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)
Indicate by check mark which basis of accounting the registrant
has used to prepare the financial statements included in this filing:
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:
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]
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.
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:
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.
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:
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.
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.
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$1.2579.
PART I
ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND
ADVISORS
Not applicable.
ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE
Not applicable.
ITEM 3. KEY INFORMATION
|
A.
|
Selected Financial Data
|
Our selected financial data and the information in the
following tables for the years ended December 31, 2013 – 2017 was derived from
our audited consolidated financial statements. These audited consolidated
financial statements have been audited by BDO Canada LLP, Chartered Professional
Accountants, for the years ended December 31, 2017, 2016, 2015, 2014, and
2013.
The information in the following table should be read in
conjunction with the information appearing under the heading “Item 5. Operating
and Financial Review and Prospects” and our audited consolidated financial
statements under the heading "Item 18. Financial Statements".
The Company’s annual audited Consolidated Financial Statements
have been prepared in accordance with IFRS, as issued by the International
Accounting Standards Board (“IASB”) and interpretations of the International
Financial Reporting Interpretations Committee (“IFRIC”).
We have not declared any dividends since incorporation and do
not anticipate that we will do so in the foreseeable future. Our present policy
is to retain all available funds for use in our operations and the expansion of
our business.
The following table is a summary of selected audited
consolidated financial information of the Company for each of the four most
recently completed financial years. The information presented is presented in
accordance with IFRS:
|
(CA$ 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.
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.
13
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.
14
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.
15
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.
16
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.
17
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.
|
18
|
(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 $4.5 million to drill, case and complete
its 25% working interest share of eight natural gas wells at Kokopelli in
Colorado and complete a salt water disposal facility.
Additions to property and equipment and exploration and
evaluation assets:
19
|
|
|
Year ended December 31, 2017
|
|
|
Year ended December 31, 2016
|
|
|
|
|
|
(CA$ 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.
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
|
20
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.
21
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 1
st
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 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.
|
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;
|
22
|
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.
23
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.
24
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:
25
|
|
•
|
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.
|
26
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.
27
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:
|
28
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.
|
29
|
(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:
30
|
|
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
|
31
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”).
32
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.
33
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.
34
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.
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
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.
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
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.
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.
35
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.
36
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).
37
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.
38
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
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.
In 2017, the Company paid $42,000 for the ongoing Kokopelli
development program in Colorado. The Company funded this program through the use
of a combination of cash on hand and the loans from the companies associated
with a director and officer of the Company.
|
C.
|
Research and Development, Patents and Licenses,
etc.
|
None.
The general outlook for crude oil prices will be tied primarily
to the supply response to the current price environment and the pace of growth
of the global economy. Overall, crude oil price volatility and a modest price
improvement are expected in 2018. Agreement to extend production cuts through to
the end of 2018 led by OPEC will support oil prices through 2018.
In 2017, natural gas prices were higher than those in 2016.
This was the result of consumption exceeding production and supply, leading to
lower inventory level. Prices are expected to be higher again in 2018 since
there is higher probability of an increase in natural gas consumption as a
result of colder weather per forecast.
|
E.
|
Off-Balance Sheet
Arrangements
|
The Company has no material undisclosed off-balance sheet
arrangements that have or are reasonably likely to have, a current or future
effect on our results of operations or financial condition at December 31, 2017.
|
F.
|
Tabular Disclosure of Contractual
Obligations
|
As of December 31, 2017, and in the normal course of business
we have obligations to make future payments, representing contracts and other
commitments that are known and committed.
39
|
(CA$ 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.
|
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
|
40
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
.
|
41
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.
42
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".
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.
43
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.
|
44
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:
45
|
|
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.
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.
46
|
(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.
47
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”.
The Company had the equivalent of approximately 10 full-time
employees and consultants during 2017.
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.
48
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
.
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.
49
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”.
|
50
|
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.
None.
51
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
|
|
|
|
|
|
|
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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
|
|
|
|
|
|
|
|
|
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Quarterly High and Low
Market Prices – Past 2
Years
|
|
|
|
|
|
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|
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
|
|
|
|
|
|
|
|
|
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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.
Not Applicable.
52
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”.
Not Applicable.
Not Applicable.
Not Applicable.
ITEM 10. ADDITIONAL INFORMATION
Not Applicable.
|
B.
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Memorandum and Articles of
Association
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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.
53
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:
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•
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Borrow money in a manner and amount, on any security,
from any source and upon any terms and conditions as they deem
appropriate;
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•
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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;
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•
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Guarantee the repayment of money by any other person or
the performance of any obligation of any other person; and
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•
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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:
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(a)
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is or was a director, alternate director, officer,
employee or agent of the Company;
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(b)
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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;
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(c)
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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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54
|
(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;
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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:
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(a)
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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;
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(b)
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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;
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(c)
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subdivide or consolidate all or any of its unissued, or
fully paid issued, shares;
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(d)
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if the Company is authorized to issue shares of a class
or shares with par value;
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(i)
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decrease the par value of those shares; or
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(ii)
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if none of the shares of that class of shares are
allotted or issued, increase the par value of those
shares;
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(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;
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(f)
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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
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(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.
55
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:
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•
|
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;
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•
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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
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•
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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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56
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:
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|
•
|
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;
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•
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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
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•
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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:
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•
|
the rate or amount of dividends, whether
cumulative, non-cumulative or partially cumulative and the dates, places
and currencies of payment thereof;
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•
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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;
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•
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the terms and conditions of any share purchase
plan or sinking fund;
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•
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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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57
|
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•
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voting rights; and
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•
|
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.
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.
58
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.
59
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.
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.
60
The following investments by non-Canadians are subject to
notification under the ICA:
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(a)
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an investment to establish a new Canadian business;
and
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(b)
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an investment to acquire control of a Canadian business
that is not reviewable pursuant to the ICA.
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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:
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(a)
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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;
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(b)
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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
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(c)
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the limits set out in paragraph (a) apply to all
investors for acquisitions of a Canadian business that is a cultural
business.:
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WTO Investor as defined in the ICA means:
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(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;
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(b)
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a government of a WTO Member, whether federal, state or
local, or an agency thereof;
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an entity that is not a Canadian-controlled entity, and
that is a WTO investor-controlled entity, as determined in accordance with
the ICA;
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(c)
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a corporation or limited
partnership:
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(i)
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that is not a Canadian-controlled entity, as determined
pursuant to the ICA;
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(ii)
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that is not a WTO investor within the meaning of the
ICA;
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(iii)
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of which less than a majority of its voting interests are
owned by WTO investors;
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(iv)
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that is not controlled in fact through the ownership of
its voting interests; and
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(v)
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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;
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(i)
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that is not a Canadian-controlled entity, as determined
pursuant to the ICA;
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(ii)
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that is not a WTO investor within the meaning of the
ICA;
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(iii)
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that is not controlled in fact through the ownership of
its voting interests, and
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(iv)
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of which two thirds of its trustees are any combination
of Canadians and WTO investors, or
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(e)
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any other form of business organization specified by the
regulations that is controlled by a WTO investor.
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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.
61
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.
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.
62
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:
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•
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an individual who is a citizen or resident of
the U.S.;
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•
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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;
|
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•
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an estate whose income is subject to U.S.
federal income taxation regardless of its source; or
|
63
|
•
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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.
64
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.
65
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.
66
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.
67
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.
Not Applicable.
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.
68
|
I.
|
Subsidiary Information
|
Not applicable.
69
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.
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.
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.
70
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.
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
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.
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.
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.
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.
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.
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.
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.
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.
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 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.
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.
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).
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:
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.
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.
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.
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%).
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.
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.
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.
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 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 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:
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 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 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.
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 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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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:
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.
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.
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.
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.
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.
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.
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.
Exploration and evaluation (“E&E”) assets consist of the
Company’s exploration projects which are pending the determination of proven
reserves.
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.
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:
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
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)
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.
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)
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.
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)
|
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.
|
|
|
|
|
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
|
|
|
|
|
|
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
|
|
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