Notes
to the Condensed Consolidated Financial Statements
December
31, 2015
1.
|
NATURE OF BUSINESS AND BASIS OF PRESENTATION
|
Nature
of Business
Deep
Well Oil & Gas, Inc. was originally incorporated on July 18, 1988 under the laws of the state of Nevada as Worldwide Stock
Transfer, Inc. (Worldwide Stock Transfer, Inc. later changed its name to Allied Devices Corporation) and in connection with a
plan of reorganization, effective on September 10, 2003, the company was reorganized and changed its name to Deep Well Oil &
Gas, Inc. (“Deep Well”).
These
condensed consolidated financial statements have been prepared showing the name “Deep Well Oil & Gas, Inc. (and Subsidiaries)”
(“the Company”) and the post-split common stock, with $0.001 par value.
Basis
of Presentation
The
interim condensed consolidated financial statements included herein have been prepared by the Company, without audit, pursuant
to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally
included in financial statements prepared in accordance with accounting principles generally accepted in the United States of
America (“US GAAP”) have been condensed or omitted pursuant to such rules and regulations, although the Company believes
that the disclosures are adequate so as to make the information presented not misleading.
These
interim condensed consolidated financial statements follow the same significant accounting policies and methods of application
as the Company’s annual consolidated financial statements for the year ended September 30, 2015.
These
statements reflect all adjustments, consisting solely of normal recurring adjustments (unless otherwise disclosed) which, in the
opinion of management, are necessary for a fair presentation of the information contained therein. However, the results of operations
for the interim periods may not be indicative of results to be expected for the full fiscal year. It is suggested that these condensed
consolidated financial statements be read in conjunction with the audited consolidated financial statements and notes thereto
included in the Company’s Annual Report on Form 10-K for the year ended September 30, 2015.
2.
|
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
|
Basis
of Consolidation
These
condensed consolidated financial statements include the accounts of two wholly owned subsidiaries: (1) Northern Alberta Oil Ltd.
(“Northern”) from the date of acquisition, being June 7, 2005, incorporated under the Business Corporations Act (Alberta),
Canada; and (2) Deep Well Oil & Gas (Alberta) Ltd., incorporated under the Business Corporations Act (Alberta), Canada on
September 15, 2005. All inter-company balances and transactions have been eliminated.
Change
in Accounting Principle
During
the fourth fiscal quarter of 2015, the Company voluntarily changed its method of accounting for its oil and gas properties from
the successful efforts method to the full cost method. Accordingly, financial information for prior periods have been recast to
reflect retrospective application of the full cost method. The Company believes that the full cost method is preferable as it
reflects the results of the Company’s operations and the economics of exploring for and developing its non-traditional long
life oil sands assets in the Peace River oil sands area in Alberta, Canada. The Company’s condensed consolidated financial
statements have been recast to reflect these differences. There was no effect on the prior period financial statements as a result
of the change in accounting policy.
Prepaid
Assets
$453,180
was held in trust for a potential acquisition which was not concluded by the Company and was subsequently returned to the Company
in May of 2016.
Crude
oil and natural gas properties
The
Company follows the full cost method of accounting for oil sands properties pursuant to SEC Regulation S-X Rule 4-10. The full
cost method of accounting for oil and gas operations requires that all costs associated with the exploration for and development
of oil and gas reserves be capitalized on a country by country basis. Such costs include lease acquisition costs, geological and
geophysical expenses, carrying charges on non-producing properties, costs of drilling both productive and non-productive wells,
production equipment and overhead charges directly related to acquisition, exploration and development activities.
Under
the full cost method, oil and gas properties are subject to the ceiling test performed quarterly. A ceiling test write-down is
recognized in net earnings if the carrying amount of a cost centre exceeds the “cost centre ceiling”. The carrying
amount of the cost centre includes the capitalized costs of proved oil and natural gas properties, net of accumulated depletion
and deferred income taxes. The cost centre ceiling is the sum of (A) present value of the estimated future net cash flows from
proved oil and natural gas reserves using a 10 percent per year discount factor, (B) the costs of unproved properties not being
amortized, and (C) the lower of cost or fair value of unproved properties included in the costs being amortized; less (D) related
income tax effects. As of December 31, 2015, no ceiling test write-downs were recorded for the Company’s oil and gas properties.
Costs
associated with unproved properties are excluded from the depletion calculation until it is determined that proved reserves are
attributable or impairment has occurred. Unproved properties are assessed annually for impairment. Costs that have been impaired
are included in the costs subject to depletion within the full cost pool.
Asset
Retirement Obligations
The
Company accounts for asset retirement obligations by recording the fair value of the estimated future cost of the Company’s
plugging and abandonment obligations. The asset retirement obligation is recorded when there is a legal obligation associated
with the retirement of a tangible long-lived asset and the fair value of the liability can reasonably be estimated. Upon initial
recognition of an asset retirement obligation, the Company increases the carrying amount of the long-lived asset by the same amount
as the liability. Over time, the liabilities are accreted for the change in their present value through charges to oil and gas
production and well operations costs. The initial capitalized costs are depleted over the useful lives of the related assets through
charges to depreciation, depletion, and amortization. If the fair value of the estimated asset retirement obligation changes,
an adjustment is recorded to both the asset retirement obligation and the asset retirement cost.
Revisions
in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs, and changes in the
estimated timing of settling asset retirement obligations. As of December 31, 2015 and September 30, 2015, asset retirement obligations
amount to $416,330 and $426,607, respectively. The Company has posted bonds, where required, with the Government of Alberta based
on the amount the government estimates the cost of abandonment and reclamation to be.
Financial,
Concentration and Credit Risk
The
Company’s consideration or related financial credit risk related to cash and cash equivalents depends on if funds are fully
insured by either The Canada Deposit Insurance Corporation (“CDIC”), or The Credit Union Deposit Guarantee Corporation
(“CUDGC”) deposit insurance limit. As of December 31, 2015, the Company has approximately $275,859 funds that are
in excess of deposit insurance limits, which may have financial credit risk. For the Company funds that are maintained in a financial
institution which has its deposits fully guaranteed by CUDGC, there is no financial credit risk.
The Company is not directly subject
to credit risk resulting from the concentration of its crude oil sales. For the period ending December 31, 2015 and for the year
ended September 30, 2015, the Company has recorded oil sales received from the operator of the Company’s producing properties.
The Company’s joint venture partner is the operator of the Company’s producing properties and it is the Company’s
joint venture partner who sells all of the Company’s oil production to 11 purchasers in the oil and gas industry. The Company
does not require collateral and management periodically evaluates the operator’s financial statements and the collectability
of oil sales receivables from the operator and believes that the Company’s oil sales receivables are fully collectable and
that the risk of loss is minimal.
Basic
and Diluted Net Income (Loss) Per Share
Basic
net income (loss) per share amounts are computed based on the weighted average number of shares actually outstanding. Diluted
net income (loss) per share amounts are computed using the weighted average number of common shares and common equivalent shares
outstanding as if shares had been issued on the exercise of the common share rights, unless the exercise becomes antidilutive
and then the basic and diluted per share amounts are the same. There were 65,105,221 potentially dilutive securities excluded
from the the diluted earnings per share calculation because their effect would be antidilutive.
Recently
Adopted Accounting Standards
In
June 2014, the FASB issued ASU 2014-10, “Development Stage Entities (Topic 915): Elimination of Certain Financial Reporting
Requirements, Including an Amendment to Variable Interest Entities Guidance in Topic 810, Consolidation”. The guidance eliminates
the definition of a development stage entity thereby removing the incremental financial reporting requirements from U.S. GAAP
for development or exploration stage entities, primarily presentation of inception to date financial information. The provisions
of the amendments are effective for annual reporting periods beginning after December 15, 2014, and the interim periods therein.
However, early adoption is permitted. Accordingly, the Company has adopted this standard as of September 30, 2014.
In
August 2015, the FASB issued ASU 2015-14, “Revenue from Contracts with Customers (Topic 606) — Deferral of the Effective
Date.” ASU 2015-14 defers the effective date of ASU 2014-09 by one year to annual reporting periods beginning after December
15, 2017 with early adoption permitted for periods beginning after December 15, 2016. The adoption of this standard is not expected
to have a material impact on the Company’s consolidated financial statements.
In
February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” requiring lessees to recognize lease assets and
lease liabilities for most leases classified as operating leases under previous U.S. GAAP. The guidance is effective for fiscal
years beginning after December 15, 2018, with early adoption permitted. The Company will be required to use a modified retrospective
approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements.
The adoption of this standard is not expected to have a material impact on the Company’s consolidated financial statements.
The
Company does not expect the adoption of any other recent accounting pronouncements to have a material impact on the Company’s
financial statements.
3.
|
OIL AND GAS PROPERTIES
|
The
Company’s oil sands acreage as of December 31, 2015, covers 43,015 gross acres (34,096 net acres) on 68 sections of land
under nine oil sands leases. Until the Company extends the leases “into perpetuity” based on the Alberta governmental
regulations, the lease expiration dates of the Company’s nine oil sands leases are as follows:
|
1)
|
32
sections of land under 5 oil sands leases are set to expire on July 10, 2018. Of the
5 oil sands leases totaling 32 sections of land, it is the Company’s opinion that
the Company has already met the governmental requirements on 17 of the 32 sections to
continue these sections into perpetuity. These 17 sections contain the majority of the
resources identified to date on these 5 oil sands leases. The Company has completed or
is in the process of applying for continuation of these leases or parts of the leases
where the majority of the oil sands resources have been confirmed;
|
|
2)
|
31
sections of land under 3 oil sands leases are set to expire on August 19, 2019; and
|
|
3)
|
5
sections of land under 1 oil sands lease are set expire on April 9, 2024. It is the Company’s
opinion that the Company has already met the governmental requirements for this lease
and it will be applying to continue all 5 sections of this lease into perpetuity.
|
Lease
Rental Commitments
The
Company has acquired interests in certain oil sands properties located in North Central Alberta, Canada. The terms include certain
commitments related to oil sands properties that require the payments of rents as long as the leases are non-producing. As of
December 31, 2015, the Company’s net payments due under this commitment are as follows:
|
|
|
(USD $)
|
|
|
(Cdn $)
|
|
|
2016
|
|
$
|
26,112
|
|
|
$
|
36,221
|
|
|
2017
|
|
$
|
34,815
|
|
|
$
|
48,294
|
|
|
2018
|
|
$
|
34,815
|
|
|
$
|
48,294
|
|
|
2019
|
|
$
|
21,251
|
|
|
$
|
29,478
|
|
|
2020
|
|
$
|
3,230
|
|
|
$
|
4,480
|
|
|
Subsequent
|
|
$
|
12,919
|
|
|
$
|
17,920
|
|
The
Company follows the full cost method of accounting for costs of oil properties. Under this method, oil and gas properties, for
which no proved reserves have been assigned, must be assessed at least annually to ascertain whether or not a write down should
occur. Unproven properties are assessed annually, or more frequently as economic events indicate, for potential write down.
This
consists of comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest
costs. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable
assumptions. Proven oil properties are reviewed for any write down on a field-by-field basis. No write downs were recognized for
the period ended December 31, 2015.
Capitalized
costs of proven oil properties will be depleted using the unit-of-production method when the property is placed in production.
Substantially
all of the Company’s oil activities are conducted jointly with others. The accounts reflect only the Company’s proportionate
interest in such activities.
4.
|
CAPITALIZATION
OF COSTS INCURRED IN OIL AND GAS ACTIVITIES
|
The
following table illustrates capitalized costs relating to oil producing activities for the three months ended December 31, 2015
and the fiscal year ended September 30, 2015:
|
|
|
December 31,
2015
|
|
|
September 30, 2015
|
|
|
Unproved Oil and Gas Properties
|
|
$
|
21,055,090
|
|
|
$
|
21,044,015
|
|
|
Proved Oil and Gas Properties
|
|
|
–
|
|
|
|
–
|
|
|
Accumulated Depreciation and Depletion
|
|
|
(65,216
|
)
|
|
|
(62,363
|
)
|
|
Net Capitalized Cost
|
|
$
|
20,989,874
|
|
|
$
|
20,981,652
|
|
Depreciation
and depletion expense for the three months ended December 31, 2015 and 2014 were $2,853 and $3,136 respectively.
5.
|
EXPLORATION ACTIVITIES
|
The
following table presents information regarding the Company’s costs incurred in the oil property acquisition, exploration
and development activities for the three months ended December 31, 2015 and the fiscal year ended September 30, 2015:
|
|
|
December 31,
2015
|
|
|
September 30, 2015
|
|
|
Acquisition of Properties:
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
–
|
|
|
$
|
–
|
|
|
Unproved
|
|
$
|
11,076
|
|
|
$
|
135,575
|
|
|
Exploration costs
|
|
$
|
847
|
|
|
$
|
46,351
|
|
|
Development costs
|
|
$
|
–
|
|
|
$
|
–
|
|
6.
|
SIGNIFICANT TRANSACTIONS WITH RELATED PARTIES
|
Accounts
payable – related parties was $2,002 as of December 31, 2015 (September 30, 2015 - $4,833) for expenses to be reimbursed
to directors. This amount is unsecured, non-interest bearing, and has no fixed terms of repayment.
As
of December 31, 2015, officers, directors, their families, and their controlled entities have acquired 53.63% of the Company’s
outstanding common capital stock. This percentage does not include unexercised warrants or stock options.
The
Company incurred expenses $33,714 to one related party, Concorde Consulting, for professional fees and consulting services provided
to the Company during the period ended December 31, 2015 (December 31, 2014 - $39,618). These amounts were fully paid as of December
31, 2015.
7.
|
ASSET RETIREMENT OBLIGATIONS
|
The
total future asset retirement obligation is estimated by management based on the Company’s net working interests in all
wells and facilities, estimated costs as determined by the Alberta Energy Regulator to reclaim and abandon wells and facilities
and the estimated timing of the costs to be incurred in future periods. At December 31, 2015, the Company estimates the undiscounted
cash flows related to asset retirement obligation to total approximately $582,649 (September 30, 2015 - $602,613). The fair value
of the liability at December 31, 2015 is estimated to be $416,330 (September 30, 2015 - $426,607) using a risk free rate of 3.74%
and an inflation rate of 2%. The actual costs to settle the obligation are expected to occur in approximately 27 years.
Changes
to the asset retirement obligation were as follows:
|
|
|
December 31, 2015
|
|
|
September 30, 2015
|
|
|
Balance, beginning of period
|
|
$
|
426,607
|
|
|
$
|
469,013
|
|
|
Liabilities incurred
|
|
|
–
|
|
|
|
35,031
|
|
|
Effect of foreign exchange
|
|
|
(14,285
|
)
|
|
|
(93,421
|
)
|
|
Disposal
|
|
|
–
|
|
|
|
–
|
|
|
Accretion expense
|
|
|
4,008
|
|
|
|
15,984
|
|
|
Balance, end of period
|
|
$
|
416,330
|
|
|
$
|
426,607
|
|
Common
Stock Issued and Outstanding
As
of December 31, 2015, the Company had outstanding 229,374,605 shares of common stock.
Warrants
The
following table summarizes the Company’s warrants outstanding as of December 31, 2015:
|
|
|
Shares Underlying
Warrants Outstanding
|
|
|
Shares Underlying
Warrants Exercisable
|
|
|
Range of Exercise Price
|
|
Shares Underlying Warrants Outstanding
|
|
|
Weighted Average Remaining Contractual Life
|
|
|
Weighted Average Exercise Price
|
|
|
Shares Underlying Warrants Exercisable
|
|
|
Weighted Average Exercise Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$0.105 at December 31, 2015
|
|
|
52,155,221
|
|
|
|
0.90
|
|
|
$
|
0.105
|
|
|
|
52,155,221
|
|
|
$
|
0.105
|
|
|
$0.075 at December 31, 2015
|
|
|
520,000
|
|
|
|
0.47
|
|
|
|
0.075
|
|
|
|
520,000
|
|
|
|
0.075
|
|
|
|
|
|
52,675,221
|
|
|
|
0.89
|
|
|
$
|
0.105
|
|
|
|
52,675,221
|
|
|
$
|
0.105
|
|
The
following is a summary of warrant activity for the period ended December 31, 2015:
|
|
|
Number of Warrants
|
|
|
Weighted Average Exercise Price
|
|
|
Intrinsic Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30, 2015
|
|
|
52,675,221
|
|
|
$
|
0.105
|
|
|
$
|
–
|
|
|
Cancelled
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
Granted
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
Exercised
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
Balance, December 31, 2015
|
|
|
52,675,221
|
|
|
$
|
0.105
|
|
|
$
|
–
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding Warrants, December 31, 2015
|
|
|
52,675,221
|
|
|
$
|
0.105
|
|
|
$
|
–
|
|
There
were 52,675,221 warrants outstanding as of December 31, 2015 (September 30, 2015 – 52,675,221), which have a historical
fair market value of $3,153,216 (September 30, 2015 - $3,153,216).
For
the period ended December 31, 2015, the Company recorded share based compensation expense related to stock options in the amount
of $68,654 (September 30, 2015 – $1,116,544) on the stock options that were previously granted. As of December 31, 2015,
there was remaining unrecognized compensation cost of $171,631 related to the non-vested portion of these unit option awards.
Compensation expense is based upon straight-line depreciation of the grant-date fair value over the vesting period of the underlying
unit option.
|
|
|
Shares Underlying
Options Outstanding
|
|
|
Shares Underlying
Options Exercisable
|
|
|
Range of Exercise Price
|
|
Shares Underlying Options Outstanding
|
|
|
Weighted Average Remaining Contractual Life
|
|
|
Weighted Average Exercise Price
|
|
|
Shares Underlying Options Exercisable
|
|
|
Weighted Average Exercise Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$0.14 at December 31, 2015
|
|
|
900,000
|
|
|
|
0.23
|
|
|
$
|
0.14
|
|
|
|
900,000
|
|
|
$
|
0.14
|
|
|
$0.05 at December 31, 2015
|
|
|
3,450,000
|
|
|
|
2.47
|
|
|
|
0.05
|
|
|
|
3,450,000
|
|
|
|
0.05
|
|
|
$0.30 at December 31, 2015
|
|
|
250,000
|
|
|
|
2.83
|
|
|
|
0.30
|
|
|
|
250,000
|
|
|
|
0.30
|
|
|
$0.34 at December 31, 2015
|
|
|
450,000
|
|
|
|
2.93
|
|
|
|
0.34
|
|
|
|
450,000
|
|
|
|
0.34
|
|
|
$0.38 at December 31, 2015
|
|
|
6,780,000
|
|
|
|
3.72
|
|
|
|
0.38
|
|
|
|
5,320,000
|
|
|
|
0.38
|
|
|
$0.23 at December 31, 2015
|
|
|
600,000
|
|
|
|
3.88
|
|
|
|
0.23
|
|
|
|
400,000
|
|
|
|
0.23
|
|
|
|
|
|
12,430,000
|
|
|
|
3.08
|
|
|
$
|
0.26
|
|
|
|
10,770,000
|
|
|
$
|
0.25
|
|
The
aggregate intrinsic value of exercisable options as of December 31, 2015, was $Nil (September 30, 2015 - $Nil).
The
following is a summary of stock option activity as at December 31, 2015:
|
|
|
Number of Underlying Shares
|
|
|
Weighted Average Exercise Price
|
|
|
Weighted Average Fair Market Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30, 2015
|
|
|
12,430,000
|
|
|
$
|
0.26
|
|
|
$
|
0.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2015
|
|
|
12,430,000
|
|
|
$
|
0.26
|
|
|
$
|
0.21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable, December 31, 2015
|
|
|
10,770,000
|
|
|
$
|
0.25
|
|
|
$
|
0.20
|
|
There
were 1,660,000 unvested stock options outstanding as of December 31, 2015 (September 30, 2015 – 2,010,000).
10.
|
CHANGES
IN NON-CASH WORKING CAPITAL
|
|
|
|
Three Months Ended
|
|
|
Three Months Ended
|
|
|
|
|
December 31, 2015
|
|
|
December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable decrease
|
|
$
|
43,024
|
|
|
$
|
693,356
|
|
|
Prepaid expenses increase
|
|
|
442,548
|
|
|
|
1,855
|
|
|
Accounts payable decrease
|
|
|
19,618
|
|
|
|
(363,263
|
)
|
|
|
|
$
|
(465,954
|
)
|
|
$
|
331,948
|
|
Compensation
to Directors
Concorde
Consulting, a company owned 100% by Mr. Curtis J. Sparrow, for providing services as Chief Financial Officer to the Company for
$11,238 per month (Cdn $15,000 per month). As of December 31, 2015, the Company did not owe Concorde Consulting any of this amount.
Rental
Agreement
On
July 27, 2015, the Company renewed its Edmonton office lease commencing effective on July 1, 2015 and expiring on June 30, 2017.
The quarterly payments due are as follows:
|
|
|
USD $
|
|
|
Cdn $
|
|
|
2016 Q2 (January - March)
|
|
$
|
5,745
|
|
|
$
|
7,969
|
|
|
2016 Q3 (April - June)
|
|
$
|
5,745
|
|
|
$
|
7,969
|
|
|
2016 Q4 (July - September)
|
|
$
|
5,745
|
|
|
$
|
7,969
|
|
|
2017 Q1 (October - December)
|
|
$
|
5,745
|
|
|
$
|
7,969
|
|
|
2017 Q2 (January - March)
|
|
$
|
5,745
|
|
|
$
|
7,969
|
|
|
2017 Q3 (April - June)
|
|
$
|
5,745
|
|
|
$
|
7,969
|
|
On
March 23, 2016, 900,000 stock options previously granted on March 23, 2011 to two directors, expired unexercised.
On
June 20, 2016, warrants to acquire up to 520,000 common shares of the Company, expired unexercised.
On
November 23, 2016, warrants to acquire up to 52,155,221 common shares of the Company, expired unexercised.
On
June 19, 2017, the Company renewed its Edmonton office lease commencing effective on July 1, 2017 and expiring on June 30, 2019.
As part of the lease renewal the Company received the first 3 months of basic rent free. The quarterly payments due are as follows:
|
|
|
USD $
|
|
|
Cdn $
|
|
|
2017 Q4 (July - September)
|
|
$
|
–
|
|
|
$
|
–
|
|
|
2018 Q1 (October - December)
|
|
$
|
5,745
|
|
|
$
|
7,969
|
|
|
2018 Q2 (January - March)
|
|
$
|
5,745
|
|
|
$
|
7,969
|
|
|
2018 Q3 (April - June)
|
|
$
|
5,745
|
|
|
$
|
7,969
|
|
|
2018 Q4 (July - September)
|
|
$
|
5,745
|
|
|
$
|
7,969
|
|
|
2019 Q1 (October - December)
|
|
$
|
5,745
|
|
|
$
|
7,969
|
|
|
2019 Q2 (January - March)
|
|
$
|
5,745
|
|
|
$
|
7,969
|
|
|
2019 Q3 (April - June)
|
|
$
|
5,745
|
|
|
$
|
7,969
|
|
First
production from the Company’s joint Steam Assisted Gravity Drainage Demonstration Project (the “SAGD Project”)
began on September 16, 2014. As a result of the low-price environment for bitumen in 2015 and early 2016, a majority of the Company’s
Joint Venture partners voted to temporarily suspend operations of the SAGD Project at the end of February 2016. In early May of
2016, an amended application was submitted to the AER for an expansion of the existing SAGD Project facility site which would
potentially increase the operation for up to a total of eight SAGD well pairs. The amended application sought approval to expand
the existing SAGD Project facility site to 3,200 bopd (100% basis). It is anticipated that only five SAGD well pairs need to be
operating to achieve this production level. The expanded facility will be designed to handle up to 3,200 bopd. The AER approval
for the expansion of the existing SAGD Project was granted on December 14, 2017. While the joint venture has not yet approved
to expand the SAGD Project, currently, the SAGD Project continues to move forward with engineering and identification of long
lead time items towards potential expansion to 3,200 bopd and future development at Sawn Lake.