [Text Block]

NOTE 5 – EXPLORATION AND EVALUATION (“E&E”) ASSETS

	Canadian Oil	United States
	and Gas	Oil and Gas
	Properties	Properties		Total
	$	$		$
Cost:
Balance at January 1, 2016	281	18,982		19,263
Additions	2	-		2
Change in decommissioning provision	13	-		13
Disposals	-	(772	)	(772	)
Foreign currency translation and other	-	(768	)	(768	)
Balance at December 31, 2016	296	17,442		17,738
Additions	4	3		7
Change in decommissioning provision	56	-		56
Disposals	-	-		-
Foreign currency translation and other	-	(1,174	)	(1,174	)
Balance at December 31, 2017	356	16,271		16,627

	Canadian Oil		United States
	and Gas		Oil and Gas
	Properties		Properties		Total
	$		$		$
Accumulated impairment losses:
Balance at January 1, 2016	-		(16,041	)	(16,041	)
Impairment losses	-		(1,790	)	(1,790	)
Disposals	-		513		513
Foreign currency translation and other	-		550		550
Balance at December 31, 2016	-		(16,768	)	(16,768	)
Impairment losses (Note 7)	(350	)	(621	)	(971	)
Disposals	-		-		-
Foreign currency translation and other	-		1,120		1,120
Balance at December 31, 2017	(350	)	(16,269	)	(16,619	)

	Canadian Oil	United States
	and Gas	Oil and Gas
	Properties	Properties	Total
	$	$	$
Carrying amounts:
At December 31, 2016	296	674	970
At December 31, 2017	6	2	8

Exploration and evaluation (“E&E”) assets consist of the Company’s exploration projects which are pending the determination of proven reserves.

United States Exploration and Evaluation Properties

As at December 31, 2017, the Company holds oil and gas leases in the Piceance, Paradox and Uinta Basins in the US Rocky Mountains, of which a portion was classified as E&E assets.

The E&E asset impairment is $621,000 and $1,790,000 for the year ended December 31, 2017 and December 31, 2016, respectively. The impairment was recognized upon a review of each exploration license or field, carried out, at least annually, to confirm whether the Company intends further appraisal activity or to otherwise extract value from the property.

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PROPERTY AND EQUIPMENT

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

PROPERTY AND EQUIPMENT [Text Block]

NOTE 6 – PROPERTY AND EQUIPMENT

	Canadian Oil		United States
	and Gas		Oil and Gas		Corporate and
	Properties		Properties		Other Assets		Total
	$		$		$		$
Cost:
Balance at January 1, 2016	33,376		16,653		179		50,208
Additions	300		225		3		528
Change in decommissioning provision	(48	)	(4	)	-		(52	)
Foreign currency translation and other	-		(502	)	-		(502	)
Balance at December 31, 2016	33,628		16,372		182		50,182
Additions	405		39		5		449
Change in decommissioning provision	94		(3	)	-		91
Disposals	-		-		(29	)	(29	)
Foreign currency translation and other	-		(1,060	)	-		(1,060	)
Balance at December 31, 2017	34,127		15,348		158		49,633

	Canadian Oil		United States
	and Gas		Oil and Gas		Corporate and
	Properties		Properties		Other Assets		Total
	$		$		$		$
Accumulated amortization, depletion and impairment
losses:
Balance at January 1, 2016	(26,774	)	(1,375	)	(160	)	(28,309	)
Amortization and depletion	(1,248	)	(380	)	(5	)	(1,633	)
Impairment losses	(1,070	)	-		-		(1,070	)
Foreign currency translation and other	-		41		1		42
Balance at December 31, 2016	(29,092	)	(1,714	)	(164	)	(30,970	)
Amortization and depletion (Note 7)	(561	)	(223	)	(3	)	(787	)
Impairment losses (Note 7)	(870	)	-		-		(870	)
Disposals	-		-		25		25
Foreign currency translation and other	-		131		-		131
Balance at December 31, 2017	(30,523	)	(1,806	)	(142	)	(32,471	)

	Canadian Oil	United States
	and Gas	Oil and Gas	Corporate and
	Properties	Properties	Other Assets	Total
	$	$	$	$
Carrying amounts:
At December 31, 2016	4,536	14,658	18	19,212
At December 31, 2017	3,604	13,542	16	17,162

Canadian Oil and Gas Properties

Amortization and depletion is computed using the unit of production method by reference to the total production for the CGU over the estimated net proved and probable reserves of oil and gas for the CGU determined by independent consultants. The calculation of amortization and depletion for the year ended December 31, 2017 included estimated future development costs of $Nil (December 31, 2016 - nil; December 31, 2015 - $nil) as estimated by the Company’s external reserves evaluator.

During the year ended December 31, 2017, the Company capitalized $7,000 (December 31, 2016 – $104,000) of general and administrative costs related to its Canadian oil and gas interests.

In accordance with IFRS, impairment tests were conducted at December 31, 2017 on each of the Company’s CGUs. The estimated recoverable amounts were determined using fair value less cost to sell. In determining the recoverability of oil and gas interests and making these evaluations, the Company used the net present value of the cash flows from proved plus probable oil and gas reserves of each CGU as estimated by the Company’s independent reserve evaluator.

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

a)	Reserves – Assumptions that are valid at the time of reserve estimation may change significantly when new information becomes available. Changes in forward price estimates, production costs or recovery rates may change the economic status of reserves and may ultimately result in reserves being restated.
b)	Crude oil and natural gas prices – Forward price estimates of the crude oil and natural gas prices are used in the cash flow model. Commodity prices have fluctuated widely in recent years due to global and regional factors including supply and demand fundamentals, inventory levels, exchange rates, weather, economic and geopolitical factors.
c)	Discount rate – The discount rate used to calculate the net present value of cash flows is 14.4% post tax.

Below are the following forward commodity price estimates used in the December 31, 2017 impairment test:

	Natural gas	NGL	Crude oil
	(AECO)	(Edmonton Pentanes Plus)	(Edmonton Par)
	Cdn $ / mmbtu	Cdn $ / bbl	Cdn $ / bbl
2018	2.20	76.42	70.25
2019	2.54	74.68	70.25
2020	2.88	74.38	70.31
2021	3.24	77.16	72.84
2022	3.47	79.88	75.61
2023	3.58	82.53	78.31
2024	3.66	86.14	81.93
2025	3.73	89.76	85.54
2026	3.80	92.57	88.35
2027	3.88	94.43	90.22
Each benchmark price increased on average approximately 2% thereafter

For the year ended December 31, 2017, the Company recorded an impairment of $870,000 (December 31, 2016 - $940,000) on its Drake/Woodrush CGU. The impairment was recognized because the carrying value exceeded the recoverable amount. The fair value less cost to sell values used to determine the recoverable amounts of the impaired PP&E assets are classified as Level 3 fair value measurements.

On December 22, 2017, the Company signed a “Funding and Participation Agreement” (“the Agreement”) with a private U.S. based investment firm to underwrite 50% of the capital costs of at least one exploration well at Woodrush, currently scheduled to commence in the first quarter of 2018. Under the terms of the Agreement, the investment firm will pay approximately two-thirds of the total cost of the first well of the 2018 program, through tie in, to earn a 15% Gross Overriding Royalty (“GORR”).

The investment firm has the right to elect to participate in the drilling and completion of a 2 ^nd and subsequent wells, if any, by paying 50% of the capital costs to earn a 15% GORR in the well spacing unit on a well-by-well basis.

United States Oil and Gas Properties

Amortization and depletion is computed using the unit of production method by reference to the total production for the CGU over the estimated net proved and probable reserves of oil and gas for the CGU determined by independent consultants. The calculation of amortization and depletion for the year ended December 31, 2017 included estimated future development costs of $83.7 million (December 31, 2016 - $84.0 million; December 31, 2015 - $86.4 million) as estimated by the Company’s external reserves evaluator.

During the year ended December 31, 2017, the Company capitalized $12,000 (December 31, 2016 – $14,000) of general and administrative costs related to its US oil and gas interests.

At December 31, 2017 and December 31, 2016, the Company evaluated its oil and gas interests for indicators of any impairment or related recovery. The Company determined the recoverable amount of the CGU based on the cash flows from oil and gas reserves, using a discount rate of 14.3% (post tax) and determined there was no impairment at December 31, 2017 and December 31, 2016. The key inputs used included forward prices from NYMEX futures (adjusted for an inflationary factor), a discount rate of 14.3% (post tax) which was applied to the discounted cash flows and the reserves that were estimated.

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AMORTIZATION, DEPLETION AND IMPAIRMENT LOSSES

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

AMORTIZATION, DEPLETION AND IMPAIRMENT LOSSES [Text Block]

NOTE 7 – AMORTIZATION, DEPLETION AND IMPAIRMENT LOSSES

	Year ended December 31
	2017	2016	2015
	$	$	$
Exploration and Evaluation Assets (E & E assets)
Impairment losses (Note 5)	971	1,790	534
Property and Equipment (D & P assets)
Amortization and depletion (Note 6)	787	1,633	2,655
Impairment losses (Note 6)	870	1,070	1,000
	2,628	4,493	4,189

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LOANS FROM RELATED PARTIES

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

LOANS FROM RELATED PARTIES [Text Block]

NOTE 8 – LOANS FROM RELATED PARTIES

(a) Loan from Hodgkinson Equity Corporation (“HEC”)

On March 12, 2015, as amended on May 6, 2015, June 22, 2015, September 28, 2015, November 18, 2015 and June 5, 2017, the Company issued a promissory note for $4,500,000 to HEC, a private company controlled by the CEO of the Company. The promissory note is secured by all assets of Dejour USA and a negative pledge by the Company not to further encumber DEAL’s oil and gas properties without HEC’s prior approval. The principal and interest at Canadian prime rate plus 5% per annum was repayable by the earlier of (i) within 10 business days of receipt of written demand from HEC for the repayment and (ii) June 10, 2015 or such later date to which the term of the promissory note may be extended. On May 6, 2015, the due date of the loan was extended to September 30, 2015. On September 28, 2015, the due date of the loan was further extended to December 31, 2015. On November 18, 2015, the Company extended the due date of the loan from December 31, 2015 to November 30, 2018. Additionally, a monthly principal repayment of $114,230 was due on the 1 ^st day of each month commencing June 1, 2016. HEC agreed to waive the requirement of the Company to repay the total monthly principal repayments of $1,371,000 until the loan was restructured on June 5, 2017.

In consideration for the extension, the Company issued HEC 9,000,000 Warrants. Each Warrant entitles the holder to acquire one common share at a price of C$0.45 /US$0.35 per share any time prior to December 4, 2020. Shares acquired through the exercise of Warrants prior to April 5, 2016 were restricted from sale through the facilities of the stock exchanges for four months. On February 19, 2016, the Company rescinded the negative pledge security agreement and issued a first mortgage in favour of HEC on DEAL’s oil and gas properties. The first mortgage security so issued ranked “pari passu” with HVI’s first mortgage security interest (note 8(b)).

On June 5, 2017, the Company restructured the term of the loan with extension of the due date from November 30, 2018 to June 5, 2022; reduction of the interest rate to Canadian prime rate plus 1% per annum; and the right to convert the entire outstanding amount into 58,441,558 common shares of the Company at a price of $0.077 per share. In exchange for the modification, HEC agreed to cancel the 9,000,000 warrants described above. The fair value of the amended loan was determined by applying a risk-adjusted rate of 20% to discount the contractual cash flows over the 5 -year life of the loan. The fair value of the liability component of $2,346,000 is then deducted from the face value of the amended loan ($4.5 million), with the balance being taken directly to equity.

As a result of the loan restructure in June 2017, a loss on extinguishment is recognized as follows:

	$
Face value of amended loan	2,346
Conversion feature	2,158
Carrying value of old loan before restructure	(3,976	)
Loss on extinguishment	528

⁽¹⁾ $3,903,000 (carrying value at March 31, 2017) + $127,000 (accretion) - $54,000 (cash interest) = $3,976,000

As at December 31, 2017, the carrying value of the loan liability is as follows:

	$
Balance upon initial recognition	2,337
Accretion expense	265
Cash interest	(104	)
Balance at December 31, 2017	2,498
Current portion	(317	)
Non-current portion	2,181

Other terms of the loan are:

• the Company may repay the loan at any time without penalty;

• the Company, through DEAL, must receive HEC’s approval to further encumber DEAL’s Canadian oil and gas properties; and

• In the event of default, all the indebtedness secured by the promissory note becomes due and payable and the interest rate is immediately increased to Canadian prime rate plus 4.5% per annum.

(b) Loan from Hodgkinson Ventures Inc. (“HVI”)

On June 22, 2015, as amended on September 28, 2015, November 18, 2015 and June 5,2017, the Company issued a promissory note for $2,000,000 to HVI, a private company associated with the CEO of the Company, on a “pari passu” basis with the loan from HEC (note 8(a)). The promissory note is secured by all assets of Dejour USA and a negative pledge by the Company not to further encumber DEAL’s oil and gas properties without HVI’s prior approval. The principal and interest at Canadian prime rate plus 5% per annum were repayable on or before September 30, 2015. On September 28, 2015, the due date of the loan was extended to December 31, 2015. On November 18, 2015, the Company extended the due date of the loan from December 31, 2015 to November 30, 2018. Additionally, a monthly principal repayment of $50,769 was due on the 1 ^st day of each month commencing June 1, 2016. HVI agreed to waive the requirement of the Company to repay the total monthly principal repayments of $660,000 until the loan was restructured on June 5, 2017.

In consideration for the extension, the Company issued HVI 4,000,000 Warrants. Each Warrant entitles the holder to acquire one common share at a price of C$0.45 /US$0.35 per share any time prior to December 4, 2020. Shares acquired through the exercise of Warrants prior to April 5, 2016 were restricted from sale through the facilities of the stock exchanges for four months. On February 19, 2016, the Company rescinded the negative pledge security agreement and issued a first mortgage in favour of HVI on DEAL’s oil and gas properties. The first mortgage security so issued ranked “pari passu” with HEC’s first mortgage security interest (note 8(a)).

On June 5, 2017, the Company restructured the term of the loan with extension of the due date from November 30, 2018 to June 5, 2022; reduction of the interest rate to Canadian prime rate plus 1% per annum; and the right to convert the entire outstanding amount into 25,974,025 common shares of the Company at a price of $0.077 per share. In exchange for the modification, HVI agreed to cancel the 4,000,000 warrants described above.

The fair value of the amended loan was determined by applying a risk-adjusted rate of 20% to discount the contractual cash flows over the 5 -year life of the loan. The fair value of the liability component of $1,043,000 is then deducted from the face value of the amended loan ($2.0 million), with the balance being taken directly to equity.

As a result of the loan restructure in June 2017, a loss on extinguishment is recognized as follows:

	$
Face value of amended loan	1,043
Conversion feature	960
Carrying value of old loan before restructure	(1,613	)
Loss on extinguishment	390

⁽¹⁾ $1,560,000 (carrying value at March 31, 2017) + $77,000 (accretion) - $24,000 (cash interest) = $1,613,000

As at December 31, 2017, the carrying value of the loan liability and derivative liability are as follows:

	$
Balance upon initial recognition	1,039
Accretion expense	117
Cash interest	(46	)
Balance at December 31, 2017	1,110
Current portion	(141	)
Non-current portion	969

Other terms of the loan are:

• the Company may repay the loan at any time without penalty;

• the Company, through DEAL, must receive HVI’s approval to further encumber DEAL’s Canadian oil and gas properties; and

• In the event of default, all the indebtedness secured by the promissory note becomes due and payable and the interest rate is immediately increased to Canadian prime rate plus 4.5% per annum.

(c) Loan from a director and officer of the Company and his spouse

On September 15, 2015, as amended on January 11, 2016, March 31, 2016, June 2, 2016, September 30, 2016, December 31, 2016 and June 30, 2017, the Company issued a grid promissory note of up to $1,000,000 to a director and officer of the Company and his spouse (the “Lenders”). The promissory note bears interest at 12% per annum. The principal and interest accrued on the loan were repayable on or before December 31, 2015. On January 11, 2016, the Company issued an additional grid promissory note of up to $200,000 to a director and officer of the Company and his spouse and the due date of the loan was extended to March 31, 2016. On March 31, 2016, the due date of the loan was further extended to September 30, 2016.

On June 2, 2016, the Company increased the maximum amount of the non-revolving loan from $1,200,000 to $1,500,000. The interest rate was also reduced from 12% to 10% per annum. Additionally, the Company issued a 2 ^nd mortgage in favour of the Lenders on DEAL’s oil and gas properties to a maximum of $1,500,000 as partial security for the loan. On September 30, 2016, the due date of the loan was extended to December 31, 2016. On December 31, 2016, the due date of the loan was extended to June 30, 2017. On June 30, 2017, the due date of the loan was further extended to June 30, 2018. The maximum loan amount available at December 31, 2017 was $1,500,000 (December 31, 2016 - $1,500,000). During the year ended December 31, 2017, $450,000 was borrowed (2016 - $50,000) and $500,000 was repaid via issuance of the Company’s common shares (2016 - $Nil) leaving a balance outstanding of $1,000,000 at December 31, 2017 (December 31, 2016 - $1,050,000).

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FLOW-THROUGH SHARES LIABILITY

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

FLOW-THROUGH SHARES LIABILITY [Text Block]

NOTE 9 – FLOW-THROUGH SHARES LIABILITY

The following is a continuity schedule of the liability portion of the flow-through shares issuances:

	Issued in		Issued in
	October		December	Total
	2017		2017
	$		$	$
Balance at January 1, 2017	-		-	-
Liability incurred on flow-through shares issued	21		93	114
Settlement of flow-through share liability on incurring expenditures	(21	)	-	(21	)
Balance at December 31, 2017	-		93	93

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DECOMMISSIONING LIABILITY

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

DECOMMISSIONING LIABILITY [Text Block]

NOTE 10 – DECOMMISSIONING LIABILITY

	Canadian		United States
	Oil and Gas		Oil and Gas
	Properties (1)		Properties (1)		Total
	$		$		$
Balance at January 1, 2016	3,679		146		3,825
Change in estimated future cash flows	(36	)	(4	)	(40	)
Actual costs incurred and other	(53	)	(5	)	(58	)
Unwinding of discount	46		3		49
Balance at December 31, 2016	3,636		140		3,776
Change in estimated future cash flows	146		(3	)	143
Actual costs incurred and other	(3	)	(8	)	(11	)
Unwinding of discount	60		3		63
Balance at December 31, 2017	3,839		132		3,971

⁽¹⁾ relates to property and equipment (note 6)

The present value of the decommissioning liability was calculated using the following weighted average inputs:

	Canadian Oil	United States
	and Gas	Oil and Gas
	Properties	Properties
As at December 31, 2017:
Discount rate	1.94%	2.20%
Inflation rate	2.00%	2.00%
As at December 31, 2016:
Discount rate	1.60%	2.34%
Inflation rate	2.00%	2.00%

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FINANCIAL CONTRACT LIABILITY

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

FINANCIAL CONTRACT LIABILITY [Text Block]

NOTE 11 – FINANCIAL CONTRACT LIABILITY

On December 31, 2012, Dejour USA entered into a financial contract with a U.S. oil and gas drilling fund (“Drilling Fund”) to fund the drilling of up to three wells and the completion of up to four wells in the State of Colorado. The total amount contributed by the Drilling Fund was US$7,000,000.

The financial contract contains a provision whereby Dejour USA must purchase the Drilling Funds’ working interest in the four wells funded by the US$7,000,000 if the Drilling Fund fails to obtain a certain minimum return on investment by September 30, 2016. A subsequent amendment limited Dejour USA’s cash exposure to a potential “put” by the Drilling Fund to US$3,000,000, with the difference to be settled by an assignment of working interests in certain P&NG properties owned by Dejour USA. The Company is not a party to the financial contract.

On September 30, 2016, the Drilling Fund served notice to Dejour USA requiring Dejour USA to purchase the Drilling Funds’ working interest in the 4 wellbores in accordance with the contract. However, prior to serving such notice, the Drilling Fund executed certain assignments transferring ownership of its working interests in the 4 wellbores to another entity and the assignee mortgaged its interest therein. Dejour USA and its attorneys are reviewing the impact of the Drilling Fund’s actions on the validity of the financial contract between the parties.

As at December 31, 2017, Dejour USA has recorded a liability owing to the Drilling Fund of $6,752,000, as follows:

	$
Balance at January 1, 2016 (US$5,207)	7,207
Accretion expense (US$222)	296
Foreign exchange gain	(214	)
Adjustment to financial contract liability (US$47)	(63	)
Balance at December 31, 2016 (US$5,382)	7,226
Foreign exchange gain	(474	)
Balance at December 31, 2017 (US$5,382)	6,752

This amount, if any, is subject to a resolution of the financial contract between the parties. Dejour USA has received no formal communication from the Drilling Fund since the “put” notice date of September 30, 2016.

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SHARE CAPITAL

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

SHARE CAPITAL [Text Block]

NOTE 12 – SHARE CAPITAL

Authorized

The Company is authorized to issue an unlimited number of common voting shares, an unlimited number of first preferred shares issuable in series, and an unlimited number of second preferred shares issuable in series. No preferred shares have been issued and the terms of preferred shares have not been defined.

In January 2018, the Company renounced $523,000 flow-through funds to investors, using the look-back rule. The Company expects to fully spend the flow-through funds during 2018 and a deferred income tax recovery of $93,000 will be recognized on settlement of flow-through shares liability.

In December 2017, the Company renounced $149,000 flow-through funds to investors, using the general rule. The flow-through funds had been fully spent by December 31, 2017. As a result of renunciation, a deferred income tax recovery of $21,000 was recognized on settlement of the flow-through shares liability.

In December 2017, the Company completed a private placement and 8,633,166 common shares were issued at a price of $0.075 per share for gross proceeds of $647,000 and an additional 5,738,665 flow-through shares were issued for gross proceeds of $523,000 ( 5,091,165 at $0.09 per share and 647,500 at $0.10 per share). The Company paid finders’ fees of $51,000 and other costs of $24,000 related to this offering. 946,667 of the common shares were issued at $0.075 per share to certain creditors of the Company to settle the amounts owing to them.

In October 2017, the Company completed a private placement and 42,297,400 common shares were issued at a price of $0.06 per share for gross proceeds of $2,538,000 and additional 2,128,571 flow-through shares were issued at a price of $0.07 per share for gross proceeds of $149,000. The Company paid finders’ fees of $41,000 and other costs of $23,000 related to this offering. 21,924,067 of the common shares were issued at $0.06 per share to Directors and Officers of the Company (17,967,644) and certain creditors of the Company (3,956,423) to settle the amounts owing to them.

In June and July 2016, the Company completed a dual tranche private placement and 8,298,333 common shares were issued at a price of $0.12 per share for total gross proceeds of $995,800. The Company paid finders’ fees of $18,000 and other costs of $29,000 related to this offering. Directors and Officers of the Company purchased 3,600,000 common shares of this offering.

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STOCK OPTIONS AND SHARE PURCHASE WARRANTS

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

STOCK OPTIONS AND SHARE PURCHASE WARRANTS [Text Block]

NOTE 13 – STOCK OPTIONS AND SHARE PURCHASE WARRANTS

(a) Stock Options

The Stock Option Plan (the “Plan”) is a 10% “rolling” plan pursuant to which the number of common shares reserved for issuance is 10% of the Company’s issued and outstanding common shares as constituted on the date of any grant of options.

The Plan provides for the grant of options to purchase common shares to eligible directors, senior officers, employees and consultants of the Company (“Participants”). The exercise periods and vesting periods of options granted under the Plan are to be determined by the Company with approval from the Board of Directors. The expiration of any option will be accelerated if the participant’s employment or other relationship with the Company terminates. The exercise price of an option is to be set by the Company at the time of grant but shall not be lower than the market price (as defined in the Plan) at the time of grant.

The following table summarizes information about outstanding stock option transactions:

			Weighted
	Number of		average
	options		exercise price
			$
Balance at January 1, 2016	140,738		1.20
Options granted	3,400,000		0.16
Options cancelled	(52,818	)	1.26
Options forfeited	(87,920	)	1.16
Balance at December 31, 2016 and December 31, 2017	3,400,000		0.16

Details of the stock options as at December 31, 2017 are as follows:

	Outstanding			Exercisable
		Weighted average			Weighted average
	Number	exercise	contractual	Number	exercise	contractual
	of options	price	life (years)	of options	price	life (years)
		$			$
$0.16	3,400,000	0.16	3.43	3,400,000	0.16	3.43

During the year ended December 31, 2017, the Company did not grant any stock options (2016 – 3,400,000). The fair value of the options issued during the year ended December 31, 2016 was estimated using the Black Scholes option pricing model with the following weighted average inputs:

For the year ended December 31		2016
Fair value at grant date	$	0.06
Expected volatility		80.35%
Expected option life		1.37 years
Dividends		0.0%
Risk-free interest rate		0.54%
Estimated forfeiture rate		6.85%

Expected volatility is based on historical volatility and average weekly stock prices were used to calculate volatility. Management believes that the annualized weekly average of volatility is the best measure of expected volatility.

(b) Share Purchase Warrants

The following table summarizes information about warrant transactions:

	Number of		Weighted average
	warrants		exercise price
			$
Balance at January 1, 2016 and December 31, 2016	15,719,540		0.85
Warrants cancelled	(13,000,000	)	0.45
Warrants expired	(2,719,540	)	2.59
Balance at December 31, 2017	-		-

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SUPPLEMENTAL INFORMATION

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

SUPPLEMENTAL INFORMATION [Text Block]

NOTE 14 – SUPPLEMENTAL INFORMATION

(a) Changes in working capital consisted of the following:

	Year ended December 31
	2017		2016		2015
	$		$		$
Changes in working capital:
Accounts receivable	284		1,530		(1,597	)
Prepaids and deposits	(10	)	12		110
Accounts payable and accrued liabilities	15		(758	)	(530	)
	289		784		(2,017	)
Comprised of:
Operating activities	219		667		204
Investing activities	32		178		(2,289	)
Financing activities	38		(61	)	68
	289		784		(2,017	)
Other cash flow information:
Cash paid for interest	480		596		417
Income taxes paid	-		-		-

(b) Per share amounts:

Basic loss per share amounts has been calculated by dividing the net loss for the year attributable to the shareholders’ of the Company by the weighted average number of common shares outstanding. Stock options and share purchase warrants were excluded from the calculation. The basic and diluted net loss per share is the same as the stock options and share purchase warrants were anti-dilutive. The following table summarizes the common shares used in calculating basic and diluted net loss per common share:

	Year ended December 31,
	2017	2016	2015
Weighted average common shares outstanding
Basic	61,682,462	42,095,366	36,492,207
Diluted	61,682,462	42,095,366	36,492,207

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RELATED PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

RELATED PARTY TRANSACTIONS [Text Block]

NOTE 15 – RELATED PARTY TRANSACTIONS

During the years ended December 31, 2017, 2016 and 2015 and in addition to the loans from related parties (note 9), the Company entered into the following transactions with related parties:

(a)

Compensation awarded to key management included a total of salaries and consulting fees of $466,000 (2016 - $470,000 and 2015 - $473,000) and non-cash stock-based compensation of $Nil (2016 - $80,000 and 2015 - $464,000). Key management includes the Company’s officers and directors. The salaries and consulting fees are included in general and administrative expenses. Included in accounts payable and accrued liabilities at December 31, 2017 is $131,000 (December 31, 2016 - $262,000 and December 31, 2015 - $200,000) owing to the two officers of the Company.

(b)

Interest expenses of $370,000 (2016 - $595,000 and 2015 - $343,000) related to the loans from related parties were paid in cash to the CEO of the Company and his spouse or the companies controlled by or associated with the CEO of the Company. And, interest expenses of $139,000 (2016 - $Nil and 2015 - $Nil) related to the loans from related parties were paid via issuance of the Company’s shares to the companies controlled by or associated with the CEO of the Company.

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INCOME TAXES

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

INCOME TAXES [Text Block]

NOTE 16 – INCOME TAXES

The actual income tax provisions differ from the expected amounts calculated by applying the Canadian combined federal and provincial corporate income tax rates to the Company’s loss before income taxes. The components of these differences are as follows:

	2017		2016		2015
	$		$		$
Loss before income taxes	(5,232	)	(5,486	)	(7,108	)
Corporate tax rate	26.44%		26.59%		26.00%
Expected tax recovery	(1,383	)	(1,459	)	(1,848	)
Increase (decrease) resulting from:
Differences in foreign tax rates and change in statutory tax rates	6,381		(231	)	(989	)
Impact of foreign exchange rate changes	1,277		506		(3,005	)
Change in unrecognized deferred tax assets	(6,507	)	1,290		4,509
Stock based compensation and expiry of losses	33		198		509
Non taxable/deductible amounts	199		(304	)	824
Deferred income tax recovery	-		-		-

On December 22, 2017, the United States government enacted the US Tax Cuts and Jobs Act (“Act”). The Act includes a range of legislative changes including a reduction of the US federal corporate income tax rate from 35% to 21% effective January 1, 2018. As a result of these legislative changes, the Company is required to revalue its United States deferred income tax assets and liabilities based on the rates they are expected to reverse at in the future, which is 21% for federal tax purposes. The impact for the Company’s 2017 financial statements is a reduction in deferred income tax assets of $6.38 million.

No deferred tax asset has been recognized in respect of the following losses and deductible temporary differences as it is not considered probable that sufficient future taxable profit will allow the deferred tax assets to be recovered.

	2017	2016	2015
	$	$	$
Deferred income tax assets
Non-capital losses available	20,998	26,679	26,547
Capital losses available	1,113	1,072	1,072
Resource tax pools in excess of net book value	5,279	4,846	3,726
Share issue costs and others	654	1,171	1,133
Unrecognized deferred tax assets	28,044	33,768	32,478

The Company has the approximate amounts of tax pools available as follows:

As at December 31	2017	2016	2015
	$	$	$
Canada:
Exploration and development expenditures	17,100	16,750	16,657
Unamortized share issue costs	261	292	455
Capital losses	8,242	8,242	8,242
Non-capital losses	33,120	30,783	29,148
	58,723	56,067	54,502
United States:
Exploration and development expenditures	15,883	17,149	18,560
Undeducted expenses	2,760	2,954	2,737
Non-capital losses	53,733	58,247	57,400
	72,376	78,350	78,697
Total	131,099	134,417	133,199

The exploration and development expenditures at December 31, 2017 can be carried forward to reduce future income taxes indefinitely. The non-capital losses for income tax purposes expire as follows:

	Canada	United States	Total
	$	$	$
2026	24	2,531	2,555
2027	3,606	3,374	6,980
2028	4,674	253	4,927
2029	3,780	3,266	7,046
2030	2,068	2,775	4,843
2031	2,408	2,794	5,202
2032	4,372	7,606	11,978
2033	2,167	16,215	18,382
2034	3,966	12,665	16,631
2035	2,292	543	2,835
2036	1,815	1,639	3,454
2037	1,948	72	2,020
	33,120	53,733	86,853

The Company does not recognize deferred tax assets related to the foregoing tax pools because it is not probable that future taxable profit will be available against which the tax pools can be utilized.

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COMMITMENTS

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

COMMITMENTS [Text Block]

NOTE 17 – COMMITMENTS

The following is a summary of the Company’s undiscounted contractual obligations and commitments as at December 31, 2017:

		Payments Due by Period
	1 Year	2-3 Years	4-5 Years	Total
	$	$	$	$
Debt repayments (1)	1,000	-	6,500	7,500
Interest payments (2)	50	-	-	50
Operating leases	88	92	-	180
Financial contract liability	6,752	-	-	6,752
	7,890	92	6,500	14,482

(1)	Short-term and long-term loans from related parties
(2)	Fixed interest payments on loan from related parties of $1,000,000

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OPERATING SEGMENTS

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

OPERATING SEGMENTS [Text Block]

NOTE 18 – OPERATING SEGMENTS

Segment information is provided on the basis of geographic segments as the Company manages its business through two geographic regions – Canada and the United States. The two geographic segments presented reflect the way in which the Company’s management reviews business performance. The Company’s revenue and losses of each geographic segment are as follows:

	Canada						United States						Total
	2017		2016		2015		2017		2016		2015		2017		2016		2015
	$		$		$		$		$		$		$		$		$
Year ended December 31
Revenues, net of royalties	1,814		3,190		6,606		666		883		490		2,480		4,073		7,096
Segmented loss	(4,948	)	(3,279	)	(1,769	)	(261	)	(2,207	)	(5,339	)	(5,209	)	(5,486	)	(7,108	)
Amortization, depletion and impairment losses	1,784		2,324		3,441		844		2,169		748		2,628		4,493		4,189
Interest expense	950		1,236		500		-		294		525		950		1,530		1,025
Capital expenditures	414		305		1,168		42		225		4,570		456		530		5,738

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DETERMINATION OF FAIR VALUES

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

DETERMINATION OF FAIR VALUES [Text Block]

NOTE 19 – DETERMINATION OF FAIR VALUES

A number of the Company’s accounting policies and disclosures require the determination of fair value. Fair values have been determined for measurement and/or disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes specific to that financial asset or financial liability. Due to the use of subjective judgments and uncertainties in the determination of these fair values the values should not be interpreted as being realizable in an immediate settlement of the financial instruments.

The Company classifies the fair value of financial instruments according to the following hierarchy based on the amount of observable inputs used to value the instruments:

• Level 1: Values based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities.

• Level 2: Values based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability.

• Level 3: Values based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement.

At December 31, 2017 and December 31, 2016, the derivative liability is measured using an option pricing model with significant unobservable inputs (Level 3). The financial contract liability is measured at the initial transaction price, which is deemed to be fair value, and subsequently measured based on netbacks in accordance with the Joint Operating Agreement. This model also has significant unobservable inputs (Level 3).

The following tables provide fair value measurement information for financial assets and liabilities as at December 31, 2017 and December 31, 2016:

			Quoted Prices in	Significant Other	Significant
	Carrying	Fair	Active Markets	Observable Inputs	Unobservable
December 31, 2017	Amount	Value	(Level 1)	(Level 2)	Inputs (Level 3)
	$	$	$	$	$
Financial Assets:
Cash and cash equivalents	1,010	1,010	1,010	-	-
Accounts receivable	388	388	388	-	-
Financial Liabilities:
Accounts payable and accrued liabilities	1,291	1,291	1,291	-	-
Loans from related parties	4,608	4,608	-	-	4,608
Financial contract liability	6,752	6,752	-	-	6,752

			Quoted Prices in	Significant Other	Significant
	Carrying	Fair	Active Markets	Observable Inputs	Unobservable
December 31, 2016	Amount	Value	(Level 1)	(Level 2)	Inputs (Level 3)
	$	$	$	$	$
Financial Assets:
Cash and cash equivalents	141	141	141	-	-
Accounts receivable	672	672	672	-	-
Financial Liabilities:
Accounts payable and accrued liabilities	2,165	2,165	2,165	-	-
Loans from related parties	6,394	6,394	-	-	6,394
Derivative liability	153	153	-	-	153
Financial contract liability	7,226	7,226	-	-	7,226

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FINANCIAL INSTRUMENTS AND CAPITAL MANAGEMENT

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

FINANCIAL INSTRUMENTS AND CAPITAL MANAGEMENT [Text Block]

NOTE 20 – FINANCIAL INSTRUMENTS AND CAPITAL MANAGEMENT

The Company operates in the United States, giving rise to exposure to market risks from changes in foreign currency rates. Currently, the Company does not use derivative instruments to reduce its exposure to foreign currency risk.

The Company also has exposure to a number of risks from its use of financial instruments including: credit risk, liquidity risk, and market risk. This note presents information about the Company’s exposure to each of these risks and the Company’s objectives, policies and processes for measuring and managing risk, and the Company’s management of capital.

(a) Credit Risk

Credit risk arises from credit exposure to receivables due from joint operating partners and marketers included in accounts receivable. The maximum exposure to credit risk is equal to the carrying value of the financial assets.

The Company is exposed to third party credit risk through its contractual arrangements with its current or future joint operating partners, marketers of its petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to the Company, such failures may have a material adverse effect on the Company’s business, financial condition, and results of operations.

The objective of managing the third party credit risk is to minimize losses in financial assets. The Company assesses the credit quality of the partners, taking into account their financial position, past experience, and other factors. The Company mitigates the risk of non-collection of certain amounts by obtaining the joint operating partners’ share of capital expenditures in advance of a project and by monitoring accounts receivable on a regular basis. As at December 31, 2017 and 2016, no accounts receivable has been deemed uncollectible or written off during the year.

As at December 31, 2017, the Company’s receivables consist of $196,000 (2016 - $244,000) from joint operating partners, $121,000 (2016 - $276,000) from oil and natural gas marketers and $71,000 (2016 - $152,000) from other trade receivables. The Company considers all amounts outstanding for more than 90 days as past due. Currently, there is no indication that amounts are non-collectable; thus a provision for doubtful accounts has not been set up. As at December 31, 2017, $Nil (2016 - $Nil) of accounts receivable are past due.

(b) Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they are due. The nature of the oil and gas industry is capital intensive and the Company maintains and monitors a certain level of cash flow to finance operating and capital expenditures.

The Company’s ongoing liquidity and cash flow are impacted by various events and conditions. These events and conditions include but are not limited to commodity price fluctuations, general credit and market conditions, operation and regulatory factors, such as government permits, the availability of drilling and other equipment, lands and pipeline access, weather, and reservoir quality.

To mitigate the liquidity risk, the Company closely monitors its credit facility, production level and capital expenditures to ensure that it has adequate liquidity to satisfy its financial obligations.

(c) Market Risk

Market risk is the risk that changes in market prices, such as foreign exchange rates, commodity prices, and interest rates will affect the Company’s net earnings. The objective of market risk management is to manage and control market risk exposures within acceptable limits, while maximizing returns. The Company utilizes financial derivatives to manage certain market risks. All such transactions are conducted in accordance with the risk management policy that has been approved by the Board of Directors.

(i) Foreign Currency Exchange Risk

Foreign currency exchange rate risk is the risk that the fair value of financial instruments or future cash flows will fluctuate as a result of changes in foreign exchange rates. Although substantially all of the Company’s oil and natural gas sales are denominated in Canadian dollars, the underlying market prices in Canada for oil and natural gas are impacted by changes in the exchange rate between the Canadian and United States dollars. Given that changes in exchange rate have an indirect influence, the impact of changing exchange rates cannot be accurately quantified. The Company had no forward exchange rate contracts in place as at or during the year ended December 31, 2017 and 2016.

The Company was exposed to the following foreign currency risk at December 31:

	2017		2016
Expressed in foreign currencies	CND$		CND$
Cash and cash equivalents	30		1
Accounts receivable	228		282
Accounts payable and accrued liabilities	(213	)	(312	)
Balance sheet exposure	45		(29	)

The following foreign exchange rates applied for the year ended and as at December 31:

	2017	2016
December 31, reporting date rate	1.2545	1.3427
YTD average USD to CAD	1.2986	1.3253

The Company has performed a sensitivity analysis on its foreign currency denominated financial instruments. Based on the Company’s foreign currency exposure noted above and assuming that all other variables remain constant, a 10% appreciation of the US dollar against the Canadian dollar would result in the decrease of net loss of $5,000 at December 31, 2017 (2016 – increase of net loss of $3,000). For a 10% depreciation of the above foreign currencies against the Canadian dollar, assuming all other variables remain constant, there would be an equal and opposite impact on net loss.

(ii) Interest Rate Risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. At December 31, 2017, the Company was exposed to interest rate fluctuations on the loans from related parties which bore a floating rate of interest. Assuming all other variables remain constant, an increase or decrease of 1% in market interest rate at December 31, 2017 would have increased or decreased net loss by $65,000. The Company had no interest rate swap contracts in place at or during the year ended December 31, 2017 and 2016.

(iii) Commodity Price Risk

Revenues and consequently cash flows fluctuate with commodity prices and the US/Canadian dollar exchange rate. Commodity prices are determined on a global basis and circumstances that occur in various parts of the world are outside of the control of the Company. The Company may protect itself from fluctuations in prices by using the financial derivative sales contracts. The Company may enter into commodity price contracts to manage the risks associated with price volatility and thereby protect its cash flows used to fund its capital program. Assuming all other variables remain constant, an increase or decrease of oil price of $1 per bbl and gas price of $0.01 per mcf at December 31, 2017 would have decreased or increased net loss by $34,000. The Company had no commodity contracts in place at December 31, 2017.

(d) Capital Management Strategy

The Company’s policy on capital management is to maintain a prudent capital structure so as to maintain financial flexibility, preserve access to capital markets, maintain investor, creditor and market confidence, and to allow the Company to fund future developments. The Company considers its capital structure to include share capital, cash and cash equivalents, and working capital. In order to maintain or adjust capital structure, the Company may from time to time issue shares or enter into debt agreements and adjust its capital spending to manage current and projected operating cash flows and debt levels.

The Company’s share capital is not subject to any external restrictions. The Company has not paid or declared any dividends, nor are any contemplated in the foreseeable future. There have been no changes to the Company’s capital management strategy during the year ended December 31, 2017.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

Basis of consolidation [Policy Text Block]

(a) Basis of consolidation

The consolidated financial statements include the financial statements of the Company and subsidiaries controlled by the Company. Subsidiaries are fully consolidated from the date of acquisition, being the date on which the Company obtains control, and continue to be consolidated until the date that such control ceases. All intra-group balances, transactions, income and expenses are eliminated in full on consolidation.

The financial statements of the subsidiaries are prepared using the same reporting period as the parent company, using consistent accounting policies.

Exploration, development, and production activities may be conducted jointly with others and accordingly, the Company accounts for the assets, liabilities, revenues and expenses related to its interest in the joint operations from the date that joint control commences until the date that it ceases.

Foreign currency [Policy Text Block]

(b) Foreign currency

The financial statements of entities within the consolidated group that have a functional currency different from that of the Company (“foreign operations”) are translated into Canadian dollars as follows: assets and liabilities – at the closing rate as at the balance sheet date, and income and expenses – at the average rate of the period (as this is considered a reasonable approximation to actual rates). All resulting changes are recognized in other comprehensive loss as cumulative translation differences.

When the Company disposes of its entire interests in a foreign operation, or loses control, joint control, or significant influence over a foreign operation, the foreign currency gains or losses accumulated in other comprehensive loss related to the foreign operation are recognized in profit or loss. If an entity disposes of part of an interest in a foreign operation which remains a subsidiary, a proportionate amount of foreign currency gains or losses accumulated in other comprehensive income related to the subsidiary are reallocated between controlling and non-controlling interests.

Transactions in foreign currencies are translated into the functional currency at exchange rates at the date of the transactions. Foreign currency differences arising on translation are recognized in profit or loss. Foreign currency monetary assets and liabilities are translated at the functional currency exchange rate at the balance sheet date. Non- monetary items that are measured at historical cost in a foreign currency are translated using the exchange rates as at the dates of the initial transactions. Non-monetary items measured at fair value in a foreign currency are translated using the exchange rates at the date when the fair value was determined.

Exchange differences recognized in the profit or loss statement of the Company’s entities’ separate financial statements on the translation of monetary items forming part of the Company’s net investment in the foreign operation are reclassified to foreign exchange reserve on consolidation.

Cash and cash equivalents [Policy Text Block]

(c) Cash and cash equivalents

Cash and cash equivalents consist of cash and highly liquid investments having maturity dates of three months or less from the date of acquisition that are readily convertible to cash.

Resource properties [Policy Text Block]

(d) Resource properties

Exploration and evaluation (“E&E”) costs

Pre-license costs are expensed in the period in which they are incurred.

E&E costs are initially capitalized as either tangible or intangible E&E assets according to the nature of the assets acquired. Intangible E&E assets may include costs of license acquisition, technical services and studies, seismic acquisition, exploration drilling and testing, and directly attributable overhead and administration expenses. The costs are accumulated in cost centers by well, field or exploration area pending determination of technical feasibility and commercial viability.

E&E assets are assessed for impairment if sufficient data exists to determine technical feasibility and commercial viability or facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For purposes of impairment testing, E&E assets are assessed at the individual asset level. If it is not possible to estimate the recoverable amount of the individual asset, exploration and evaluation assets are allocated to cash-generating units (“CGU’s”). Such CGU’s are not larger than an operating segment.

Exploration assets are not depleted and are carried forward until technical feasibility and commercial viability of extracting a mineral resource is considered to be determinable or sufficient/continued progress is made in assessing the commercial viability of the E&E assets. The technical feasibility and commercial viability of extracting a mineral resource is considered to be determinable when proven reserves are determined to exist. A review of each exploration license or field is carried out, at least annually, to confirm whether the Company intends further appraisal activity or to otherwise extract value from the property. When this is no longer the case, the costs are written off. Upon determination of proven reserves, E&E assets attributable to those reserves are first tested for impairment and then reclassified from E&E assets to oil and natural gas properties.

The Company may occasionally enter into arrangements, whereby the Company will transfer part of an oil and gas interest, as consideration, for an agreement by the transferee to meet certain E&E expenditures which would have otherwise been undertaken by the Company. The Company does not record any expenditures made by the transferee. Any cash consideration received from the agreement is credited against the costs previously capitalized to the oil and gas interest given up by the Company, with any excess cash accounted for as a gain on disposal.

Oil and gas properties and other property and equipment costs

Items of property and equipment, which include oil and gas development and production assets, are measured at cost less accumulated depletion and depreciation and accumulated impairment losses.

The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of the decommissioning obligation and, for qualifying assets, borrowing costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset. When significant parts of an item of property and equipment, including oil and natural gas interests, have different useful lives, they are accounted for as separate items (major components).

Depletion and Depreciation

Oil and gas development and production assets are depreciated, by significant component, on a unit-of-production basis over proved and probable reserve volumes, taking into account estimated future development costs necessary to bring those reserves into production. Future development costs are estimated by taking into account the level of development required to produce the reserves. These estimates are reviewed by independent reserve engineers at least annually. Changes in reserve estimates are dealt with prospectively. Proved and probable reserves are estimated using independent reserve engineer reports and represent the estimated quantities of oil, natural gas and gas liquids.

Other property and equipment are depreciated based on a declining balance basis, which approximates the estimated useful lives of the asset, at the following rates:

Office furniture and equipment	20%
Computer equipment	45%
Vehicle	30%
Leasehold improvements	term of lease

Depreciation methods, useful lives and residual values are reviewed at each reporting date. Other property and equipment are allocated to each of the Company’s primary cash-generating units, based on estimated future net revenue, consistent with the recoverable values applied in the most recent impairment test.

Derecognition

The carrying amount of an item of property and equipment is derecognized on disposal, when no beneficial interest is retained, or when no future economic benefits are expected from its use or disposal. The gain or loss arising from derecognition is included in profit or loss when the item is derecognized and is measured as the difference between the net disposal proceeds, if any, and the carrying amount of the item. The date of disposal is the date when the Company is no longer subject to the risks of ownership and is no longer the beneficiary of the rewards of ownership. Where the asset is derecognized, the date of disposal coincides with the date the revenue from the sale of the asset is recognized.

On the disposition of an undivided interest in a property, where an economic benefit remains, the Company recognizes the farm out only on the receipt of consideration by reducing the carrying amount of the related property with any excess recognized in profit or loss of the period.

Major maintenance and repairs

The costs of day-to-day servicing are expensed as incurred. These primarily include the costs of labor, consumables and small parts. Material costs of replaced parts, turnarounds and major inspections are capitalized as it is probable that future economic benefits will be received. The carrying value of a replaced part is derecognized in accordance with the derecognition principles above.

Jointly controlled operations

The Company conducts its oil and gas development and production activities through jointly controlled operations and the accounts reflect only its interest in such activities. A joint arrangement exists where the parties take their share of the output and is accounted for by recognizing the Company’s share of assets and liabilities jointly owned and incurred, and the recognition of its share of revenue and expenses of the joint operation. At December 31, 2017, the Company’s material joint operation in Canada is Drake/Woodrush. The principal activity is oil and gas production and the ownership percentage is 99% (December 31, 2016 – 99%).

Provisions [Policy Text Block]

(e) Provisions

A provision is recognized if, as a result of a past event, the Company 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. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risk specific to the liability.

Decommissioning liability

A decommissioning liability is recognized when the Company has a present legal or constructive obligation as a result of past events, it is probable that an outflow of resources will be required to settle the obligation, and a reliable estimate of the amount of obligation can be made. A corresponding amount equivalent to the provision is also recognized as part of the cost of the related asset. The amount recognized is management’s estimated cost of decommissioning, discounted to its present value using a risk free rate. Changes in the estimated timing of decommissioning or decommissioning cost estimates are dealt with prospectively by recording an adjustment to the provision and a corresponding adjustment to the related asset unless the change arises from production. The unwinding of the discount on the decommissioning provision is included as a finance cost. Actual costs incurred upon settlement of the decommissioning liability are charged against the provision to the extent the provision was established.

Earnings (loss) per share [Policy Text Block]

(f) Earnings (loss) per share

Basic earnings (loss) per share figures have been calculated using the weighted average number of common shares outstanding during the respective periods.

Diluted earnings (loss) per common share is calculated by dividing the profit or loss applicable to common shares by the sum of the weighted average number of common shares issued and outstanding and all additional common shares that would have been outstanding if potentially dilutive instruments were converted. The diluted earnings (loss) per share figure is equal to that of basic earnings (loss) per share since the effects of options and warrants have been excluded as they are anti-dilutive.

Share based payments [Policy Text Block]

(g) Share based payments

Where equity-settled share options are awarded to employees, the fair value of the options at the date of grant is charged to profit or loss over the vesting period. Performance vesting conditions are taken into account by adjusting the number of equity instruments expected to vest at each reporting date so that, ultimately, the cumulative amount recognized over the vesting period is based on the number of options that will eventually vest. Where equity instruments are granted to employees, they are recorded at the instruments grant date fair value.

Where the terms and conditions of options are modified before they vest, the increase in the fair value of the options, measured immediately before and after the modification, is also charged to profit or loss over the remaining vesting period.

Where equity instruments are granted to non-employees, they are recorded at the fair value of the goods or services received in profit or loss, unless they are related to the issuance of shares. Amounts related to the issuance of shares are recorded as a reduction of share capital.

When the value of goods or services received in exchange for the share-based payment to non-employees cannot be reliably estimated, the fair value of the share-based payment is measured by use of a valuation model to measure the value of the equity instruments issued. The expected life used in the model is adjusted, based on management’s best estimate, for the effects of non-transferability, exercise restrictions, and behavioural considerations.

All equity-settled share based payments are reflected in contributed surplus, until exercised. Upon exercise, shares are issued from treasury and the amount reflected in contributed surplus is credited to share capital along with any consideration received.

Where a grant of options is cancelled or settled during the vesting period, excluding forfeitures when vesting conditions are not satisfied, the Company immediately accounts for the cancellation as an acceleration of vesting and recognizes the amount that otherwise would have been recognized for services received over the remainder of the vesting period. Any payment made to the employee on the cancellation is accounted for as the repurchase of an equity interest except to the extent the payment exceeds the fair value of the equity instrument granted, measured at the repurchase date. Any such excess is recognized as an expense.

Revenue recognition [Policy Text Block]

(h) Revenue recognition

Revenue from the sale of oil and petroleum products is recognized when the significant risks and rewards of ownership have been transferred, which is when title passes to the customer. This generally occurs when the product is physically transferred into a vessel, pipe or other delivery mechanism. Revenue is stated after deducting sales taxes, excise duties and similar levies.

Revenue from the production of oil and natural gas in which the Company has an interest with other producers is recognized based on the Company’s working interest and the terms of the relevant production sharing contracts.

Financial instruments [Policy Text Block]

(i) Financial instruments

Financial assets

Financial assets are classified as one of the following categories. All transactions related to financial instruments are recorded on a trade date basis. The Company's accounting policy for each category is as follows:

Loans and receivables

These assets are non-derivative financial assets resulting from the delivery of cash or other assets by a lender to a borrower in return for a promise to repay on a specified date or dates, or on demand. They are initially recognized at fair value plus transaction costs that are directly attributable to their acquisition or issue and subsequently carried at amortized cost, using the effective interest rate method, less any impairment losses. Amortized cost is calculated taking into account any discount or premium on acquisition and includes fees that are an integral part of the effective interest rate and transaction costs. Gains and losses are recognized in profit or loss when the loans and receivables are derecognized or impaired, as well as through the amortization process. The Company’s loans and receivables comprise cash and cash equivalents and accounts and other receivables.

Held-to-maturity investments

Held to maturity investments are initially measured at fair value and are subsequently measured at amortized cost using the effective interest rate method, less any impairment losses. The Company does not currently have any held-to-maturity investments.

Available-for-sale assets

Available-for-sale assets are measured at fair value, with unrealized gains and losses recorded in other comprehensive income (loss) until the asset is realized or impairment is viewed as other than temporary, at which time they will be recorded in profit or loss. The Company does not currently have any available-for-sale assets.

Financial assets at fair value through profit or loss

An instrument is classified at fair value through profit or loss if it is held for trading or is designated as such upon initial recognition. Financial instruments are designated at fair value through profit or loss if the Company manages such investments and makes purchase and sale decisions based on their fair value in accordance with the Company’s risk management or investment strategy. Upon initial recognition, attributable transaction costs are recognized in profit or loss when incurred. Financial instruments at fair value through profit or loss are measured at fair value, and changes therein are recognized in profit or loss. The Company does not have any financial assets at fair value through profit or loss.

Financial liabilities

Financial liabilities are classified as either fair value through profit or loss or other financial liabilities, based on the purpose for which the liability was incurred.

The Company’s other financial liabilities comprise accounts payable and accrued liabilities, bank credit facility, loans from related parties and financial contract liability. These liabilities are initially recognized at fair value, net of any transaction costs directly attributable to the issuance of the instrument and subsequently carried at amortized cost using the effective interest rate method, which ensures that any financing expense over the period of repayment is at a constant rate on the balance of the liability carried in the balance sheet. Interest expense in this context includes initial transaction costs and premiums payable on redemption, as well as any interest or coupon payable while the liability is outstanding. Any revision to the amount or timing of cash flows related to an instrument is reflected in its carrying amount by computing the present value of the revised cash flows at the instrument’s initial effective interest rate. The change in carrying amount is reflected in profit or loss of the period. Accounts payable represent liabilities for goods and services provided to the Company prior to the end of the period which are unpaid. Accounts payable amounts are unsecured and are usually paid within 30 days from receipt of invoice.

Financial liabilities are classified as held-for-trading if they are acquired for the purpose of selling in the near term. Derivatives are also categorized as held for trading unless they are designated as hedges.

The Company has derivative financial instruments in the form of warrants issued in US dollars, or with certain adjustment provisions, and contracts entered into to manage its exposure to volatility in commodity prices. Commodity contracts are not used for trading or other speculative purposes. Such derivative financial instruments are initially recognized at fair value at the date at which the derivatives are issued and are subsequently re-measured at fair value. These derivatives do not qualify for hedge accounting and changes in fair value are recognized immediately in profit and loss.

For outstanding warrants at each reporting period, the change in the fair value of the liability between reporting periods is recorded in the consolidated statement of comprehensive income (loss). As warrants are exercised, immediately before exercise, the liability on these exercised warrants is re-measured and the valuation change is recorded in the consolidated statement of comprehensive income (loss). Upon exercise, the re-measured warrant liability on these exercised warrants is eliminated and there is an offsetting entry to share capital.

Financial instrument measurement

If the market value for a financial instrument is not an active market the Company establishes fair value by using a valuation technique. Valuation techniques include using recent arm’s length market transaction between knowledgeable, willing parties, if available, reference to the current fair value of another instrument that is substantially the same, discounted cash flow analysis and option pricing models. The fair value of a financial instrument will be based on one or more factors that may include the time value of money, credit risk, commodity prices, equity prices, volatility, servicing costs and other factors.

Impairment [Policy Text Block]

(j) Impairment

Impairment of financial assets

At each reporting date, the Company assesses whether there is objective evidence that a financial asset is impaired. If such evidence exists, the Company recognizes an impairment loss, as follows:

Financial assets are carried at amortized cost. The loss is the difference between the amortized cost of the loan or receivable and the present value of the estimated future cash flows, discounted using the instrument’s original effective interest rate. The carrying amount of the asset is reduced by this amount either directly or indirectly through the use of an allowance account.

Impairment losses on financial assets carried at amortized cost are reversed in subsequent periods if the amount of the loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognized.

Non-financial assets

For the purpose of impairment testing, assets are grouped together in CGUs, which are the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets. The carrying value of long-term assets is reviewed at each period for indicators that the carrying value of an asset or a CGU may not be recoverable. The Company uses geographical proximity, geological similarities, analysis of shared infrastructure, commodity type, assessment of exposure to market risks and materiality to define its CGUs. If indicators of impairment exist, the recoverable amount of the asset or CGU is estimated. If the carrying value of the asset or CGU exceeds the recoverable amount, the asset or CGU is written down with an impairment recognized in profit or loss.

The recoverable amount of an asset or CGU is the greater of its value in use and its fair value less costs to sell. Fair value is determined to be the amount for which the asset could be sold in an arm’s length transaction. For resource properties, fair value less costs to sell may be determined by using discounted future net cash flows of proved and probable reserves using forecast prices and costs. Value in use is determined by estimating the net present value of future net cash flows expected from the continued use of the asset or CGU.

Impairment losses recognized in prior years are assessed at each reporting date for any indication that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimate used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation, if no impairment loss had been recognized.

Taxes [Policy Text Block]

(k) Taxes

Income taxes

Income tax expense comprises current and deferred tax. Income tax expense is recognized in profit or loss except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity.

Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.

Deferred tax is recognized for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on temporary differences on the initial recognition of assets or liabilities in a transaction that is not a business combination and affects neither accounting profit nor taxable profit. In addition, deferred tax is not recognized for taxable temporary differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when the asset is realized or the liability is settled, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, when they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously.

A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

Production taxes

Royalties, resource rent taxes and revenue-based taxes are accounted for under International Accounting Standards (‘IAS’) 12 when they have characteristics of an income tax. This is considered to be the case when they are imposed under Government authority and the amount is payable based on taxable income, rather than based on quantity produced or as a percentage of revenue, after adjustment for temporary differences. For such arrangements, current and deferred tax is provided on the same basis as described above for other forms of taxation. Obligations arising from royalty arrangements that do not satisfy these criteria are recognized as a reduction of revenues.

Share capital [Policy Text Block]

(l) Share capital

The Company’s common shares, stock options, share purchase warrants and flow-through shares are classified as equity instruments only to the extent that they do not meet the definition of a financial liability or financial asset. Incremental costs directly attributable to the issue of equity instruments are shown in equity as a deduction, net of tax, from the proceeds.

Flow-through shares [Policy Text Block]

(m) Flow-through shares

The Company will from time to time, issue flow-through common shares to finance a portion of its exploration program. Pursuant to the terms of the flow-through share agreements, these shares transfer the tax deductibility of qualifying resource expenditures to investors. On issuance, the Company separates the flow-through share into i) a flow-through share premium, equal to the estimated premium, if any, investors pay for the flow-through feature, which is recognized as a liability and; ii) share capital. Upon expenditures being incurred, the Company derecognizes the liability and recognizes a deferred income tax recovery for the amount of tax reduction renounced to the shareholders.

Adoption of new and amended standards [Policy Text Block]

(n) Adoption of new and amended standards

There were no new or amended accounting standards or interpretations that had a significant impact on the Company’s consolidated financial statements during the year ended December 31, 2017.

Future accounting pronouncements [Policy Text Block]

(o) Future accounting pronouncements

Certain pronouncements were issued by “IASB” or “IFRIC” that are mandatory for accounting periods beginning after January 1, 2018 or later periods. The following new accounting standards, amendments to accounting standards and interpretations, have not been early adopted in these consolidated financial statements:

IFRS 9, “Financial Instruments”: In July 2014, the IASB completed the final phase of its project to replace IAS 39, the current standard on the recognition and measurement of financial instruments. IFRS 9 is now the new standard which sets out the recognition and measurement requirements for financial instruments and some contracts to buy or sell non-financial items. IFRS 9 provides a single model of classifying and measuring financial assets and liabilities and provides for only two classification categories: amortized cost and fair value. Hedge accounting requirements have also been updated in the new standard and are now more aligned with the risk management activities of an entity. IFRS 9 is effective for annual periods beginning on or after January 1, 2018. Early adoption is permitted; however, if an entity elects to apply this standard early, it must disclose that fact and apply all of the requirements in this standard at the same time. The Company has determined that there will not be any material impact on its consolidated financial statements as a result of the adoption of IFRS 9.

IFRS 15, “Revenue from Contracts with Customers”: the standard was issued in May 2014 and amended in April 2016. IFRS 15 applies to contracts with customers, excluding, most notably, insurance and leasing contracts. IFRS 15 prescribes a framework in accounting for revenues from contracts within its scope, including (a) identifying the contract, (b) identify separate performance obligations in the contract, (c) determine the transaction price of the contract, (d) allocate the transaction price to the performance obligations and (e) recognize revenues when each performance obligation is satisfied. IFRS 15 also prescribes additional financial statement presentations and disclosures. The Company currently expects to adopt IFRS 15 as of January 1, 2018, under the modified retrospective method where the cumulative effect is recognized at the date of initial application. The Company has completed the evaluation of IFRS 15. It has been concluded that the adoption of IFRS 15 will not have a material effect on the Company’s consolidated financial statements.

IFRS 16, “Leases”: In January 2016, the IASB issued the standard to replace IAS 17 “Leases”. For lessees applying IFRS 16, a single recognition and measurement model for leases would apply, with required recognition of assets and liabilities for most leases. The standard will come into effect for annual periods beginning on or after January 1, 2019, with earlier adoption permitted. It is anticipated that the adoption of IFRS 16 will have impact on the Company’s consolidated balance sheet due to the operating lease commitments as disclosed in note 17.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

Disclosure of detailed information about estimated useful life or depreciation rate [Table Text Block]

Office furniture and equipment	20%
Computer equipment	45%
Vehicle	30%
Leasehold improvements	term of lease

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EXPLORATION AND EVALUATION (E&E) ASSETS (Tables)

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

Disclosure of detailed information about exploration assets [Table Text Block]

	Canadian Oil	United States
	and Gas	Oil and Gas
	Properties	Properties		Total
	$	$		$
Cost:
Balance at January 1, 2016	281	18,982		19,263
Additions	2	-		2
Change in decommissioning provision	13	-		13
Disposals	-	(772	)	(772	)
Foreign currency translation and other	-	(768	)	(768	)
Balance at December 31, 2016	296	17,442		17,738
Additions	4	3		7
Change in decommissioning provision	56	-		56
Disposals	-	-		-
Foreign currency translation and other	-	(1,174	)	(1,174	)
Balance at December 31, 2017	356	16,271		16,627

Disclosure of detailed information about impairment on exploration and evaluation assets [Table Text Block]

	Canadian Oil		United States
	and Gas		Oil and Gas
	Properties		Properties		Total
	$		$		$
Accumulated impairment losses:
Balance at January 1, 2016	-		(16,041	)	(16,041	)
Impairment losses	-		(1,790	)	(1,790	)
Disposals	-		513		513
Foreign currency translation and other	-		550		550
Balance at December 31, 2016	-		(16,768	)	(16,768	)
Impairment losses (Note 7)	(350	)	(621	)	(971	)
Disposals	-		-		-
Foreign currency translation and other	-		1,120		1,120
Balance at December 31, 2017	(350	)	(16,269	)	(16,619	)

Disclosure of detailed information about carrying amounts of exploration and evaluation assets [Table Text Block]

	Canadian Oil	United States
	and Gas	Oil and Gas
	Properties	Properties	Total
	$	$	$
Carrying amounts:
At December 31, 2016	296	674	970
At December 31, 2017	6	2	8

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PROPERTY AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

Disclosure of detailed information about property, plant and equipment [Table Text Block]

	Canadian Oil		United States
	and Gas		Oil and Gas		Corporate and
	Properties		Properties		Other Assets		Total
	$		$		$		$
Cost:
Balance at January 1, 2016	33,376		16,653		179		50,208
Additions	300		225		3		528
Change in decommissioning provision	(48	)	(4	)	-		(52	)
Foreign currency translation and other	-		(502	)	-		(502	)
Balance at December 31, 2016	33,628		16,372		182		50,182
Additions	405		39		5		449
Change in decommissioning provision	94		(3	)	-		91
Disposals	-		-		(29	)	(29	)
Foreign currency translation and other	-		(1,060	)	-		(1,060	)
Balance at December 31, 2017	34,127		15,348		158		49,633

Disclosure of detailed information about accumulated amortization, depletion and impairment losses of property and equipment [Table Text Block]

	Canadian Oil		United States
	and Gas		Oil and Gas		Corporate and
	Properties		Properties		Other Assets		Total
	$		$		$		$
Accumulated amortization, depletion and impairment
losses:
Balance at January 1, 2016	(26,774	)	(1,375	)	(160	)	(28,309	)
Amortization and depletion	(1,248	)	(380	)	(5	)	(1,633	)
Impairment losses	(1,070	)	-		-		(1,070	)
Foreign currency translation and other	-		41		1		42
Balance at December 31, 2016	(29,092	)	(1,714	)	(164	)	(30,970	)
Amortization and depletion (Note 7)	(561	)	(223	)	(3	)	(787	)
Impairment losses (Note 7)	(870	)	-		-		(870	)
Disposals	-		-		25		25
Foreign currency translation and other	-		131		-		131
Balance at December 31, 2017	(30,523	)	(1,806	)	(142	)	(32,471	)

Disclosure of detailed information about carrying amount of property and equipment [Table Text Block]

	Canadian Oil	United States
	and Gas	Oil and Gas	Corporate and
	Properties	Properties	Other Assets	Total
	$	$	$	$
Carrying amounts:
At December 31, 2016	4,536	14,658	18	19,212
At December 31, 2017	3,604	13,542	16	17,162

Disclosure of detailed information about commodity price estimates [Table Text Block]

	Natural gas	NGL	Crude oil
	(AECO)	(Edmonton Pentanes Plus)	(Edmonton Par)
	Cdn $ / mmbtu	Cdn $ / bbl	Cdn $ / bbl
2018	2.20	76.42	70.25
2019	2.54	74.68	70.25
2020	2.88	74.38	70.31
2021	3.24	77.16	72.84
2022	3.47	79.88	75.61
2023	3.58	82.53	78.31
2024	3.66	86.14	81.93
2025	3.73	89.76	85.54
2026	3.80	92.57	88.35
2027	3.88	94.43	90.22
Each benchmark price increased on average approximately 2% thereafter

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AMORTIZATION, DEPLETION AND IMPAIRMENT LOSSES (Tables)

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

Disclosure of impairment of assets [Table Text Block]

	Year ended December 31
	2017	2016	2015
	$	$	$
Exploration and Evaluation Assets (E & E assets)
Impairment losses (Note 5)	971	1,790	534
Property and Equipment (D & P assets)
Amortization and depletion (Note 6)	787	1,633	2,655
Impairment losses (Note 6)	870	1,070	1,000
	2,628	4,493	4,189

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LOANS FROM RELATED PARTIES (Tables)

12 Months Ended

Dec. 31, 2017

Hodgkinson Equity Corporation (HEC) [Member]

Statement [Line Items]

Disclosure of detailed information about gain loss on debt extinguishment [Table Text Block]

	$
Face value of amended loan	2,346
Conversion feature	2,158
Carrying value of old loan before restructure	(3,976	)
Loss on extinguishment	528

Disclosure of detailed information about debt activity [Table Text Block]

	$
Balance upon initial recognition	2,337
Accretion expense	265
Cash interest	(104	)
Balance at December 31, 2017	2,498
Current portion	(317	)
Non-current portion	2,181

Hodgkinson Ventures Inc. (HVI) [Member]

Statement [Line Items]

Disclosure of detailed information about gain loss on debt extinguishment [Table Text Block]

	$
Face value of amended loan	1,043
Conversion feature	960
Carrying value of old loan before restructure	(1,613	)
Loss on extinguishment	390

Disclosure of detailed information about debt activity [Table Text Block]

	$
Balance upon initial recognition	1,039
Accretion expense	117
Cash interest	(46	)
Balance at December 31, 2017	1,110
Current portion	(141	)
Non-current portion	969

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FLOW-THROUGH SHARES LIABILITY (Tables)

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

Disclosure of detailed information about liability portion of the flow-through shares issuances [Table Text Block]

	Issued in		Issued in
	October		December	Total
	2017		2017
	$		$	$
Balance at January 1, 2017	-		-	-
Liability incurred on flow-through shares issued	21		93	114
Settlement of flow-through share liability on incurring expenditures	(21	)	-	(21	)
Balance at December 31, 2017	-		93	93

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DECOMMISSIONING LIABILITY (Tables)

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

Disclosure of detailed information about decommissioning liability [Table Text Block]

	Canadian		United States
	Oil and Gas		Oil and Gas
	Properties (1)		Properties (1)		Total
	$		$		$
Balance at January 1, 2016	3,679		146		3,825
Change in estimated future cash flows	(36	)	(4	)	(40	)
Actual costs incurred and other	(53	)	(5	)	(58	)
Unwinding of discount	46		3		49
Balance at December 31, 2016	3,636		140		3,776
Change in estimated future cash flows	146		(3	)	143
Actual costs incurred and other	(3	)	(8	)	(11	)
Unwinding of discount	60		3		63
Balance at December 31, 2017	3,839		132		3,971

Disclosure of detailed information about present value of the decommissioning liability [Table Text Block]

	Canadian Oil	United States
	and Gas	Oil and Gas
	Properties	Properties
As at December 31, 2017:
Discount rate	1.94%	2.20%
Inflation rate	2.00%	2.00%
As at December 31, 2016:
Discount rate	1.60%	2.34%
Inflation rate	2.00%	2.00%

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FINANCIAL CONTRACT LIABILITY (Tables)

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

Disclosure of detailed information about financial contract liability [Table Text Block]

	$
Balance at January 1, 2016 (US$5,207)	7,207
Accretion expense (US$222)	296
Foreign exchange gain	(214	)
Adjustment to financial contract liability (US$47)	(63	)
Balance at December 31, 2016 (US$5,382)	7,226
Foreign exchange gain	(474	)
Balance at December 31, 2017 (US$5,382)	6,752

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STOCK OPTIONS AND SHARE PURCHASE WARRANTS (Tables)

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

Disclosure of number and weighted average exercise prices of share options [Table Text Block]

			Weighted
	Number of		average
	options		exercise price
			$
Balance at January 1, 2016	140,738		1.20
Options granted	3,400,000		0.16
Options cancelled	(52,818	)	1.26
Options forfeited	(87,920	)	1.16
Balance at December 31, 2016 and December 31, 2017	3,400,000		0.16

Disclosure of number and weighted average remaining contractual life of outstanding share options [Table Text Block]

	Outstanding			Exercisable
		Weighted average			Weighted average
	Number	exercise	contractual	Number	exercise	contractual
	of options	price	life (years)	of options	price	life (years)
		$			$
$0.16	3,400,000	0.16	3.43	3,400,000	0.16	3.43

Disclosure of detailed information about options, valuation assumptions [Table Text Block]

For the year ended December 31		2016
Fair value at grant date	$	0.06
Expected volatility		80.35%
Expected option life		1.37 years
Dividends		0.0%
Risk-free interest rate		0.54%
Estimated forfeiture rate		6.85%

Disclosure of detailed information about warrants, activity [Table Text Block]

	Number of		Weighted average
	warrants		exercise price
			$
Balance at January 1, 2016 and December 31, 2016	15,719,540		0.85
Warrants cancelled	(13,000,000	)	0.45
Warrants expired	(2,719,540	)	2.59
Balance at December 31, 2017	-		-

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SUPPLEMENTAL INFORMATION (Tables)

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

Disclosure of detailed information about supplemental cash flow information [Table Text Block]

	Year ended December 31
	2017		2016		2015
	$		$		$
Changes in working capital:
Accounts receivable	284		1,530		(1,597	)
Prepaids and deposits	(10	)	12		110
Accounts payable and accrued liabilities	15		(758	)	(530	)
	289		784		(2,017	)
Comprised of:
Operating activities	219		667		204
Investing activities	32		178		(2,289	)
Financing activities	38		(61	)	68
	289		784		(2,017	)
Other cash flow information:
Cash paid for interest	480		596		417
Income taxes paid	-		-		-

Disclosure of detailed information about per share amounts [Table Text Block]

	Year ended December 31,
	2017	2016	2015
Weighted average common shares outstanding
Basic	61,682,462	42,095,366	36,492,207
Diluted	61,682,462	42,095,366	36,492,207

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INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

Disclosure of detailed information about effective income tax expense recovery [Table Text Block]

	2017		2016		2015
	$		$		$
Loss before income taxes	(5,232	)	(5,486	)	(7,108	)
Corporate tax rate	26.44%		26.59%		26.00%
Expected tax recovery	(1,383	)	(1,459	)	(1,848	)
Increase (decrease) resulting from:
Differences in foreign tax rates and change in statutory tax rates	6,381		(231	)	(989	)
Impact of foreign exchange rate changes	1,277		506		(3,005	)
Change in unrecognized deferred tax assets	(6,507	)	1,290		4,509
Stock based compensation and expiry of losses	33		198		509
Non taxable/deductible amounts	199		(304	)	824
Deferred income tax recovery	-		-		-

Disclosure of deferred taxes [Table Text Block]

	2017	2016	2015
	$	$	$
Deferred income tax assets
Non-capital losses available	20,998	26,679	26,547
Capital losses available	1,113	1,072	1,072
Resource tax pools in excess of net book value	5,279	4,846	3,726
Share issue costs and others	654	1,171	1,133
Unrecognized deferred tax assets	28,044	33,768	32,478

Disclosure of detailed information about tax pools available [Table Text Block]

As at December 31	2017	2016	2015
	$	$	$
Canada:
Exploration and development expenditures	17,100	16,750	16,657
Unamortized share issue costs	261	292	455
Capital losses	8,242	8,242	8,242
Non-capital losses	33,120	30,783	29,148
	58,723	56,067	54,502
United States:
Exploration and development expenditures	15,883	17,149	18,560
Undeducted expenses	2,760	2,954	2,737
Non-capital losses	53,733	58,247	57,400
	72,376	78,350	78,697
Total	131,099	134,417	133,199

Disclosure of detailed information about expiration of non capital losses for income tax [Table Text Block]

	Canada	United States	Total
	$	$	$
2026	24	2,531	2,555
2027	3,606	3,374	6,980
2028	4,674	253	4,927
2029	3,780	3,266	7,046
2030	2,068	2,775	4,843
2031	2,408	2,794	5,202
2032	4,372	7,606	11,978
2033	2,167	16,215	18,382
2034	3,966	12,665	16,631
2035	2,292	543	2,835
2036	1,815	1,639	3,454
2037	1,948	72	2,020
	33,120	53,733	86,853

XML

COMMITMENTS (Tables)

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

Disclosure of detailed information about commitments [Table Text Block]

		Payments Due by Period
	1 Year	2-3 Years	4-5 Years	Total
	$	$	$	$
Debt repayments (1)	1,000	-	6,500	7,500
Interest payments (2)	50	-	-	50
Operating leases	88	92	-	180
Financial contract liability	6,752	-	-	6,752
	7,890	92	6,500	14,482

XML

OPERATING SEGMENTS (Tables)

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

Disclosure of detailed information about revenue and expenses by reportable segments [Table Text Block]

	Canada						United States						Total
	2017		2016		2015		2017		2016		2015		2017		2016		2015
	$		$		$		$		$		$		$		$		$
Year ended December 31
Revenues, net of royalties	1,814		3,190		6,606		666		883		490		2,480		4,073		7,096
Segmented loss	(4,948	)	(3,279	)	(1,769	)	(261	)	(2,207	)	(5,339	)	(5,209	)	(5,486	)	(7,108	)
Amortization, depletion and impairment losses	1,784		2,324		3,441		844		2,169		748		2,628		4,493		4,189
Interest expense	950		1,236		500		-		294		525		950		1,530		1,025
Capital expenditures	414		305		1,168		42		225		4,570		456		530		5,738

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DETERMINATION OF FAIR VALUES (Tables)

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Statement [Line Items]

Disclosure of fair value of financial instruments [Table Text Block]

			Quoted Prices in	Significant Other	Significant
	Carrying	Fair	Active Markets	Observable Inputs	Unobservable
December 31, 2017	Amount	Value	(Level 1)	(Level 2)	Inputs (Level 3)
	$	$	$	$	$
Financial Assets:
Cash and cash equivalents	1,010	1,010	1,010	-	-
Accounts receivable	388	388	388	-	-
Financial Liabilities:
Accounts payable and accrued liabilities	1,291	1,291	1,291	-	-
Loans from related parties	4,608	4,608	-	-	4,608
Financial contract liability	6,752	6,752	-	-	6,752

			Quoted Prices in	Significant Other	Significant
	Carrying	Fair	Active Markets	Observable Inputs	Unobservable
December 31, 2016	Amount	Value	(Level 1)	(Level 2)	Inputs (Level 3)
	$	$	$	$	$
Financial Assets:
Cash and cash equivalents	141	141	141	-	-
Accounts receivable	672	672	672	-	-
Financial Liabilities:
Accounts payable and accrued liabilities	2,165	2,165	2,165	-	-
Loans from related parties	6,394	6,394	-	-	6,394
Derivative liability	153	153	-	-	153
Financial contract liability	7,226	7,226	-	-	7,226

XML

FINANCIAL INSTRUMENTS AND CAPITAL MANAGEMENT (Tables)

12 Months Ended

Dec. 31, 2017

Statement [Line Items]

Disclosure of detailed information about foreign currency risk [Table Text Block]

	2017		2016
Expressed in foreign currencies	CND$		CND$
Cash and cash equivalents	30		1
Accounts receivable	228		282
Accounts payable and accrued liabilities	(213	)	(312	)
Balance sheet exposure	45		(29	)

Disclosure of detailed information about exposed foreign currency risk [Table Text Block]

	2017	2016
December 31, reporting date rate	1.2545	1.3427
YTD average USD to CAD	1.2986	1.3253

XML

BASIS OF PRESENTATION (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Basis Of Presentation 1	$ 8.2
Basis Of Presentation 2	115.8
Basis Of Presentation 3	$ 6.8

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative) (Details)	12 Months Ended
	Dec. 31, 2017 d
Statement [Line Items]
Summary Of Significant Accounting Policies 1	99.00%
Summary Of Significant Accounting Policies 2	99.00%
Summary Of Significant Accounting Policies 3	30
Summary Of Significant Accounting Policies 4	12

XML

EXPLORATION AND EVALUATION (E&E) ASSETS (Narrative) (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Exploration And Evaluation (e&e) Assets 1	$ 621,000
Exploration And Evaluation (e&e) Assets 2	$ 1,790,000

XML

PROPERTY AND EQUIPMENT (Narrative) (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Property And Equipment 1	$ 0
Property And Equipment 2	0
Property And Equipment 3	7,000
Property And Equipment 4	$ 104,000
Property And Equipment 5	14.40%
Property And Equipment 6	$ 870,000
Property And Equipment 7	$ 940,000
Property And Equipment 8	50.00%
Property And Equipment 9	15.00%
Property And Equipment 10	2
Property And Equipment 11	50.00%
Property And Equipment 12	15.00%
Property And Equipment 13	$ 83,700,000
Property And Equipment 14	84,000,000
Property And Equipment 15	86,400,000
Property And Equipment 16	12,000
Property And Equipment 17	$ 14,000
Property And Equipment 18	14.30%
Property And Equipment 19	14.30%

XML

LOANS FROM RELATED PARTIES (Narrative) (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($) d $ / shares shares
Statement [Line Items]
Loans From Related Parties 1	$ 4,500,000
Loans From Related Parties 2	5.00%
Loans From Related Parties 3 | d	10
Loans From Related Parties 4	$ 114,230
Loans From Related Parties 5 | d	1
Loans From Related Parties 6	$ 1,371,000
Loans From Related Parties 7	9,000,000
Loans From Related Parties 8	$ 0.45
Loans From Related Parties 9 | $ / shares	$ 0.35
Loans From Related Parties 10	1.00%
Loans From Related Parties 11 | shares	58,441,558
Loans From Related Parties 12 | $ / shares	$ 0.077
Loans From Related Parties 13 | shares	9,000,000
Loans From Related Parties 14	20.00%
Loans From Related Parties 15	5
Loans From Related Parties 16	$ 2,346,000
Loans From Related Parties 17	4,500,000
Loans From Related Parties 18	3,903,000
Loans From Related Parties 19	127,000
Loans From Related Parties 20	54,000
Loans From Related Parties 21	$ 3,976,000
Loans From Related Parties 22	4.50%
Loans From Related Parties 23	$ 2,000,000
Loans From Related Parties 24	5.00%
Loans From Related Parties 25	$ 50,769
Loans From Related Parties 26 | d	1
Loans From Related Parties 27	$ 660,000
Loans From Related Parties 28	4,000,000
Loans From Related Parties 29	$ 0.45
Loans From Related Parties 30 | $ / shares	$ 0.35
Loans From Related Parties 31	1.00%
Loans From Related Parties 32 | shares	25,974,025
Loans From Related Parties 33 | $ / shares	$ 0.077
Loans From Related Parties 34 | shares	4,000,000
Loans From Related Parties 35	20.00%
Loans From Related Parties 36	5
Loans From Related Parties 37	$ 1,043,000
Loans From Related Parties 38	2,000,000
Loans From Related Parties 39	1,560,000
Loans From Related Parties 40	77,000
Loans From Related Parties 41	24,000
Loans From Related Parties 42	$ 1,613,000
Loans From Related Parties 43	4.50%
Loans From Related Parties 44	$ 1,000,000
Loans From Related Parties 45	12.00%
Loans From Related Parties 46	$ 200,000
Loans From Related Parties 47	1,200,000
Loans From Related Parties 48	$ 1,500,000
Loans From Related Parties 49	12.00%
Loans From Related Parties 50	10.00%
Loans From Related Parties 51	$ 1,500,000
Loans From Related Parties 52	1,500,000
Loans From Related Parties 53	1,500,000
Loans From Related Parties 54	450,000
Loans From Related Parties 55	50,000
Loans From Related Parties 56	500,000
Loans From Related Parties 57	0
Loans From Related Parties 58	1,000,000
Loans From Related Parties 59	$ 1,050,000

XML

FINANCIAL CONTRACT LIABILITY (Narrative) (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Financial Contract Liability 1	$ 7,000,000
Financial Contract Liability 2	7,000,000
Financial Contract Liability 3	$ 3,000,000
Financial Contract Liability 4	4
Financial Contract Liability 5	4
Financial Contract Liability 6	$ 6,752,000

XML

SHARE CAPITAL (Narrative) (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($) $ / shares shares
Statement [Line Items]
Share Capital 1	$ 523,000
Share Capital 2	93,000
Share Capital 3	149,000
Share Capital 4	$ 21,000
Share Capital 5 | shares	8,633,166
Share Capital 6 | $ / shares	$ 0.075
Share Capital 7	$ 647,000
Share Capital 8	5,738,665
Share Capital 9	$ 523,000
Share Capital 10	5,091,165
Share Capital 11 | $ / shares	$ 0.09
Share Capital 12	647,500
Share Capital 13 | $ / shares	$ 0.10
Share Capital 14	$ 51,000
Share Capital 15	$ 24,000
Share Capital 16	946,667
Share Capital 17 | $ / shares	$ 0.075
Share Capital 18 | shares	42,297,400
Share Capital 19 | $ / shares	$ 0.06
Share Capital 20	$ 2,538,000
Share Capital 21	2,128,571
Share Capital 22 | $ / shares	$ 0.07
Share Capital 23	$ 149,000
Share Capital 24	41,000
Share Capital 25	$ 23,000
Share Capital 26	21,924,067
Share Capital 27 | $ / shares	$ 0.06
Share Capital 28	(17,967,644)
Share Capital 29	(3,956,423)
Share Capital 30 | shares	8,298,333
Share Capital 31 | $ / shares	$ 0.12
Share Capital 32	$ 995,800
Share Capital 33	18,000
Share Capital 34	$ 29,000
Share Capital 35 | shares	3,600,000

XML

STOCK OPTIONS AND SHARE PURCHASE WARRANTS (Narrative) (Details)	12 Months Ended
	Dec. 31, 2017
Statement [Line Items]
Stock Options And Share Purchase Warrants 1	10.00%
Stock Options And Share Purchase Warrants 2	10.00%
Stock Options And Share Purchase Warrants 3	3,400,000

XML

RELATED PARTY TRANSACTIONS (Narrative) (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Related Party Transactions 1	$ 466,000
Related Party Transactions 2	470,000
Related Party Transactions 3	473,000
Related Party Transactions 4	0
Related Party Transactions 5	80,000
Related Party Transactions 6	464,000
Related Party Transactions 7	131,000
Related Party Transactions 8	262,000
Related Party Transactions 9	200,000
Related Party Transactions 10	370,000
Related Party Transactions 11	595,000
Related Party Transactions 12	343,000
Related Party Transactions 13	139,000
Related Party Transactions 14	0
Related Party Transactions 15	$ 0

XML

INCOME TAXES (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Income Taxes 1	35.00%
Income Taxes 2	21.00%
Income Taxes 3	21.00%
Income Taxes 4	$ 6,380

XML

COMMITMENTS (Narrative) (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Commitments 1	$ 1,000,000

XML

FINANCIAL INSTRUMENTS AND CAPITAL MANAGEMENT (Narrative) (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($) d
Statement [Line Items]
Financial Instruments And Capital Management 1	$ 196,000
Financial Instruments And Capital Management 2	244,000
Financial Instruments And Capital Management 3	121,000
Financial Instruments And Capital Management 4	276,000
Financial Instruments And Capital Management 5	71,000
Financial Instruments And Capital Management 6	$ 152,000
Financial Instruments And Capital Management 7 | d	90
Financial Instruments And Capital Management 8	$ 0
Financial Instruments And Capital Management 9	$ 0
Financial Instruments And Capital Management 10	10.00%
Financial Instruments And Capital Management 11	$ 5,000
Financial Instruments And Capital Management 12	$ 3,000
Financial Instruments And Capital Management 13	10.00%
Financial Instruments And Capital Management 14	1.00%
Financial Instruments And Capital Management 15	$ 65,000
Financial Instruments And Capital Management 16	1
Financial Instruments And Capital Management 17	0.01
Financial Instruments And Capital Management 18	$ 34,000

XML

Disclosure of detailed information about estimated useful life or depreciation rate (Details)	12 Months Ended
	Dec. 31, 2017
Statement [Line Items]
Summary Of Significant Accounting Policies Disclosure Of Detailed Information About Estimated Useful Life Or Depreciation Rate 1	20.00%
Summary Of Significant Accounting Policies Disclosure Of Detailed Information About Estimated Useful Life Or Depreciation Rate 2	45.00%
Summary Of Significant Accounting Policies Disclosure Of Detailed Information About Estimated Useful Life Or Depreciation Rate 3	30.00%

XML

Disclosure of detailed information about exploration assets (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 1	$ 281
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 2	18,982
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 3	19,263
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 4	2
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 5	0
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 6	2
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 7	13
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 8	0
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 9	13
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 10	0
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 11	(772)
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 12	(772)
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 13	0
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 14	(768)
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 15	(768)
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 16	296
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 17	17,442
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 18	17,738
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 19	4
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 20	3
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 21	7
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 22	56
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 23	0
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 24	56
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 25	0
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 26	0
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 27	0
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 28	0
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 29	(1,174)
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 30	(1,174)
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 31	356
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 32	16,271
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Exploration Assets 33	$ 16,627

XML

Disclosure of detailed information about impairment on exploration and evaluation assets (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 1	$ 0
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 2	(16,041)
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 3	(16,041)
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 4	0
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 5	(1,790)
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 6	(1,790)
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 7	0
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 8	513
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 9	513
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 10	0
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 11	550
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 12	550
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 13	0
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 14	(16,768)
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 15	(16,768)
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 16	(350)
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 17	(621)
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 18	(971)
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 19	0
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 20	0
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 21	0
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 22	0
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 23	1,120
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 24	1,120
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 25	(350)
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 26	(16,269)
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Impairment On Exploration And Evaluation Assets 27	$ (16,619)

XML

Disclosure of detailed information about carrying amounts of exploration and evaluation assets (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Carrying Amounts Of Exploration And Evaluation Assets 1	$ 296
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Carrying Amounts Of Exploration And Evaluation Assets 2	674
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Carrying Amounts Of Exploration And Evaluation Assets 3	970
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Carrying Amounts Of Exploration And Evaluation Assets 4	6
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Carrying Amounts Of Exploration And Evaluation Assets 5	2
Exploration And Evaluation (e&e) Assets Disclosure Of Detailed Information About Carrying Amounts Of Exploration And Evaluation Assets 6	$ 8

XML

Disclosure of detailed information about property, plant and equipment (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 1	$ 33,376
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 2	16,653
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 3	179
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 4	50,208
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 5	300
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 6	225
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 7	3
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 8	528
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 9	(48)
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 10	(4)
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 11	0
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 12	(52)
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 13	0
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 14	(502)
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 15	0
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 16	(502)
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 17	33,628
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 18	16,372
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 19	182
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 20	50,182
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 21	405
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 22	39
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 23	5
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 24	449
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 25	94
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 26	(3)
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 27	0
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 28	91
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 29	0
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 30	0
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 31	(29)
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 32	(29)
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 33	0
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 34	(1,060)
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 35	0
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 36	(1,060)
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 37	34,127
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 38	15,348
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 39	158
Property And Equipment Disclosure Of Detailed Information About Property, Plant And Equipment 40	$ 49,633

XML

Disclosure of detailed information about accumulated amortization, depletion and impairment losses of property and equipment (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 1	$ (26,774)
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 2	(1,375)
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 3	(160)
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 4	(28,309)
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 5	(1,248)
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 6	(380)
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 7	(5)
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 8	(1,633)
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 9	(1,070)
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 10	0
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 11	0
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 12	(1,070)
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 13	0
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 14	41
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 15	1
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 16	42
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 17	(29,092)
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 18	(1,714)
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 19	(164)
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 20	(30,970)
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 21	(561)
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 22	(223)
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 23	(3)
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 24	(787)
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 25	(870)
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 26	0
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 27	0
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 28	(870)
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 29	0
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 30	0
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 31	25
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 32	25
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 33	0
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 34	131
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 35	0
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 36	131
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 37	(30,523)
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 38	(1,806)
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 39	(142)
Property And Equipment Disclosure Of Detailed Information About Accumulated Amortization, Depletion And Impairment Losses Of Property And Equipment 40	$ (32,471)

XML

Disclosure of detailed information about carrying amount of property and equipment (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Property And Equipment Disclosure Of Detailed Information About Carrying Amount Of Property And Equipment 1	$ 4,536
Property And Equipment Disclosure Of Detailed Information About Carrying Amount Of Property And Equipment 2	14,658
Property And Equipment Disclosure Of Detailed Information About Carrying Amount Of Property And Equipment 3	18
Property And Equipment Disclosure Of Detailed Information About Carrying Amount Of Property And Equipment 4	19,212
Property And Equipment Disclosure Of Detailed Information About Carrying Amount Of Property And Equipment 5	3,604
Property And Equipment Disclosure Of Detailed Information About Carrying Amount Of Property And Equipment 6	13,542
Property And Equipment Disclosure Of Detailed Information About Carrying Amount Of Property And Equipment 7	16
Property And Equipment Disclosure Of Detailed Information About Carrying Amount Of Property And Equipment 8	$ 17,162

XML

Disclosure of detailed information about commodity price estimates (Details)	12 Months Ended
	Dec. 31, 2017
Statement [Line Items]
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 1	2.20
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 2	76.42
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 3	70.25
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 4	2.54
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 5	74.68
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 6	70.25
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 7	2.88
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 8	74.38
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 9	70.31
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 10	3.24
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 11	77.16
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 12	72.84
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 13	3.47
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 14	79.88
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 15	75.61
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 16	3.58
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 17	82.53
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 18	78.31
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 19	3.66
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 20	86.14
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 21	81.93
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 22	3.73
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 23	89.76
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 24	85.54
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 25	3.80
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 26	92.57
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 27	88.35
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 28	3.88
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 29	94.43
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 30	90.22
Property And Equipment Disclosure Of Detailed Information About Commodity Price Estimates 31	2.00%

XML

Disclosure of impairment of assets (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Amortization, Depletion And Impairment Losses Disclosure Of Impairment Of Assets 1	$ 971
Amortization, Depletion And Impairment Losses Disclosure Of Impairment Of Assets 2	1,790
Amortization, Depletion And Impairment Losses Disclosure Of Impairment Of Assets 3	534
Amortization, Depletion And Impairment Losses Disclosure Of Impairment Of Assets 4	787
Amortization, Depletion And Impairment Losses Disclosure Of Impairment Of Assets 5	1,633
Amortization, Depletion And Impairment Losses Disclosure Of Impairment Of Assets 6	2,655
Amortization, Depletion And Impairment Losses Disclosure Of Impairment Of Assets 7	870
Amortization, Depletion And Impairment Losses Disclosure Of Impairment Of Assets 8	1,070
Amortization, Depletion And Impairment Losses Disclosure Of Impairment Of Assets 9	1,000
Amortization, Depletion And Impairment Losses Disclosure Of Impairment Of Assets 10	2,628
Amortization, Depletion And Impairment Losses Disclosure Of Impairment Of Assets 11	4,493
Amortization, Depletion And Impairment Losses Disclosure Of Impairment Of Assets 12	$ 4,189

XML

Disclosure of detailed information about gain loss on debt extinguishment (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Hodgkinson Equity Corporation (HEC) [Member]
Statement [Line Items]
Loans From Related Parties Disclosure Of Detailed Information About Gain Loss On Debt Extinguishment 1	$ 2,346
Loans From Related Parties Disclosure Of Detailed Information About Gain Loss On Debt Extinguishment 2	2,158
Loans From Related Parties Disclosure Of Detailed Information About Gain Loss On Debt Extinguishment 3	(3,976)
Loans From Related Parties Disclosure Of Detailed Information About Gain Loss On Debt Extinguishment 4	528
Hodgkinson Ventures Inc. (HVI) [Member]
Statement [Line Items]
Loans From Related Parties Disclosure Of Detailed Information About Gain Loss On Debt Extinguishment 1	1,043
Loans From Related Parties Disclosure Of Detailed Information About Gain Loss On Debt Extinguishment 2	960
Loans From Related Parties Disclosure Of Detailed Information About Gain Loss On Debt Extinguishment 3	(1,613)
Loans From Related Parties Disclosure Of Detailed Information About Gain Loss On Debt Extinguishment 4	$ 390

XML

Disclosure of detailed information about debt activity (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Hodgkinson Equity Corporation (HEC) [Member]
Statement [Line Items]
Loans From Related Parties Disclosure Of Detailed Information About Debt Activity 1	$ 2,337
Loans From Related Parties Disclosure Of Detailed Information About Debt Activity 2	265
Loans From Related Parties Disclosure Of Detailed Information About Debt Activity 3	(104)
Loans From Related Parties Disclosure Of Detailed Information About Debt Activity 4	2,498
Loans From Related Parties Disclosure Of Detailed Information About Debt Activity 5	(317)
Loans From Related Parties Disclosure Of Detailed Information About Debt Activity 6	2,181
Hodgkinson Ventures Inc. (HVI) [Member]
Statement [Line Items]
Loans From Related Parties Disclosure Of Detailed Information About Debt Activity 1	1,039
Loans From Related Parties Disclosure Of Detailed Information About Debt Activity 2	117
Loans From Related Parties Disclosure Of Detailed Information About Debt Activity 3	(46)
Loans From Related Parties Disclosure Of Detailed Information About Debt Activity 4	1,110
Loans From Related Parties Disclosure Of Detailed Information About Debt Activity 5	(141)
Loans From Related Parties Disclosure Of Detailed Information About Debt Activity 6	$ 969

XML

Disclosure of detailed information about liability portion of the flow-through shares issuances (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($) shares
Statement [Line Items]
Flow-through Shares Liability Disclosure Of Detailed Information About Liability Portion Of The Flow-through Shares Issuances 1	$ 0
Flow-through Shares Liability Disclosure Of Detailed Information About Liability Portion Of The Flow-through Shares Issuances 2	$ 0
Flow-through Shares Liability Disclosure Of Detailed Information About Liability Portion Of The Flow-through Shares Issuances 3 | shares	0
Flow-through Shares Liability Disclosure Of Detailed Information About Liability Portion Of The Flow-through Shares Issuances 4	$ 21
Flow-through Shares Liability Disclosure Of Detailed Information About Liability Portion Of The Flow-through Shares Issuances 5	93
Flow-through Shares Liability Disclosure Of Detailed Information About Liability Portion Of The Flow-through Shares Issuances 6	114
Flow-through Shares Liability Disclosure Of Detailed Information About Liability Portion Of The Flow-through Shares Issuances 7	(21)
Flow-through Shares Liability Disclosure Of Detailed Information About Liability Portion Of The Flow-through Shares Issuances 8	0
Flow-through Shares Liability Disclosure Of Detailed Information About Liability Portion Of The Flow-through Shares Issuances 9	(21)
Flow-through Shares Liability Disclosure Of Detailed Information About Liability Portion Of The Flow-through Shares Issuances 10	0
Flow-through Shares Liability Disclosure Of Detailed Information About Liability Portion Of The Flow-through Shares Issuances 11	93
Flow-through Shares Liability Disclosure Of Detailed Information About Liability Portion Of The Flow-through Shares Issuances 12	$ 93

XML

Disclosure of detailed information about decommissioning liability (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 1	$ 3,679
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 2	146
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 3	3,825
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 4	(36)
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 5	(4)
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 6	(40)
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 7	(53)
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 8	(5)
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 9	(58)
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 10	46
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 11	3
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 12	49
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 13	3,636
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 14	140
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 15	3,776
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 16	146
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 17	(3)
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 18	143
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 19	(3)
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 20	(8)
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 21	(11)
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 22	60
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 23	3
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 24	63
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 25	3,839
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 26	132
Decommissioning Liability Disclosure Of Detailed Information About Decommissioning Liability 27	$ 3,971

XML

Disclosure of detailed information about present value of the decommissioning liability (Details)	12 Months Ended
	Dec. 31, 2017
Statement [Line Items]
Decommissioning Liability Disclosure Of Detailed Information About Present Value Of The Decommissioning Liability 1	1.94%
Decommissioning Liability Disclosure Of Detailed Information About Present Value Of The Decommissioning Liability 2	2.20%
Decommissioning Liability Disclosure Of Detailed Information About Present Value Of The Decommissioning Liability 3	2.00%
Decommissioning Liability Disclosure Of Detailed Information About Present Value Of The Decommissioning Liability 4	2.00%
Decommissioning Liability Disclosure Of Detailed Information About Present Value Of The Decommissioning Liability 5	1.60%
Decommissioning Liability Disclosure Of Detailed Information About Present Value Of The Decommissioning Liability 6	2.34%
Decommissioning Liability Disclosure Of Detailed Information About Present Value Of The Decommissioning Liability 7	2.00%
Decommissioning Liability Disclosure Of Detailed Information About Present Value Of The Decommissioning Liability 8	2.00%

XML

Disclosure of detailed information about financial contract liability (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Financial Contract Liability Disclosure Of Detailed Information About Financial Contract Liability 1	$ 5,207
Financial Contract Liability Disclosure Of Detailed Information About Financial Contract Liability 2	7,207
Financial Contract Liability Disclosure Of Detailed Information About Financial Contract Liability 3	222
Financial Contract Liability Disclosure Of Detailed Information About Financial Contract Liability 4	296
Financial Contract Liability Disclosure Of Detailed Information About Financial Contract Liability 5	(214)
Financial Contract Liability Disclosure Of Detailed Information About Financial Contract Liability 6	47
Financial Contract Liability Disclosure Of Detailed Information About Financial Contract Liability 7	(63)
Financial Contract Liability Disclosure Of Detailed Information About Financial Contract Liability 8	5,382
Financial Contract Liability Disclosure Of Detailed Information About Financial Contract Liability 9	7,226
Financial Contract Liability Disclosure Of Detailed Information About Financial Contract Liability 10	(474)
Financial Contract Liability Disclosure Of Detailed Information About Financial Contract Liability 11	5,382
Financial Contract Liability Disclosure Of Detailed Information About Financial Contract Liability 12	$ 6,752

XML

Disclosure of number and weighted average exercise prices of share options (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Stock Options And Share Purchase Warrants Disclosure Of Number And Weighted Average Exercise Prices Of Share Options 1	$ 140,738
Stock Options And Share Purchase Warrants Disclosure Of Number And Weighted Average Exercise Prices Of Share Options 2	1.20
Stock Options And Share Purchase Warrants Disclosure Of Number And Weighted Average Exercise Prices Of Share Options 3	$ 3,400,000
Stock Options And Share Purchase Warrants Disclosure Of Number And Weighted Average Exercise Prices Of Share Options 4	0.16
Stock Options And Share Purchase Warrants Disclosure Of Number And Weighted Average Exercise Prices Of Share Options 5	$ (52,818)
Stock Options And Share Purchase Warrants Disclosure Of Number And Weighted Average Exercise Prices Of Share Options 6	1.26
Stock Options And Share Purchase Warrants Disclosure Of Number And Weighted Average Exercise Prices Of Share Options 7	$ (87,920)
Stock Options And Share Purchase Warrants Disclosure Of Number And Weighted Average Exercise Prices Of Share Options 8	1.16
Stock Options And Share Purchase Warrants Disclosure Of Number And Weighted Average Exercise Prices Of Share Options 9	$ 3,400,000
Stock Options And Share Purchase Warrants Disclosure Of Number And Weighted Average Exercise Prices Of Share Options 10	0.16

XML

Disclosure of number and weighted average remaining contractual life of outstanding share options (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Stock Options And Share Purchase Warrants Disclosure Of Number And Weighted Average Remaining Contractual Life Of Outstanding Share Options 1	$ 0.16
Stock Options And Share Purchase Warrants Disclosure Of Number And Weighted Average Remaining Contractual Life Of Outstanding Share Options 2	$ 3,400,000
Stock Options And Share Purchase Warrants Disclosure Of Number And Weighted Average Remaining Contractual Life Of Outstanding Share Options 3	0.16
Stock Options And Share Purchase Warrants Disclosure Of Number And Weighted Average Remaining Contractual Life Of Outstanding Share Options 4	3.43
Stock Options And Share Purchase Warrants Disclosure Of Number And Weighted Average Remaining Contractual Life Of Outstanding Share Options 5	$ 3,400,000
Stock Options And Share Purchase Warrants Disclosure Of Number And Weighted Average Remaining Contractual Life Of Outstanding Share Options 6	0.16
Stock Options And Share Purchase Warrants Disclosure Of Number And Weighted Average Remaining Contractual Life Of Outstanding Share Options 7	3.43

XML

Disclosure of detailed information about options, valuation assumptions (Details)	12 Months Ended
	Dec. 31, 2017 yr
Statement [Line Items]
Stock Options And Share Purchase Warrants Disclosure Of Detailed Information About Options, Valuation Assumptions 1	0.06
Stock Options And Share Purchase Warrants Disclosure Of Detailed Information About Options, Valuation Assumptions 2	80.35%
Stock Options And Share Purchase Warrants Disclosure Of Detailed Information About Options, Valuation Assumptions 3	1.37
Stock Options And Share Purchase Warrants Disclosure Of Detailed Information About Options, Valuation Assumptions 4	0.00%
Stock Options And Share Purchase Warrants Disclosure Of Detailed Information About Options, Valuation Assumptions 5	0.54%
Stock Options And Share Purchase Warrants Disclosure Of Detailed Information About Options, Valuation Assumptions 6	6.85%

XML

Disclosure of detailed information about warrants, activity (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Stock Options And Share Purchase Warrants Disclosure Of Detailed Information About Warrants, Activity 1	$ 15,719,540
Stock Options And Share Purchase Warrants Disclosure Of Detailed Information About Warrants, Activity 2	0.85
Stock Options And Share Purchase Warrants Disclosure Of Detailed Information About Warrants, Activity 3	$ (13,000,000)
Stock Options And Share Purchase Warrants Disclosure Of Detailed Information About Warrants, Activity 4	0.45
Stock Options And Share Purchase Warrants Disclosure Of Detailed Information About Warrants, Activity 5	$ (2,719,540)
Stock Options And Share Purchase Warrants Disclosure Of Detailed Information About Warrants, Activity 6	2.59
Stock Options And Share Purchase Warrants Disclosure Of Detailed Information About Warrants, Activity 7	$ 0
Stock Options And Share Purchase Warrants Disclosure Of Detailed Information About Warrants, Activity 8	$ 0

XML

Disclosure of detailed information about supplemental cash flow information (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 1	$ 284
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 2	1,530
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 3	(1,597)
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 4	(10)
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 5	12
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 6	110
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 7	15
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 8	(758)
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 9	(530)
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 10	289
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 11	784
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 12	(2,017)
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 13	219
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 14	667
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 15	204
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 16	32
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 17	178
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 18	(2,289)
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 19	38
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 20	(61)
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 21	68
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 22	289
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 23	784
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 24	(2,017)
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 25	480
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 26	596
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 27	417
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 28	0
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 29	0
Supplemental Information Disclosure Of Detailed Information About Supplemental Cash Flow Information 30	$ 0

XML

Disclosure of detailed information about per share amounts (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Supplemental Information Disclosure Of Detailed Information About Per Share Amounts 1	$ 61,682,462
Supplemental Information Disclosure Of Detailed Information About Per Share Amounts 2	42,095,366
Supplemental Information Disclosure Of Detailed Information About Per Share Amounts 3	36,492,207
Supplemental Information Disclosure Of Detailed Information About Per Share Amounts 4	61,682,462
Supplemental Information Disclosure Of Detailed Information About Per Share Amounts 5	42,095,366
Supplemental Information Disclosure Of Detailed Information About Per Share Amounts 6	$ 36,492,207

XML

Disclosure of detailed information about effective income tax expense recovery (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 1	$ (5,232)
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 2	(5,486)
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 3	$ (7,108)
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 4	26.44%
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 5	26.59%
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 6	26.00%
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 7	$ (1,383)
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 8	(1,459)
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 9	(1,848)
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 10	6,381
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 11	(231)
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 12	(989)
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 13	1,277
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 14	506
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 15	(3,005)
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 16	(6,507)
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 17	1,290
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 18	4,509
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 19	33
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 20	198
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 21	509
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 22	199
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 23	(304)
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 24	824
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 25	0
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 26	0
Income Taxes Disclosure Of Detailed Information About Effective Income Tax Expense Recovery 27	$ 0

XML

Disclosure of deferred taxes (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Income Taxes Disclosure Of Deferred Taxes 1	$ 20,998
Income Taxes Disclosure Of Deferred Taxes 2	26,679
Income Taxes Disclosure Of Deferred Taxes 3	26,547
Income Taxes Disclosure Of Deferred Taxes 4	1,113
Income Taxes Disclosure Of Deferred Taxes 5	1,072
Income Taxes Disclosure Of Deferred Taxes 6	1,072
Income Taxes Disclosure Of Deferred Taxes 7	5,279
Income Taxes Disclosure Of Deferred Taxes 8	4,846
Income Taxes Disclosure Of Deferred Taxes 9	3,726
Income Taxes Disclosure Of Deferred Taxes 10	654
Income Taxes Disclosure Of Deferred Taxes 11	1,171
Income Taxes Disclosure Of Deferred Taxes 12	1,133
Income Taxes Disclosure Of Deferred Taxes 13	28,044
Income Taxes Disclosure Of Deferred Taxes 14	33,768
Income Taxes Disclosure Of Deferred Taxes 15	$ 32,478

XML

Disclosure of detailed information about tax pools available (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 1	$ 17,100
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 2	16,750
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 3	16,657
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 4	261
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 5	292
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 6	455
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 7	8,242
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 8	8,242
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 9	8,242
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 10	33,120
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 11	30,783
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 12	29,148
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 13	58,723
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 14	56,067
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 15	54,502
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 16	15,883
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 17	17,149
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 18	18,560
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 19	2,760
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 20	2,954
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 21	2,737
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 22	53,733
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 23	58,247
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 24	57,400
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 25	72,376
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 26	78,350
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 27	78,697
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 28	131,099
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 29	134,417
Income Taxes Disclosure Of Detailed Information About Tax Pools Available 30	$ 133,199

XML

Disclosure of detailed information about expiration of non capital losses for income tax (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 1	$ 24
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 2	2,531
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 3	2,555
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 4	3,606
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 5	3,374
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 6	6,980
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 7	4,674
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 8	253
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 9	4,927
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 10	3,780
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 11	3,266
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 12	7,046
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 13	2,068
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 14	2,775
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 15	4,843
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 16	2,408
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 17	2,794
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 18	5,202
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 19	4,372
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 20	7,606
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 21	11,978
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 22	2,167
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 23	16,215
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 24	18,382
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 25	3,966
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 26	12,665
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 27	16,631
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 28	2,292
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 29	543
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 30	2,835
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 31	1,815
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 32	1,639
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 33	3,454
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 34	1,948
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 35	72
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 36	2,020
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 37	33,120
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 38	53,733
Income Taxes Disclosure Of Detailed Information About Expiration Of Non Capital Losses For Income Tax 39	$ 86,853

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Disclosure of detailed information about commitments (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Commitments Disclosure Of Detailed Information About Commitments 1	$ 1,000
Commitments Disclosure Of Detailed Information About Commitments 2	0
Commitments Disclosure Of Detailed Information About Commitments 3	6,500
Commitments Disclosure Of Detailed Information About Commitments 4	7,500
Commitments Disclosure Of Detailed Information About Commitments 5	50
Commitments Disclosure Of Detailed Information About Commitments 6	0
Commitments Disclosure Of Detailed Information About Commitments 7	0
Commitments Disclosure Of Detailed Information About Commitments 8	50
Commitments Disclosure Of Detailed Information About Commitments 9	88
Commitments Disclosure Of Detailed Information About Commitments 10	92
Commitments Disclosure Of Detailed Information About Commitments 11	0
Commitments Disclosure Of Detailed Information About Commitments 12	180
Commitments Disclosure Of Detailed Information About Commitments 13	6,752
Commitments Disclosure Of Detailed Information About Commitments 14	0
Commitments Disclosure Of Detailed Information About Commitments 15	0
Commitments Disclosure Of Detailed Information About Commitments 16	6,752
Commitments Disclosure Of Detailed Information About Commitments 17	7,890
Commitments Disclosure Of Detailed Information About Commitments 18	92
Commitments Disclosure Of Detailed Information About Commitments 19	6,500
Commitments Disclosure Of Detailed Information About Commitments 20	$ 14,482

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Disclosure of detailed information about revenue and expenses by reportable segments (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 1	$ 1,814
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 2	3,190
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 3	6,606
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 4	666
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 5	883
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 6	490
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 7	2,480
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 8	4,073
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 9	7,096
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 10	(4,948)
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 11	(3,279)
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 12	(1,769)
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 13	(261)
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 14	(2,207)
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 15	(5,339)
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 16	(5,209)
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 17	(5,486)
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 18	(7,108)
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 19	1,784
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 20	2,324
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 21	3,441
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 22	844
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 23	2,169
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 24	748
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 25	2,628
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 26	4,493
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 27	4,189
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 28	950
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 29	1,236
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 30	500
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 31	0
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 32	294
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 33	525
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 34	950
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 35	1,530
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 36	1,025
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 37	414
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 38	305
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 39	1,168
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 40	42
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 41	225
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 42	4,570
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 43	456
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 44	530
Operating Segments Disclosure Of Detailed Information About Revenue And Expenses By Reportable Segments 45	$ 5,738

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Disclosure of fair value of financial instruments (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Statement [Line Items]
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 1	$ 1,010
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 2	1,010
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 3	1,010
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 4	0
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 5	0
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 6	388
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 7	388
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 8	388
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 9	0
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 10	0
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 11	1,291
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 12	1,291
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 13	1,291
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 14	0
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 15	0
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 16	4,608
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 17	4,608
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 18	0
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 19	0
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 20	4,608
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 21	6,752
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 22	6,752
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 23	0
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 24	0
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 25	$ 6,752
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 1		$ 141
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 2		141
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 3		141
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 4		0
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 5		0
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 6		672
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 7		672
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 8		672
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 9		0
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 10		0
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 11		2,165
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 12		2,165
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 13		2,165
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 14		0
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 15		0
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 16		6,394
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 17		6,394
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 18		0
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 19		0
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 20		6,394
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 21		153
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 22		153
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 23		0
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 24		0
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 25		153
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 26		7,226
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 27		7,226
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 28		0
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 29		0
Determination Of Fair Values Disclosure Of Fair Value Of Financial Instruments 30		$ 7,226

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Disclosure of detailed information about foreign currency risk (Details)	12 Months Ended
	Dec. 31, 2017 CAD ($)
Statement [Line Items]
Financial Instruments And Capital Management Disclosure Of Detailed Information About Foreign Currency Risk 1	$ 30
Financial Instruments And Capital Management Disclosure Of Detailed Information About Foreign Currency Risk 2	1
Financial Instruments And Capital Management Disclosure Of Detailed Information About Foreign Currency Risk 3	228
Financial Instruments And Capital Management Disclosure Of Detailed Information About Foreign Currency Risk 4	282
Financial Instruments And Capital Management Disclosure Of Detailed Information About Foreign Currency Risk 5	(213)
Financial Instruments And Capital Management Disclosure Of Detailed Information About Foreign Currency Risk 6	(312)
Financial Instruments And Capital Management Disclosure Of Detailed Information About Foreign Currency Risk 7	45
Financial Instruments And Capital Management Disclosure Of Detailed Information About Foreign Currency Risk 8	$ (29)

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Disclosure of detailed information about exposed foreign currency risk (Details)	12 Months Ended
	Dec. 31, 2017
Statement [Line Items]
Financial Instruments And Capital Management Disclosure Of Detailed Information About Exposed Foreign Currency Risk 1	1.2545
Financial Instruments And Capital Management Disclosure Of Detailed Information About Exposed Foreign Currency Risk 2	1.3427
Financial Instruments And Capital Management Disclosure Of Detailed Information About Exposed Foreign Currency Risk 3	1.2986
Financial Instruments And Capital Management Disclosure Of Detailed Information About Exposed Foreign Currency Risk 4	1.3253