CAMARILLO, CA, March 23, 2017 /PRNewswire/ -
All amounts are in U.S. Dollars unless otherwise indicated:
2016 HIGHLIGHTS
- In October 2016, the Company
completed an equity offering issuing 70,000,000 shares at a price
of C$0.20 per share. The Company
intends to use the net proceeds from this offering for exploration
and development of its Tishomingo Field, located in Oklahoma, including funding a drilling program
and for general working capital. The net cash proceeds of the
equity offering totalled $9.7
million
- The Company had oil hedges in place for almost 80% of its
production during 2016 at an average price of $65.22/bbl. In 2017, the Company has a comparable
percentage of oil hedged on its forecasted existing production at
$61.55/bbl, excluding the new
production that it expects to generate from its 2017 drilling
program.
- Operating cash flow was $5.2
million for 2016
- The Company's Total Proved Reserves increased by 1% to 18
million barrels of oil equivalent (BOE) and the Proved plus
Probable Reserves increased by 2% to 42 million BOEs based on the
Company's December 31, 2016
independent reserves evaluation.
- The estimated ultimate recovery from the Company's previously
existing producing wells increased by 1.2 million BOEs, as the
existing producing wells once again exceeded the previous year
forecast based on the Company's December 31,
2016 independent reserves evaluation
- Average production was 1,045 barrels of oil equivalent per day
(BOEPD) for 2016, a decrease of 26% compared to 2015 production of
1,415 BOEPD due to normal production decline as the Company did not
drill or complete any new wells in 2016 and also had three wells
shut-in during the fourth quarter due to offset fracture
stimulation operations by another operator
- General & administrative expenses related to continuing
operations decreased by 21% compared to 2015 due to the Company's
continuing cost cutting efforts
- Average netbacks were $16.76 per
BOE for 2016, a decrease of 21% compared to 2015 due to lower
prices in 2016 and slightly higher operating costs per barrel.
However, if the realized gains from the commodity hedge contracts
discussed above are included, the average netbacks for the year
increase by almost $11/barrel to
$27.70 per BOE
- In 2017, the Company drilled and fracture stimulated the
Chandler 8-6H well, the first well in its 2017 drilling program, in
which it holds a 99.9% working interest
- The Company also drilled the Hartgraves 1-6H well, the second
well in its 2017 drilling program, in which it holds a 100% working
interest. The Company expects to begin fracture stimulation of the
well in May
- The third well in the 2017 drilling program, the Brock 9-2H
well, is currently being drilled by the Company. The Company has a
100% working interest in that well and expects to begin fracture
stimulation operations in May
- During 2016, the Company made paydowns totaling $3.9 million on its credit facility to reduce the
outstanding balance to $20.5 million.
In the fourth quarter of 2016, the existing lenders reaffirmed the
Company's available borrowing capacity at $24.4 million.
- Revenue, net of royalties was $8.6
million for 2016 compared to $13.7
million in 2015 due to lower prices in 2016 and reduced
production
- A net loss of $11.1 million was
incurred in 2016 which included an $8.0
million unrealized loss on risk management contracts.
- Cash and working capital totaled $11.1
million and $10.6 million
respectively at December 31,
2016
BNK's President and Chief Executive Officer, Wolf Regener commented:
"With the proceeds from the equity offering that was completed
in October 2016, we were excited to
begin our 2017 drilling program at the end of the year. We
drilled and completed the Chandler 8-6H well (99.9% working
interest), which was our first well in the 2017 drilling program,
during the first quarter of 2017. The 30 day initial production
rate (IP) is 230 barrels of oil per day and 265 barrels of oil
equivalent per day. The well continues to produce a higher
oil percentage (87%) than expected from this part of the field
while still continuing to clean up. The well is
producing in line with our proved undeveloped (PUD) case type curve
for oil that is used to estimate the reserves attributed to the
Company's Tishomingo Field.
"The Hartgraves 1-6H well (100% working interest), which is the
second well in our 2017 drilling program, was successfully drilled
in the first quarter and we expect to begin fracture stimulation
operations in May.
"In addition, we are currently drilling the third well in our
drilling program, the Brock 9-2H well (100% working
interest). We expect to finish the drilling operations in
April with fracture stimulation to follow after the Hartgraves 1-6H
stimulation. The drilling and completion plan for the well
has been modified based on the learnings from the more easterly
located Chandler 8-6H well. The Company expects these changes
to result in making even better wells that exceed our PUD case type
curve as we step out further to the East.
"Despite the continued lower level of oil prices during 2016,
the Company was able to realize higher prices on a significant
amount of its production due to its hedging program. During
the year, the Company was able to realize an average price of
$65.22/bbl on almost 80% of its oil
production. This trend will continue into 2017 as the Company
has commodity contracts in place to recognize a price of
$61.55/bbl on 80% of existing
production going forward, excluding the new production coming
on-line from the 2017 drilling program.
"The Company's Total Proved Reserves increased by 1% to 18
million BOEs and the Proved plus Probable Reserves increased by 2%
to 42 million BOEs, despite not drilling any wells in 2016.
In addition, the estimated ultimate recovery from the Company's
previously existing producing wells increased by 1.2 million BOEs,
as the existing producing wells once again exceeded the previous
year forecast.
"We continue to generate positive cash flow due to our cost
cutting efforts and the impact of our hedging program. The
Company generated $5.2 million of
operating cash flows during 2016, a decrease of only 7% from
2015.
"During 2016, the Company's production declined by 26% to 1,045
boepd due to the normal production decline as the Company did not
have any new production during 2016. We also had three wells
that were shut-in during part of the fourth quarter of 2016, due to
offset fracture stimulation operations by another operator in the
Woodford formation. The
operator completed the fracture stimulations in the first quarter
of 2017 and all of these wells have been brought back on to
production. The Company does not expect any impact on the
long-term production of the wells going forward.
"Our continuing cost cutting efforts continue to result in
significant cost reductions with general and administrative
expenses decreasing by 21% during 2016 compared to the prior
year. In addition, the shutdown of the European operations
will contribute to the cost reduction efforts as these discontinued
operations incurred a net loss of $1.2
million in 2016.
"Average netbacks for 2016 were $16.76, a decrease of 21% compared to the prior
year due to lower prices. If we include the impact of the
realized gains from the commodity hedging contracts, our average
netbacks for 2016 would be $27.70,
which is a decrease of only 6% compared to 2015."
|
Fourth
Quarter
|
|
Year Ended
|
|
|
2016
|
2015
|
%
|
2016
|
2015
|
%
|
|
|
|
|
|
|
|
Net Loss:
|
|
|
|
|
|
|
$
Thousands
|
$(3,745)
|
$(6,350)
|
-%
|
$(11,148)
|
$(6,570)
|
-%
|
$ per common
share
|
$(0.02)
|
$(0.04)
|
-%
|
$(0.06)
|
$(0.04)
|
-%
|
assuming
dilution
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
Expenditures
|
$1,751
|
$417
|
320%
|
$2,497
|
$9,526
|
(74%)
|
|
|
|
|
|
|
|
Average Production
(Boepd)
|
661
|
1,367
|
(52%)
|
1,045
|
1,415
|
(26%)
|
Gross
Revenue
|
2,258
|
3,629
|
(38%)
|
11,084
|
17,606
|
(37%)
|
Average Product Price
per Barrel
|
$37.13
|
$28.86
|
29%
|
$28.98
|
$34.09
|
(15%)
|
Average Netback per
Barrel
|
$20.97
|
$17.10
|
23%
|
$16.76
|
$21.10
|
(21%)
|
Average Price per
Barrel
including Commodity Contracts
|
$47.56
|
$40.24
|
18%
|
$39.92
|
$42.42
|
(6%)
|
Average Netback per
Barrel
including Commodity Contracts
|
$31.40
|
$28.48
|
10%
|
$27.70
|
$29.43
|
(6%)
|
|
|
|
|
|
|
|
|
|
December
2016
|
|
December
2015
|
|
|
|
|
|
|
|
|
|
Cash and Cash
Equivalents
|
|
$11,101
|
|
$1,666
|
|
Working
Capital
|
|
$10,640
|
|
$7,298
|
|
Year Ended 2016 to Year Ended 2015
For 2016, oil and natural gas revenues net of royalties
decreased $5,135,000 or 37% to
$8,578,000. Oil revenues before
royalties decreased by 39% to $9,008,000 due to a 14% decrease in prices
between years and a 29% decrease in production. Natural gas
revenues before royalties declined $569,000 or 41% due to a 17% decrease in natural
gas prices per mcf and a 29% decrease in average production.
NGL revenue before royalties declined $138,000 or 10% due to a 14% decrease in
production partially offset by a 4% increase in average prices.
Exploration and evaluation expenses increased $789,000. The 2016 amount includes an
impairment of $835,000 on exploration
and evaluation leases.
Depletion and depreciation expense decreased $2,726,000 primarily due to reduced
production.
General and administrative expenses decreased $1,029,000 due to the Company's cost cutting
efforts during 2016 and 2015 which resulted in lower salary and
benefit costs due to decreased headcount, legal and professional
fees and travel costs.
Finance income decreased $4,157,000 due to an unrealized gain on risk
management contracts in 2015 of $3,975,000. Finance expense increased
$7,861,000 due to an unrealized loss
on risk management contracts of $8,027,000 in 2016.
Capital expenditures of $2,497,000
were incurred in 2016 mainly for drilling and completion costs in
Oklahoma during the fourth quarter
of the year.
FOURTH QUARTER HIGHLIGHTS:
- Revenue, net of royalties, was $1.8
million for fourth quarter 2016, a decrease of 42% compared
to the fourth quarter 2015 due to lower prices and decreased
production
- Cash flow from operations was $0.5
million in the fourth quarter of 2016 compared to
$1.0 million in prior year fourth
quarter mainly due to the shut-in of three wells during 2016
- Average netbacks for the fourth quarter of 2016 were
$20.97, an increase of 23% over
fourth quarter 2015 due to price increases. If the realized gains
from the commodity contracts are included, the average netbacks for
the fourth quarter of 2016 increase by more than $10/barrel to $31.40 per BOE compared to $28.48 per BOE for the fourth quarter of
2015
- Average production for the quarter was 661 BOEPD, a decrease of
52% compared to the prior year fourth quarter mainly due the three
shut-in wells, all of which have been brought back on production in
early 2017
- G&A expense decreased by $0.3
million, or 27%, due to the Company's cost cutting
efforts
- A net loss of $3.7 million was
incurred in the fourth quarter 2016 due primarily to unrealized
losses on commodity contracts of $2.1
million and $0.8 million
impairment of exploration and evaluation assets
- The Company's lender reaffirmed the Company's current
outstanding borrowing base of $24.4
million
Fourth Quarter 2016 to Fourth Quarter 2015
Oil and gas revenues net of royalties totaled $1,750,000 in the quarter versus $3,008,000 in the fourth quarter of 2015.
Oil revenues were $1,910,000 in
the quarter versus $3,011,000 in the
fourth quarter of 2015, a decrease of 37% due to decreased
production of 47% partially offset by an increase in average oil
prices of 18%. Natural gas revenues decreased 46% due to the
decrease in the production of 59% partially offset by an increase
in natural gas prices of 32%. NGL revenue decreased 42% to
$213,000 as average NGL production
decreased by 60% partially offset by an average price increase of
45%.
Exploration and evaluation expenses increased $833,000 in 2016 compared to 2015. The 2016
amount includes an impairment of $835,000 on exploration and evaluation
leases.
Depletion and depreciation expense decreased $845,000 primarily due to reduced production.
General and administrative expenses decreased $318,000 between quarters due to the Company's
cost cutting efforts during 2016 and 2015 which resulted in lower
salary and benefit costs due to decreased headcount, legal and
professional fees and travel costs.
BNK PETROLEUM
INC.
CONDENSED
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
(Unaudited, Expressed
in Thousands of United States Dollars)
|
|
|
December
31,
|
|
December
31,
|
|
|
2016
|
|
2015
|
Current
assets
|
|
|
|
|
|
Cash and cash
equivalents
|
$
|
11,101
|
$
|
1,666
|
|
Trade and other
receivables
|
|
1,163
|
|
2,905
|
|
Deposits and prepaid
expenses
|
|
614
|
|
906
|
|
Fair value of
commodity contracts
|
|
650
|
|
4,459
|
|
|
13,528
|
|
9,936
|
|
|
|
|
|
Non-current
assets
|
|
|
|
|
|
Fair value of
commodity contracts
|
|
-
|
|
2,802
|
|
Property, plant and
equipment
|
|
133,476
|
|
136,233
|
|
Exploration and
evaluation assets
|
|
-
|
|
835
|
|
|
133,476
|
|
139,870
|
|
|
|
|
|
Total
assets
|
$
|
147,004
|
$
|
149,806
|
|
|
|
|
|
Current
liabilities
|
|
|
|
|
|
Trade and other
payables
|
$
|
2,888
|
$
|
2,638
|
|
|
2,888
|
|
2,638
|
|
|
|
|
|
Non-current
liabilities
|
|
|
|
|
|
Fair value of
commodity contracts
|
|
1,417
|
|
-
|
|
Loans and
borrowings
|
|
20,229
|
|
23,961
|
|
Asset retirement
obligations
|
|
785
|
|
788
|
|
|
22,431
|
|
24,749
|
|
|
|
|
|
Equity
|
|
|
|
|
|
Share
capital
|
|
289,549
|
|
279,859
|
|
Contributed
surplus
|
|
22,195
|
|
21,471
|
|
Deficit
|
|
(190,059)
|
|
(178,911)
|
Total
equity
|
|
121,685
|
|
122,419
|
|
|
|
|
|
Total equity and
liabilities
|
$
|
147,004
|
$
|
149,806
|
BNK PETROLEUM
INC.
CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE
LOSS
|
(Unaudited,
expressed in Thousands of United States dollars, except per share
amounts)
|
|
|
|
Three months
ended
December
31
|
|
Year ended
December
31
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Revenue:
|
|
|
|
|
|
|
|
|
Oil and natural gas
revenue, net
|
$
|
1,750
|
$
|
3,008
|
$
|
8,578
|
$
|
13,713
|
Other
income
|
|
(19)
|
|
-
|
|
(17)
|
|
6
|
|
|
1,731
|
|
3,008
|
|
8,561
|
|
13,719
|
Expenses:
|
|
|
|
|
|
|
|
|
Exploration and
evaluation
|
|
835
|
|
2
|
|
835
|
|
46
|
Production and
operating
|
|
475
|
|
653
|
|
2,168
|
|
2,614
|
Depletion and
depreciation
|
|
868
|
|
1,713
|
|
5,249
|
|
7,975
|
General and
administrative
|
|
858
|
|
1,176
|
|
3,760
|
|
4,789
|
Share based
compensation
|
|
105
|
|
147
|
|
611
|
|
602
|
|
|
3,141
|
|
3,691
|
|
12,623
|
|
16,026
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Finance
income
|
|
634
|
|
3,034
|
|
4,184
|
|
8,341
|
Finance
expense
|
|
(2,674)
|
|
(522)
|
|
(10,100)
|
|
(2,239)
|
|
|
|
|
|
|
|
|
|
Net income/loss and
comprehensive
income/loss from continuing operations
|
$
|
(3,450)
|
|
1,829
|
|
(9,978)
|
|
3,795
|
|
Net loss and
comprehensive loss from
discontinued operations
|
|
(295)
|
|
(8,179)
|
|
(1,170)
|
|
(10,364)
|
Net loss and
comprehensive loss
|
$
|
(3,745)
|
$
|
(6,350)
|
$
|
(11,148)
|
$
|
(6,569)
|
|
|
|
|
|
|
|
|
|
Net income/loss per
share
|
|
|
|
|
|
|
|
|
|
Continuing
operations
|
|
(0.02)
|
|
0.01
|
|
(0.05)
|
|
0.02
|
|
Discontinued
operations
|
|
(0.00)
|
|
(0.05)
|
|
(0.01)
|
|
(0.06)
|
|
Basic and
Diluted
|
$
|
(0.02)
|
$
|
(0.04)
|
$
|
(0.06)
|
$
|
(0.04)
|
BNK PETROLEUM
INC.
|
FOURTH QUARTER AND
YEAR ENDED 2016
|
(Unaudited,
expressed in Thousands of United States dollars, except as
noted)
|
|
|
4th
Quarter
|
|
Year Ended Dec.
31
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Oil revenue before
royalties
|
$
|
1,910
|
|
3,011
|
|
9,008
|
|
14,823
|
Gas revenue before
royalties
|
|
135
|
|
249
|
|
829
|
|
1,398
|
NGL revenue before
royalties
|
|
213
|
|
369
|
|
1,247
|
|
1,385
|
Oil and Gas gross
revenue
|
|
2,258
|
|
3,629
|
|
11,084
|
|
17,606
|
|
|
|
|
|
|
|
|
|
Cash flow from
operating activities
|
|
454
|
|
1,039
|
|
5,180
|
|
5,581
|
Additions to
property, plant & equipment
|
|
(1,751)
|
|
(52)
|
|
(2,497)
|
|
(9,133)
|
Additions to
Exploration and Evaluation
Assets
|
|
-
|
|
(365)
|
|
-
|
|
(393)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statistics:
|
|
|
|
|
|
|
|
|
|
|
4th
Quarter
|
|
Year Ended Dec.
31
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Average oil
production (Bopd)
|
|
445
|
|
832
|
|
622
|
|
879
|
Average natural gas
production (mcf/d)
|
|
588
|
|
1,436
|
|
1,116
|
|
1,568
|
Average NGL
production (Boepd)
|
|
118
|
|
296
|
|
237
|
|
275
|
Average production
(Boepd)
|
|
661
|
|
1,367
|
|
1,045
|
|
1,415
|
Average oil price
($/bbl)
|
|
$46.63
|
|
$39.36
|
|
$39.59
|
|
$46.20
|
Average natural gas
price ($/mcf)
|
|
$2.50
|
|
$1.89
|
|
$2.03
|
|
$2.44
|
Average NGL price
($/bbl)
|
|
$19.61
|
|
$13.54
|
|
$14.36
|
|
$13.79
|
|
|
|
|
|
|
|
|
|
Average price per
barrel
|
|
$37.13
|
|
$28.86
|
|
$28.98
|
|
$34.09
|
Royalties per
barrel
|
|
8.35
|
|
6.57
|
|
6.55
|
|
7.94
|
Operating expenses
per barrel
|
|
7.81
|
|
5.19
|
|
5.67
|
|
5.05
|
Netback per
barrel
|
|
$20.97
|
|
$17.10
|
|
$16.76
|
|
$21.10
|
|
|
|
|
|
|
|
|
|
Average price per
barrel including commodity contracts
|
|
$47.56
|
|
$40.24
|
|
$39.92
|
|
$42.42
|
Royalties per
barrel
|
|
8.35
|
|
6.57
|
|
6.55
|
|
7.94
|
Operating expenses
per barrel
|
|
7.81
|
|
5.19
|
|
5.67
|
|
5.05
|
Netback per barrel
including commodity contracts
|
|
$31.40
|
|
$28.48
|
|
$27.70
|
|
$29.43
|
The information outlined above is extracted from and should be
read in conjunction with the Company's audited financial statements
for the year ended December 31, 2016
and the related management's discussion and analysis thereof,
copies of which are available under the Company's profile at
www.sedar.com.
NON-GAAP MEASURES
Netback per barrel, net operating income and funds from
operations (collectively, the "Company's Non-GAAP Measures") are
not measures recognized under Canadian generally accepted
accounting principles ("GAAP") and do not have any standardized
meanings prescribed by GAAP.
The Company's Non-GAAP Measures are described and reconciled to
the GAAP measures in the management's discussion and analysis which
are available under the Company's profile at www.sedar.com.
Cautionary Statements
In this news release and the Company's other public
disclosure:
(a)
|
The Company's natural
gas production is reported in thousands of cubic feet
("Mcfs"). The Company also uses references to barrels
("Bbls") and barrels of oil equivalent ("Boes") to
reflect natural gas liquids and oil production and sales. Boes may
be misleading, particularly if used in isolation. A Boe conversion
ratio of 6 Mcf:1 Bbl is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead. Given that the value
ratio based on the current price of crude oil as compared to
natural gas is significantly different from the energy equivalency
of 6:1, utilizing a conversion on a 6:1 basis may be misleading as
an indication of value.
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(b)
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Discounted and
undiscounted net present value of future net revenues attributable
to reserves do not represent fair market value.
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(c)
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Possible reserves are
those additional reserves that are less certain to be recovered
than probable reserves. There is a 10% probability that the
quantities actually recovered will equal or exceed the sum of
proved plus probable plus possible reserves.
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(d)
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The Company discloses
peak and 30-day initial production rates and other short-term
production rates. Readers are cautioned that such production
rates are preliminary in nature and are not necessarily indicative
of long-term performance or of ultimate recovery.
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Readers are referred to the full description of the results of
the Company's December 31, 2016
independent reserves evaluation and other oil and gas information
contained in its Form 51-101F1 Statement of Reserves Data and
Other Oil and Gas Information for the year ended December 31, 2016, which the Company filed on
SEDAR on March 23, 2017.
Caution Regarding Forward-Looking Information
This release contains forward-looking information including
information regarding the use of proceeds from the equity offering
completed in October 2016, estimates
of reserves, the proposed timing and expected results of
exploratory and development work including production from the
Company's Tishomingo field,
Oklahoma acreage, the future
performance of wells following shut-in and restart, the expected
effects of cost reduction efforts, availability of funds from the
Company's reserves based loan facility and the Company's strategy
and objectives. The use of any of the words "target", "plans",
"anticipate", "continue", "estimate", "expect", "may", "will",
"project", "should", "believe" and similar expressions are intended
to identify forward-looking statements.
Such forward-looking information is based on management's
expectations and assumptions, including that the Company's geologic
and reservoir models and analysis will be validated, that
indications of early results are reasonably accurate predictors of
the prospectiveness of the shale intervals, that previous
exploration results are indicative of future results and success,
that expected production from future wells can be achieved as
modeled, declines will match the modeling, future well production
rates will be improved over existing wells, that rates of return as
modeled can be achieved, that recoveries are consistent with
management's expectations, that additional wells are actually
drilled and completed, that design and performance improvements
will reduce development time and expense and improve productivity,
that discoveries will prove to be economic, that anticipated
results and estimated costs will be consistent with managements'
expectations, that all required permits and approvals and the
necessary labor and equipment will be obtained, provided or
available, as applicable, on terms that are acceptable to the
Company, when required, that no unforeseen delays, unexpected
geological or other effects, equipment failures, permitting delays
or labor or contract disputes are encountered, that the development
plans of the Company and its co-venturers will not change, that the
demand for oil and gas will be sustained, that the Company will
continue to be able to access sufficient capital through
financings, credit facilities, farm-ins or other participation
arrangements to maintain its projects, that the Company will
continue in compliance with the covenants under its reserves-based
loan facility and that the borrowing base will not be reduced, that
funds will be available from the Company's reserves based loan
facility when required to fund planned operations, that the Company
will not be adversely affected by changing government policies and
regulations, social instability or other political, economic or
diplomatic developments in the countries in which it operates and
that global economic conditions will not deteriorate in a manner
that has an adverse impact on the Company's business and its
ability to advance its business strategy.
Forward looking information involves significant known and
unknown risks and uncertainties, which could cause actual results
to differ materially from those anticipated. These risks include,
but are not limited to: any of the assumptions on which such
forward looking information is based vary or prove to be invalid,
including that the Company's geologic and reservoir models or
analysis are not validated, anticipated results and estimated costs
will not be consistent with managements' expectations, the risks
associated with the oil and gas industry (e.g. operational risks in
development, exploration and production; delays or changes in plans
with respect to exploration and development projects or capital
expenditures; the uncertainty of reserve and resource estimates and
projections relating to production, costs and expenses, and health,
safety and environmental risks including flooding and extended
interruptions due to inclement or hazardous weather), the risk of
commodity price and foreign exchange rate fluctuations, risks and
uncertainties associated with securing the necessary regulatory
approvals and financing to proceed with continued development of
the Tishomingo Field, the Company or its subsidiaries is not able
for any reason to obtain and provide the information necessary to
secure required approvals or that required regulatory approvals are
otherwise not available when required, that unexpected geological
results are encountered, that completion techniques require further
optimization, that production rates do not match the Company's
assumptions, that very low or no production rates are achieved,
that the Company will cease to be in compliance with the covenants
under its reserves-based loan facility and be required to repay
outstanding amounts or that the borrowing base will be reduced
pursuant to a borrowing base re-determination, that the Company is
unable to access required capital, that funding is not available
from the Company's reserves based loan facility at the times or in
the amounts required for planned operations, that occurrences such
as those that are assumed will not occur, do in fact occur, and
those conditions that are assumed will continue or improve, do not
continue or improve and the other risks identified in the Company's
most recent Annual Information Form under the "Risk Factors"
section, the Company's most recent management's discussion and
analysis and the Company's other public disclosure, available under
the Company's profile on SEDAR at www.sedar.com.
With respect to estimated reserves, the evaluation of the
Company's reserves is based on a limited number of wells with
limited production history and includes a number of assumptions
relating to factors such as availability of capital to fund
required infrastructure, commodity prices, production performance
of the wells drilled, successful drilling of infill wells, the
assumed effects of regulation by government agencies and future
capital and operating costs. All of these estimates will vary from
actual results. Estimates of the recoverable oil and natural gas
reserves attributable to any particular group of properties,
classifications of such reserves based on risk of recovery and
estimates of future net revenues expected therefrom, may vary. The
Company's actual production, revenues, taxes, development and
operating expenditures with respect to its reserves will vary from
such estimates, and such variances could be material. In
addition to the foregoing, other significant factors or
uncertainties that may affect either the Company's reserves or the
future net revenue associated with such reserves include material
changes to existing taxation or royalty rates and/or regulations,
and changes to environmental laws and regulations.
Although the Company has attempted to take into account
important factors that could cause actual costs or results to
differ materially, there may be other factors that cause actual
results not to be as anticipated, estimated or intended. There can
be no assurance that such statements will prove to be accurate as
actual results and future events could differ materially from those
anticipated in such statements. The forward-looking information
included in this release is expressly qualified in its entirety by
this cautionary statement. Accordingly, readers should not place
undue reliance on forward-looking information. The Company
undertakes no obligation to update these forward-looking
statements, other than as required by applicable law.
About BNK Petroleum Inc.
BNK Petroleum Inc.
is an international oil and gas exploration and production company
focused on finding and exploiting large, predominately
unconventional oil and gas resource plays. Through various
affiliates and subsidiaries, the Company owns and operates shale
gas properties and concessions in the
United States. Additionally the Company is utilizing its
technical and operational expertise to identify and acquire
additional unconventional projects. The Company's shares are traded
on the Toronto Stock Exchange under the stock symbol BKX.
SOURCE BNK Petroleum Inc.