Suite 901, 1015 – 4th Street SW | Calgary, Alberta T2R 1J4
Annual Report 2008
BONTERRA OIL & GAS 1
Sustainability.
Competitive Advantage.
2
9
0
2
0
4
8
5
_
B
o
n
t
e
r
r
a
E
n
e
r
g
y
S
h
e
e
t
w
i
s
e
0
9
-
0
3
-
2
6
1
5
:
2
7
:
0
8
1
F
r
o
n
t
-
-
k
e
r
i
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
B
l
a
c
k
P
A
N
T
O
N
E
6
5
3
C
P
A
N
T
O
N
E
4
1
0
C
Bonterra Oil & Gas Ltd. is a high-yield, dividend paying
oil and gas company headquartered in Calgary, Alberta
with a proven history of growth and long-term returns
for investors. It recently converted to a corporation
from an income trust and intends to continue with a
cash dividend policy similar to the distribution policy
previously followed by the Trust. The monthly dividend
amount will continue to be determined by commodity
prices and production volumes.
Bonterra’s asset base consists of stable, producing
properties located mainly in the Pembina field in central
Alberta and are characterized by a long reserve life and
low risk, predictable returns. Bonterra’s proven track
record of success is due to its experienced management
team, conservative capital structure and sustainable
pace of development, resulting in above-average results
and returns for investors.
Bonterra’s common shares trade on the Toronto Stock
Exchange under the symbol BNE.
Notice of Annual Meeting
The Annual Meeting of Shareholders will be held on
Thursday, May 21, 2009, in the Marquis Room at the
Fairmont Palliser, 133 Ninth Avenue SW, Calgary, Alberta
at 11:00 AM (Mountain Time).
Annual Highlights .....................................................2
Quarterly Highlights ..................................................3
Report to Shareholders ..............................................4
Review of Operations ................................................8
Property Discussions ................................................ 10
Statistical Review ..................................................... 12
BO NTER RA OIL & GAS LTD. 1
Experience.
CMY
Z
X
slurY
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CMY
CMYC 70MY
Z
X
Y
M
C
B
CMY
Z
X
slurM
CMYB 70
Z
X
Y
M
C
B
CMY
Z
X
CMYY 70X 70
Z
X
Y
M
C
B
CMY
Z
X
slurC
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CY
CM
CMYC 70
Z
X
Y
M
C
B
CMY
Z
X
slurB
CMYB 70
Z
X
C
B
CMY
Z
X
slurY
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CMY
CMYC 70MY
Z
X
Y
M
C
B
CMY
Z
X
slurM
CMYB 70
Z
X
Y
M
C
B
CMY
Z
X
CMYY 70X 70
Z
X
Y
M
C
B
CMY
Z
X
slurC
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CY
CM
CMYC 70
Z
X
Y
M
C
B
CMY
Z
X
slurB
CMYB 70
Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG
Annual Highlights
Annual Highlights
Financial ($000, except $ per share/unit)
Revenue – realized oil and gas
Cash payments per share/unit (1)
Cash flow from operations
Per Share/Unit Basic
Per Share/Unit Fully Diluted
Payout Ratio (1)
Net Earnings
Per Share/Unit Basic
Per Share/Unit Fully Diluted
Capital Expenditures and Acquisitions
Working Capital Deficiency
Long-term Debt
Shareholders’/Unitholders’ Equity
Shares / Units Outstanding
Operations
Oil and Liquids (barrels per day)
Average Price ($ per barrel)
Natural Gas (MCF per day)
Average Price ($ per MCF)
Total BOE per day (2)
Reserves
Oil and Liquids (barrels in 000s)
Proved Developed Producing (Gross) (3)
Proved (Gross)
Proved plus Probable (Gross)
Natural Gas (MCF in 000s)
Proved Developed Producing (Gross)
Proved (Gross)
Proved plus Probable (Gross)
Reserve Life Index (4) (oil, liquids and natural gas at 6:1) (years)
Proved Developed Producing (Gross)
Proved (Gross)
Proved plus Probable (Gross)
Reserves per Weighted Average Outstanding Share / Unit (BOE)
Proved Developed Producing (Gross)
Proved (Gross)
Proved plus Probable (Gross)
2008
2007
2006
121,730
3.12
69,570
4.07
4.06
77%
55,426
3.25
3.23
45,407
23,878
79,910
56,777
17,258
3,073
87.54
7,637
8.21
4,346
15,534
17,991
22,867
32,108
36,571
50,245
12.5
14.4
18.7
1.22
1.41
1.83
96,431
2.64
51,433
3.04
3.04
87%
30,350
1.79
1.79
19,300
58,766
-
44,376
16,928
3,113
70.31
6,627
6.75
4,218
14,468
17,472
21,910
19,863
24,125
32,465
11.3
13.7
17.4
1.05
1.27
1.62
88,734
2.82
51,944
3.10
3.08
91%
37,250
2.23
2.21
38,348
50,187
-
53,359
16,875
3,040
64.69
6,014
7.55
4,042
13,688
16,758
21,526
17,011
22,562
29,700
11.0
13.6
17.6
0.98
1.22
1.57
2 BON TERRA OIL & GAS LTD.
2
9
0
2
0
4
8
5
_
B
o
n
t
e
r
r
a
E
n
e
r
g
y
S
h
e
e
t
w
i
s
e
0
9
-
0
3
-
2
6
1
5
:
2
7
:
0
8
1
B
a
c
k
-
-
k
e
r
i
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
B
l
a
c
k
P
A
N
T
O
N
E
4
1
0
C
P
A
N
T
O
N
E
6
5
3
C
CMY
Z
X
slurY
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CMY
CMYC 70MY
Z
X
Y
M
C
B
CMY
Z
X
slurM
CMYB 70
Z
X
Y
M
C
B
CMY
Z
X
CMYY 70X 70
Z
X
Y
M
C
B
CMY
Z
X
slurC
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CY
CM
CMYC 70
Z
X
Y
M
C
B
CMY
Z
X
slurB
CMYB 70
Z
X
C
B
CMY
Z
X
slurY
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CMY
CMYC 70MY
Z
X
Y
M
C
B
CMY
Z
X
slurM
CMYB 70
Z
X
Y
M
C
B
CMY
Z
X
CMYY 70X 70
Z
X
Y
M
C
B
CMY
Z
X
slurC
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CY
CM
CMYC 70
Z
X
Y
M
C
B
CMY
Z
X
slurB
CMYB 70
Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG
2
9
0
2
0
4
8
5
_
B
o
n
t
e
r
r
a
E
n
e
r
g
y
S
h
e
e
t
w
i
s
e
0
9
-
0
3
-
2
6
1
5
:
2
7
:
0
8
1
B
a
c
k
-
-
k
e
r
i
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
B
l
a
c
k
P
A
N
T
O
N
E
4
1
0
C
P
A
N
T
O
N
E
6
5
3
C
Quarterly Highlights
2008
Financial ($000, except $ per share/unit)
Revenue – realized oil and gas sales
Cash flow from operations
Per Share/Unit Basic
Per Share/Unit Fully Diluted
Cash payments per share/unit (1)
Payout Ratio (1)
Net Earnings
Per Share/Unit Basic
Per Share/Unit Fully Diluted
Capital Expenditures and Acquisitions
Total Assets
Working Capital Deficiency
Long-term debt
Shareholders’/Unitholders’ Equity
Operations
Oil and Liquids (barrels per day)
Natural Gas (MCF per day)
Total BOE per day
4th
3rd
2nd
1st
22,613
10,336
0.59
0.59
0.62
105%
10,585
0.62
0.62
30,405
265,301
23,878
79,910
56,777
3,105
8,892
4,587
34,226
22,492
1.31
1.30
0.96
73%
21,125
1.23
1.22
6,038
150,120
47,499
-
57,623
3,013
7,233
4,219
34,398
20,530
1.21
1.20
0.84
69%
12,912
0.76
0.75
2,543
153,247
57,148
-
46,612
3,024
7,272
4,236
30,493
16,212
0.96
0.96
0.70
73%
10,804
0.64
0.64
6,421
150,169
57,810
-
48,136
3,153
7,139
4,343
(1) Cash payments per share/unit are based on payments made in respect of production months within the quarter.
(2) Barrels of oil equivalent (BOE) are calculated using a conversion ratio of 6 MCF to 1 barrel of oil. The conversion is based on an
energy equivalency convervsion method primarily applicable at the burner tip and does not represent a value equivalency at the
wellhead and as such may be misleading if used in isolation.
(3) Gross reserves relate to the Company’s ownership of reserves before deducting any royalties.
(4) The reserve life index is calculated by dividing the reserves (BOE) by the annualized fourth quarter average production rate
(2008 - 4,587 BOE per day; 2007 - 4,295 BOE per day; 2006 - 4,119).
BO NTER RA OI L & GAS LTD. 3
CMY
Z
X
slurY
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CMY
CMYC 70MY
Z
X
Y
M
C
B
CMY
Z
X
slurM
CMYB 70
Z
X
Y
M
C
B
CMY
Z
X
CMYY 70X 70
Z
X
Y
M
C
B
CMY
Z
X
slurC
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CY
CM
CMYC 70
Z
X
Y
M
C
B
CMY
Z
X
slurB
CMYB 70
Z
X
C
B
CMY
Z
X
slurY
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CMY
CMYC 70MY
Z
X
Y
M
C
B
CMY
Z
X
slurM
CMYB 70
Z
X
Y
M
C
B
CMY
Z
X
CMYY 70X 70
Z
X
Y
M
C
B
CMY
Z
X
slurC
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CY
CM
CMYC 70
Z
X
Y
M
C
B
CMY
Z
X
slurB
CMYB 70
Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG
Report to Shareholders
Bonterra Oil & Gas Ltd. (“Bonterra” or the “Company”) is pleased to report its operational, financial and reorganization results for the year
ending December 31, 2008. In assessing the year, the Company realized many positive events and results and a few negative results that
developed during the last four months of the year. These are generally attributable to severe changes in the world economy; events that
cannot be influenced by individual companies.
Highlights
• Net earnings increased substantially to $55.4 million or $3.25 per share as compared to $30.4 million or $1.79 per unit in 2007;
• Cash flow from operations totaled $69.6 million ($4.07 per share) in 2008, an increase of 35 percent year over year;
• Cash payment per share/unit to investors totaled $3.12, a substantial increase from the 2007 level of $2.64;
• The payout ratio of cash flow was 77 percent, within the Company’s annual target of 75 to 80 percent and a decrease from the 2007
level of 87 percent;
• Production increased to an all time high of 4,346 barrels of oil equivalent (BOE) per day as a result of the Company’s internal
development program and an acquisition during the year. Fourth quarter production totaled 4,587 BOE per day, an increase of nine
percent over the same period last year and the 2008 exit rate was 4,950 BOE per day;
• Reserves increased to 24.1 million BOE and 31.2 million BOE on a proved and a proved plus probable (P+P) basis, respectively.
This represents an increase of 12.1 percent to the Company’s proved reserves and a 14.4 percent increase to proved plus
probable reserves;
• Reserves per share on a P+P basis increased 13.0 percent to 1.83 BOE per share;
• Bonterra’s finding and development costs (F&D costs) including acquisitions in 2008 continue to be among the lowest in the
Canadian oil and gas industry. F&D three-year average costs were $12.30 per boe on a proved basis and $9.45 per BOE on a
P+P basis compared with the previous three year average (2005-2007) of $14.37 per boe on a proved basis and $11.07 per boe
on a P+P basis.
New Corporate Structure
Bonterra’s most notable achievement during the year was the successful conversion to a corporation from an income trust in
November, 2008. The conversion provides investors with enhanced certainty in regard to Bonterra’s ability to remain a high-income
generating investment while negating the overhang associated with the Canadian federal government’s legislation to tax trusts beginning
in 2011.
Cash Dividends/
Distributions to Investors
($ per unit/share)
90% 87% 91% 87%
100
77%
5
4
3
2
1
0
2004*
2005*
2006
2007
2008
Cash flow
from operations
Dividends/
distributions
Payout
ratio
* previously funds flow from operations
Reserves per Share/Unit
(BOE)
2.0
1.5
1.0
0.5
0.0
2004
2005
2006
2007
2008
80
60
40
20
0.0
Cash Flow Growth
($ thousands)
80,000
60,000
40,000
20,000
0
2004*
2005*
2006
2007
2008
* previously funds flow from operations
4 BON TERRA OIL & GAS LTD.
2
9
0
2
0
4
8
5
_
B
o
n
t
e
r
r
a
E
n
e
r
g
y
S
h
e
e
t
w
i
s
e
0
9
-
0
3
-
2
6
1
5
:
2
7
:
0
8
1
F
r
o
n
t
-
-
k
e
r
i
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
B
l
a
c
k
P
A
N
T
O
N
E
6
5
3
C
P
A
N
T
O
N
E
4
1
0
C
CMY
Z
X
slurY
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CMY
CMYC 70MY
Z
X
Y
M
C
B
CMY
Z
X
slurM
CMYB 70
Z
X
Y
M
C
B
CMY
Z
X
CMYY 70X 70
Z
X
Y
M
C
B
CMY
Z
X
slurC
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CY
CM
CMYC 70
Z
X
Y
M
C
B
CMY
Z
X
slurB
CMYB 70
Z
X
C
B
CMY
Z
X
slurY
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CMY
CMYC 70MY
Z
X
Y
M
C
B
CMY
Z
X
slurM
CMYB 70
Z
X
Y
M
C
B
CMY
Z
X
CMYY 70X 70
Z
X
Y
M
C
B
CMY
Z
X
slurC
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CY
CM
CMYC 70
Z
X
Y
M
C
B
CMY
Z
X
slurB
CMYB 70
Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG
CMY B 70
slurB
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70
CM
CY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurC
X
Z
CMY
B
C
M
Y
X
Z
CMY Y 70 X 70
X
Z
CMY
B
C
M
Y
X
Z
CMY B 70
slurM
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70 MY
CMY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurY
X
Z
CMY
B
C
X
Z
CMY B 70
slurB
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70
CM
CY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurC
X
Z
CMY
B
C
M
Y
X
Z
CMY Y 70 X 70
X
Z
CMY
B
C
M
Y
X
Z
CMY B 70
slurM
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70 MY
CMY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurY
X
Z
CMY
Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG
C
0
1
4
E
N
O
T
N
A
P
C
3
5
6
E
N
O
T
N
A
P
k
c
a
l
B
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
i
r
e
k
-
-
t
n
o
r
F
1
8
0
:
7
2
:
5
1
6
2
-
3
0
-
9
0
e
s
i
w
t
e
e
h
S
y
g
r
e
n
E
a
r
r
e
t
n
o
B
_
5
8
4
0
2
0
9
2
Select benefits of the new corporate structure include:
• The ability to continue to provide income oriented investors
with a substantial cash yield. Bonterra intends to continue with
a cash dividend policy similar to that followed by the Trust;
•
Substantial tax pools of approximately $465 million which will
currently allow Bonterra to extend its taxable horizon beyond
2018, subject to commodity prices;
• Higher after-tax earnings for investors as dividends are taxed
at lower rates than distributions;
• Removal of the growth limitations which currently exists under
the “normal growth” guidelines; and
• The flexibility to increase capital investment over the
next several years with a view to providing enhanced
returns to investors.
Maximizing Investor Returns
in an Uncertain Environment
As a corporation, Bonterra is well-positioned to be valued as a
growth-oriented, high-dividend paying corporation with a proven
history of growth and long-term returns for investors.
It is a long-term focus that has defined Bonterra’s ongoing business
strategy. Bonterra has continued to focus on paying dividends to
its investors, maintaining a strong balance sheet and exhibiting
spending discipline across all business cycles while the efficient
management of its high-quality, low-risk asset base provides
sustainability to the Company. With this approach, Bonterra
has been successful in offering above average results and returns
to its investors.
During the majority of 2008, the energy industry continued to
operate within a high commodity price environment. However,
during the last four months of 2008, the worldwide economic
downturn considerably impacted crude oil and natural gas prices
with substantial declines throughout the third and fourth quarters
of the year. As a result, Bonterra’s share price experienced a
significant devaluation, a common occurrence for share prices for all
publicly traded companies. Additionally, the low commodity prices
made it necessary to substantially reduce Bonterra’s monthly
distribution/dividends.
As always, the Company still maintains that the best assessment for
an entity is its return to investors. On a one-year basis, Bonterra’s
total return to shareholders in 2008 was -11 percent. This was a
disappointment as 2008 represents the only year in which a negative
return was recorded since inception in 1998. However, this does
compare well to both its peers and the major indices. As well, for
long-term holders of the Company, Bonterra has continued to
outperform both over longer periods of time.
Preserving Financial Strength
A conservative approach to the Company’s capital structure has
been a key factor in building financial strength and flexibility. A keen
focus is placed on managing operating and administrative costs to
maximize returns and position the Company for future growth.
The Company ended 2008 with a bank debt to cash flow ratio of
2.25 times (based on bank debt of $93.2 million and annualized 2008
fourth quarter cash flow from operations). This is substantially higher
than usual, even though it is in a range that is normal among its peers
at the present time. The main reason for the higher debt level is that
Production per Share/Unit
(BOE)
Bonterra vs. the Indices
0.10
0.08
0.06
0.04
0.02
0.00
2004
2005
2006
2007
2008
$250
$200
$150
$100
2003
2004
2005
2006
2007
2008
BNE
TSX Composite
Index
TSX Energy
Index
BO NTER RA OI L & GAS LTD. 5
when the company announced its reorganization and acquisition,
it had various types of options outstanding that were in the money
for approximately $35 million. At closing of the reorganization on
November 12, 2008, the world economy had changed substantially,
resulting in a large reduction in share prices. As a result, the majority
of the outstanding Bonterra options were not exercised. As well, the
Company experienced a decrease in cash flow due to the significant
drop in commodity prices during the latter half of the year.
Although the bank debt level is still very manageable, Bonterra
is focusing on attempting to reduce the bank debt to cash flow
ratio from anticipated increases in production levels and future
commodity prices or by issuing additional equity. This should allow
the Company to fund its upcoming capital development program
and take advantage of any acquisition opportunities as they
become available.
Organic Growth
Bonterra’s strategic capital development program is designed to
maximize asset development through infill drilling, workovers and
field optimization strategies. In 2008, Bonterra spent approximately
$45.4 million, including acquisitions, on its capital development
program, compared to $19.3 million the previous year. The capital
development program was successful in fully replacing 2008
annual production and substantially increasing overall reserves
and daily production.
Key attributes of the 2008 program included:
• The continued success of its Pembina Cardium infill drilling
program and successful expansion of its Edmonton shallow
gas play;
• Economic development of the Upper and Lower Shaunavon
formation in southwest Saskatchewan; and
• Continued improvement throughout all aspects of the
Company’s operations.
As a result of the Company’s efficient use of capital and disciplined
operations focus, Bonterra has been able to further increase its
reserve life index to approximately 14.4 and 18.7 years on a total
proved and P+P basis, respectively, from 13.7 and 17.4 years
in 2007.
To ensure sustainability, Bonterra continues to look at developing
new long-term and low-risk opportunities. The Company has
successfully drilled, completed and placed on production its first
operated Cardium well using horizontal, multi-stage frac technology.
This well is still under evaluation but if successful, the Company
intends to continue to pursue additional opportunities in 2009.
With low commodity prices and uncertainty in the industry, Bonterra
has been able to acquire significant additional lands in this play
at low costs.
2009 Capital Spending
Bonterra is planning to carry out a conservative capital development
program in 2009. With lower commodity prices and continuing global
economic uncertainty, the Company intends to remain focused on
its core business strategies.
Bonterra currently has plans to spend approximately $15 million on
its 2009 capital development program. The majority of 2009 drilling
is anticipated to occur during the second half of the year due in
part to surface land negotiations but mainly due to the Company’s
determination to wait for the Alberta provincial government to
disclose its incentive programs and potential modifications to its
high royalty rates that currently make the province uncompetitive
for certain types of wells. Bonterra has a drilling inventory in excess
of ten years with a wide range of opportunities located in all
As a result of the Company’s efficient use of capital and disciplined
operations focus, Bonterra has been able to further increase its
reserve life index to approximately 14.4 and 18.7 years on a total
proved and P+P basis, respectively, from 13.7 and 17.4 years
in 2007.
20
15
10
5
0
Reserves Life Index
(Years)
2004
2005
2006
2007
2008
* Proved plus Probable basis
6 B ON TERRA OIL & GAS LTD.
CMY B 70
slurB
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70
CM
CY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurC
X
Z
CMY
B
C
M
Y
X
Z
CMY Y 70 X 70
X
Z
CMY
B
C
M
Y
X
Z
CMY B 70
slurM
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70 MY
CMY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurY
X
Z
CMY
B
C
X
Z
CMY B 70
slurB
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70
CM
CY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurC
X
Z
CMY
B
C
M
Y
X
Z
CMY Y 70 X 70
X
Z
CMY
B
C
M
Y
X
Z
CMY B 70
slurM
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70 MY
CMY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurY
X
Z
CMY
Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG
C
3
5
6
E
N
O
T
N
A
P
C
0
1
4
E
N
O
T
N
A
P
k
c
a
l
B
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
i
r
e
k
-
-
k
c
a
B
1
8
0
:
7
2
:
5
1
6
2
-
3
0
-
9
0
e
s
i
w
t
e
e
h
S
y
g
r
e
n
E
a
r
r
e
t
n
o
B
_
5
8
4
0
2
0
9
2
Bonterra is committed to being successful in 2009 by maintaining a
consistent and disciplined approach. The Company will;
• Maintain a long-term focus;
• Continue to concentrate on finding additional operational
efficiencies by taking advantage of low cost optimization and
development opportunities in all its core areas;
• Take advantage of opportunities that are available in a low
price environment including lower land costs, lower project
costs and acquisition opportunities;
• Maintain a conservative capital structure.
Taking this approach will allow Bonterra to maintain its strong
dividend policy and ensure the long-term sustainability of its
business into the future.
Acknowledgements
The Board of Directors and management wish to thank all
shareholders for their continued support during these trying times
and its dedicated staff for their positive efforts and contributions
this past year.
George F. Fink
Chief Executive Officer and Director
Randy M. Jarock
President and Chief Operating Officer
three western provinces. This provides the Company with a high
degree of flexibility in executing its 2009 program as Bonterra can
respond and revise plans if changes to commodity prices, costs and
royalties occur.
Value-Adding Acquisitions
Bonterra’s ongoing business strategy remains focused on the
development of its long-life, high quality reserves to maximize
returns to investors. In addition, Bonterra has sought out value
adding acquisitions to further grow its asset base.
During 2008, the Company acquired properties in northeast British
Columbia through the closing of a corporate transaction in which
Bonterra acquired Silverwing Energy Inc. Production from this area is
approximately 650 BOE per day. In addition, Bonterra also received
10,000 net acres of undeveloped land in British Columbia with the
right to earn an additional 38,000 acres of non-producing lands in
Alberta providing the Company with significant potential for further
development. By year-end, Bonterra had successfully integrated the
properties into its operations, increased production through drilling
and identified additional optimization opportunities to further
increase cash flow.
Outlook
The year 2009 brings new challenges with lower commodity
prices, the worldwide economic problems and credit crisis. It is
impossible to predict when the economy and commodity prices
may experience a turnaround and the Company’s expectation is
that these unmanageable influences will continue to have an impact
on Bonterra’s results.
However from an operational and financial perspective, Bonterra
will continue to prosper. The Company has many competitive
advantages that will allow it to continue to pay a high dividend;
so that all shareholders will continue to be rewarded on a monthly
basis. These include:
•
a large drilling inventory;
• premium quality production which generally results in higher
netbacks and cashflow;
•
•
large tax pools that should assist in reducing taxes for many
years into the future; and
experienced, loyal and capable employees dedicated to
maximizing value for shareholders.
In addition, Bonterra is continually seeking new ways to strengthen
its financial position including cost-reduction initiatives, project
reviews throughout the year and exploring and implementing
operational efficiencies across the company.
BO NTER RA OI L & G AS LTD. 7
CMY B 70
slurB
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70
CM
CY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurC
X
Z
CMY
B
C
M
Y
X
Z
CMY Y 70 X 70
X
Z
CMY
B
C
M
Y
X
Z
CMY B 70
slurM
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70 MY
CMY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurY
X
Z
CMY
B
C
X
Z
CMY B 70
slurB
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70
CM
CY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurC
X
Z
CMY
B
C
M
Y
X
Z
CMY Y 70 X 70
X
Z
CMY
B
C
M
Y
X
Z
CMY B 70
slurM
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70 MY
CMY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurY
X
Z
CMY
Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG
C
0
1
4
E
N
O
T
N
A
P
C
3
5
6
E
N
O
T
N
A
P
k
c
a
l
B
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
i
r
e
k
-
-
t
n
o
r
F
1
8
0
:
7
2
:
5
1
6
2
-
3
0
-
9
0
e
s
i
w
t
e
e
h
S
y
g
r
e
n
E
a
r
r
e
t
n
o
B
_
5
8
4
0
2
0
9
2
Operations
Operations Overview
In 2008, Bonterra’s team executed a capital development program which continued to
build upon its strong track record of delivering sustainable growth. Operational focus and
discipline have again led to reserves growth on a per share basis.
The Company’s high-quality asset base consists of concentrated, stable and under-developed
properties with large amounts of remaining oil in place, a long reserve life and low-risk,
predictable returns. In addition to this strong asset base, which contains over 10 years of
identified drilling opportunities; our highly skilled and experienced team is dedicated to
maximizing returns from existing properties and adding value and sustainability through
the development of new long-term growth opportunities.
Production
Bonterra’s production volumes averaged 4,346 BOE per day in 2008. The majority of the
2008 capital development program was executed in the fourth quarter of the year and as
such production came on late in the year and did not contribute significantly to the year’s
average production rate. The corporate acquisition of Silverwing Energy Inc. (Silverwing)
was completed late in the year and also had little impact on the annual average. However,
the Company’s exit rate for the year was a strong 4,950 BOE per day and Bonterra expects
production levels to increase on a total and per share basis in 2009 based on current
development plans.
Capital Expenditures
Our team’s ability to optimize recovery from our high-quality asset base is paramount
to the Company’s success. In 2008, approximately $30.1 million was spent on the capital
development program which recorded a drilling success rate of 100 percent. The 2008
program consisted of drilling 44 gross (30.9 net) oil and natural gas wells. At year-end,
all but four oil wells were on production. These wells have subsequently been placed on
production at a capital cost of less than $1 million being spent in 2009.
Proved Plus Probable Reserves
(MBOE)
40000
30000
20000
10000
0
2004
2005
2006
2007
2008
Average Daily Production
(BOE per day)
5000
4000
3000
2000
1000
0
2004
2005
2006
2007
2008
NORTHEAST
BC
Alberta
Fort
St. John
Saskatchewan
Manitoba
Quebec
British
Columbia
PEMBINA
Calgary
SHAUNAVON
Regina
Ontario
8 B ON TERRA OIL & GAS LTD.
CMY B 70
slurB
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70
CM
CY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurC
X
Z
CMY
B
C
M
Y
X
Z
CMY Y 70 X 70
X
Z
CMY
B
C
M
Y
X
Z
CMY B 70
slurM
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70 MY
CMY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurY
X
Z
CMY
B
C
X
Z
CMY B 70
slurB
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70
CM
CY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurC
X
Z
CMY
B
C
M
Y
X
Z
CMY Y 70 X 70
X
Z
CMY
B
C
M
Y
X
Z
CMY B 70
slurM
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70 MY
CMY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurY
X
Z
CMY
Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG
C
0
1
4
E
N
O
T
N
A
P
C
3
5
6
E
N
O
T
N
A
P
k
c
a
l
B
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
i
r
e
k
-
-
t
n
o
r
F
1
8
0
:
7
2
:
5
1
6
2
-
3
0
-
9
0
e
s
i
w
t
e
e
h
S
y
g
r
e
n
E
a
r
r
e
t
n
o
B
_
5
8
4
0
2
0
9
2
A key component of our operations strategy includes acquiring
land for long-term growth projects at low prices in core areas. In
2008, Bonterra purchased 4,800 acres (3,520 net) of undeveloped
land for approximately $376,440 or approximately $107 per acre.
Bonterra’s undeveloped land base now totals 71,232 gross acres
(29,798 net acres). These lands represent both future development
opportunities for the company as well as opportunities for farmout
transactions.
In 2008, Bonterra completed three farmout transactions totaling
1,136 net acres in the Shaunavon area of Saskatchewan resulting
in three lower Shaunavon multi-stage frac horizontal wells and one
vertical upper Shaunavon oil well drilled in 2008.
The Company also completed three farm-in transactions totaling
600 net acres during the year. These transactions resulted in one gross
(0.25 net) operated multi-stage frac horizontal well being drilled in
the Pembina field. In addition, the Company has commitments for
the drilling of one additional well in 2009.
For 2009, the capital development program will sustain our focus on
the continued development of Bonterra’s light oil properties in the
Pembina field as well as in the Shaunavon area of Saskatchewan and
our new core area in northeast British Columbia. Bonterra currently
has plans to drill approximately 30 gross (18 net) oil and gas wells
with an estimated capital development budget of $15 million. This
plan includes 18 gross (14 net) Cardium vertical oil wells, two gross
(0.65 net) Cardium horizontal oil wells and the balance of the drilling
to consist of wells in both British Columbia and Saskatchewan. The
majority of the program is expected to be executed in the latter
half of 2009 due to both land conditions and the possibility that the
Alberta government may make potential modifications to its high
royalty rates that make Alberta uncompetitive for drilling certain
types of wells.
Operational Excellence
Bonterra’s operating strategy is aimed at enhancing cash flow over the
long-term to create sustainability in the dividends paid to investors.
Bonterra’s commitment to operational, technical and administrative
excellence helps to reduce development risks and lower operating
costs, thus allowing the Company to maximize netbacks.
Bonterra operates approximately 84 percent of its total production,
thereby allowing the Company to better manage costs and efficiently
invest capital. Bonterra is able to strategically schedule development
programs, well workovers and facility upgrades to control the nature,
pace and risk level of development. As an operator, Bonterra is able
to balance production and recovery of reserves with a risk profile
suitable to a high-income generating company.
Finding, Development
and Acquisition Costs (FD&A)
Results
from Bonterra’s ongoing operations, active capital
development program and the Company’s drilling program continue
to meet or exceed expectations resulting in increases in the third
party engineering evaluation’s estimated recoverable reserves from
existing wells and as well from future development. Continued low
decline rates have also resulted in increased reserves due to technical
revisions. Both these factors contributed to an overall FD&A cost in
2008 of $7.47 per BOE on a proved plus probable basis.
Recycle Ratio
A recycle ratio is an indication of the value created for each dollar
a company invests. Bonterra has a strong track record of creating
value through its capital expenditures and this year was not an
exception. Indeed, the Company is proud to report that the proved
plus probable recycle ratio in 2008 was 6.1 times.
2008 Reserves by Commodity
Netbacks
($ per BOE)
4%
27%
69%
Light & Medium Oil
Natural Gas
Natural Gas Liquids
80
70
60
50
40
30
20
10
0
2004*
2005*
2006
2007
2008
Cash Netbacks
Royalties
Field Operating
G&A
Interest & Taxes
30
20
10
0
Finding, Development
and Acquisition Costs
($ per BOE)
2006
2007
2008
2007
3-year
Average
2008
3-year
Average
* based on proved plus probable reserves
* After realized gain (loss) on risk management contracts
Proved
Proved Plus Probable
BO NTER RA OIL & GAS LTD. 9
Alberta
Fort
St. John
Saskatchewan
Manitoba
Quebec
NORTHEAST
BC
British
Columbia
PEMBINA
Calgary
SHAUNAVON
Regina
Ontario
CMY B 70
slurB
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70
CM
CY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurC
X
Z
CMY
B
C
M
Y
X
Z
CMY Y 70 X 70
X
Z
CMY
B
C
M
Y
X
Z
CMY B 70
slurM
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70 MY
CMY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurY
X
Z
CMY
B
C
X
Z
CMY B 70
slurB
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70
CM
CY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurC
X
Z
CMY
B
C
M
Y
X
Z
CMY Y 70 X 70
X
Z
CMY
B
C
M
Y
X
Z
CMY B 70
slurM
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70 MY
CMY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurY
X
Z
CMY
Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG
C
3
5
6
E
N
O
T
N
A
P
C
0
1
4
E
N
O
T
N
A
P
k
c
a
l
B
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
i
r
e
k
-
-
k
c
a
B
1
8
0
:
7
2
:
5
1
6
2
-
3
0
-
9
0
e
s
i
w
t
e
e
h
S
y
g
r
e
n
E
a
r
r
e
t
n
o
B
_
5
8
4
0
2
0
9
2
10 BONTERRA OIL & GAS LTD.Key PropertiesPembinaPembina is Bonterra’s main property. It is the Company’s largest producing asset and represents 83.7 percent of total reserves. Production in Pembina is primarily oil and solution gas from the Cardium formation and to a lesser extent natural gas from the Edmonton Sands with the remainder coming from the Belly River, Paskapoo and the Ardley Coals. The Pembina Cardium field is the largest conventional oil field in Canada with estimated original oil in place of 7.8 billion barrels with an average recovery to date of just 17 percent. This mature field has proved to be a significant area for multi-zone oil and natural gas exploration with predictable results. Bonterra is the third largest Cardium reserve holder in the area after acquiring the properties throughout the 1990s. After a period of lower commodity prices and beginning in 2003, Bonterra pursued a targeted infill drilling program, low-cost optimization, recompletions and key acquisitions which have resulted in not only increased reserves and maximized income from the properties but a reduction of the base decline. This clearly illustrates Bonterra’s ability to provide sustainability and performance for shareholders. Bonterra has significant potential upside in the Pembina Cardium field which could potentially increase recovery of the original oil in place. New frac technology, re-fracs and frac optimization has served to enhance recovery in older wells. As well, Bonterra drilled and completed its first operated Cardium horizontal multi-stage frac well during 2008. The well was placed on production in 2009 and is currently being evaluated.In addition, the implementation of two CO2 pilot projects by other industry operators in the areas points to the vast upside of these enhanced oil recovery projects in the Pembina field. Details of the pilot projects are proprietary, however public information released thus far has been very encouraging. Environmental concerns over CO2 emissions, location of a low cost source of CO2, development of infrastructure and supportive environmental regulations would be required to improve feasibility. Bonterra intends to continue to investigate its potential as a long-term business strategy. A significant portion of Bonterra’s Pembina production in natural gas is derived primarily from the shallow Edmonton sands that consist of a large number of varied quality reservoir sands. These numerous channel sands are distributed throughout the Company’s lands and multiple sands can be completed in a single well bore. These wells are drilled to depths shallower than 750 meters and make use of existing and owned infrastructure that reduced development and operating costs. Wells from the Edmonton sands generally have lower productivity that benefit from the new royalty framework in Alberta. 2008 Pembina Production Crude Oil and Liquids (Bbls per day) Pembina oil (operated) 2,179Pembina oil (non-operated) 341Current average daily production 2,520Natural Gas (BOE per day)Solution gas 511Shallow gas 544Coalbed methane 8Current average daily production 1,063Pembina
CMY B 70
slurB
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70
CM
CY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurC
X
Z
CMY
B
C
M
Y
X
Z
CMY Y 70 X 70
X
Z
CMY
B
C
M
Y
X
Z
CMY B 70
slurM
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70 MY
CMY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurY
X
Z
CMY
B
C
X
Z
CMY B 70
slurB
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70
CM
CY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurC
X
Z
CMY
B
C
M
Y
X
Z
CMY Y 70 X 70
X
Z
CMY
B
C
M
Y
X
Z
CMY B 70
slurM
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70 MY
CMY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurY
X
Z
CMY
Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG
C
3
5
6
E
N
O
T
N
A
P
C
0
1
4
E
N
O
T
N
A
P
k
c
a
l
B
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
i
r
e
k
-
-
k
c
a
B
1
8
0
:
7
2
:
5
1
6
2
-
3
0
-
9
0
e
s
i
w
t
e
e
h
S
y
g
r
e
n
E
a
r
r
e
t
n
o
B
_
5
8
4
0
2
0
9
2
BONTERRA OIL & GAS LTD. 11Shaunavon Bonterra’s Shaunavon properties are located in the Whitemud and Chambery fields and produce medium density crude oil from the lower Shaunavon formation. A portion of the property is being produced under waterflood with the majority of the properties still on primary production. The wells in this area are generally long-life with stable, low-decline production profiles and Bonterra continues to evaluate whether additional water flooding or optimization programs should be initiated to further increase profitability from the existing properties. In 2008, the company drilled three gross (2.9 net) successful upper Shaunavon oil wells which were placed on production in 2009. Bonterra has several follow-up locations identified that will be drilled once commodity prices improve. Bonterra’s lands in the area are located on the edge of the rewarding lower Shaunavon resource play where there has been significant industry activity in 2008. A farmout of expiring lands resulted in three lower Shaunavon wells and one vertical upper Shaunavon well being drilled that performed to the Company’s expectation. With the information obtained from the evaluation of the farmout wells and other industry activity in the area, Bonterra is evaluating future development strategies for the lower Shaunavon. Bonterra has identified potential drilling opportunities that can take advantage of Saskatchewan’s favourable royalty regime for horizontal wells once commodity prices improve. Bonterra’s 2009 plans for further development in the Shaunavon area will depend largely on commodity prices as Saskatchewan does have a relatively more favourable royalty regime for certain types of wells.Northeast British Columbia The corporate acquisition of Silverwing in late 2008 created a new core area in the Prespatou area of northeast British Columbia with significant potential for further development. The properties consist almost entirely of natural gas and associated natural gas liquids with production of approximately 650 BOE per day.The acquisition of this property occurred late in the year and the Company focused on integrating the properties into its asset base. However, Bonterra was still able to increase production in the area by participating in the drilling of three gross (0.675 net) gas wells in December of 2008. Bonterra is currently conducting a thorough review of the property to maximize cashflow by reducing operating costs and optimizing well productivity and throughput. The Company is re-evaluating the geology of the entire area to access potential opportunities and identify new ones. The magnitude of 2009 development plans will depend on the outcome of the evaluations and commodity prices. ShaunavonNortheast British Columbia
CMY B 70
slurB
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70
CM
CY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurC
X
Z
CMY
B
C
M
Y
X
Z
CMY Y 70 X 70
X
Z
CMY
B
C
M
Y
X
Z
CMY B 70
slurM
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70 MY
CMY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurY
X
Z
CMY
B
C
X
Z
CMY B 70
slurB
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70
CM
CY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurC
X
Z
CMY
B
C
M
Y
X
Z
CMY Y 70 X 70
X
Z
CMY
B
C
M
Y
X
Z
CMY B 70
slurM
X
Z
CMY
B
C
M
Y
X
Z
CMY C 70 MY
CMY
X
Z
CMY
B
C
M
Y
X
Z
CMY M 70
slurY
X
Z
CMY
Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG
C
0
1
4
E
N
O
T
N
A
P
C
3
5
6
E
N
O
T
N
A
P
k
c
a
l
B
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
i
r
e
k
-
-
t
n
o
r
F
1
8
0
:
7
2
:
5
1
6
2
-
3
0
-
9
0
e
s
i
w
t
e
e
h
S
y
g
r
e
n
E
a
r
r
e
t
n
o
B
_
5
8
4
0
2
0
9
2
Statistical Review
Reserves
Bonterra engaged the services of Sproule Associates Limited to prepare a reserve evaluation with an effective date of December 31, 2008.
The reserves are located in the provinces of Alberta, British Columbia (BC) and Saskatchewan. Bonterra’s main oil producing areas are
located in the Pembina area of Alberta, northeast BC and the Shaunavon area of Saskatchewan. The gross reserve figures for the following
tables represent Bonterra’s ownership interest before royalties and before consideration of the company’s royalty interests. Tables may not
add due to rounding.
Summary of Oil and Gas Reserves as of December 31, 2008
Reserve Category:
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved Plus Probable
Light and
Medium Oil
Gross
(Mbbl)
Natural
Gas
Gross
(MMcf)
Natural Gas
Liquids
Gross
(Mbbl)
14,650
75
2,258
16,983
4,575
21,559
32,108
870
3,593
36,571
13,675
50,245
884
11
112
1,008
301
1,308
BOE
Gross
(Mboe)
20,885
232
2,969
24,086
7,155
31,241
Reconciliation of Company Gross Reserves by Principal Product Type as of December 31, 2008
Light and Medium Oil and
Natural Gas Liquids
Natural Gas
BOE
Gross
Proved
Plus
Probable
(Mbbl)
21,910
337
–
1,716
90
66
–
(128)
(1,125)
Gross
Proved
(Mmcf)
24,125
1,949
–
5,651
12
6,878
–
751
(2,795)
22,867
36,571
Gross
Proved
Plus
Probable
(Mmcf)
32,465
2,516
–
6,824
109
9,946
–
1,180
(2,795)
50,246
Gross
Proved
(Mboe)
21,493
588
–
2,238
12
1,198
–
148
(1,591)
24,086
Gross
Proved
Plus
Probable
(Mboe)
27,321
756
–
2,853
108
1,724
–
69
(1,591)
31,241
Gross
Proved
(Mbbl)
17,472
263
–
1,296
10
52
–
23
(1,125)
17,991
December 31, 2007
Extension
Improved recovery
Technical revisions
Discoveries
Acquisitions
Dispositions
Economic factors
Production
December 31, 2008
Summary of Net Present Values of Future Net Revenue as of December 31, 2008
Net Present Values of Future Net Revenue Before Income Taxes Discounted at (% per Year)
($ Millions)
Reserve Category:
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved Plus Probable
12 BON TERRA OIL & GAS LTD.
0%
1,004.2
6.5
85.1
1,095.8
460.0
1,555.8
5%
569.2
5.3
64.5
639.1
175.6
814.6
10%
399.5
4.4
49.4
453.4
94.8
548.2
15%
20%
311.2
3.8
38.1
353.1
61.0
414.0
256.7
3.3
29.5
289.5
42.9
332.4
Net Present Values of Future Net Revenue After Income Taxes Discounted at (% per Year)
($ Millions)
Reserve Category:
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved Plus Probable
0%
903.7
3.1
49.8
956.6
339.6
1,296.2
5%
541.0
3.6
44.3
588.8
129.5
718.4
10%
389.8
3.6
37.4
430.7
70.9
501.6
15%
20%
307.3
3.4
30.7
341.4
46.6
388.0
255.1
3.1
24.9
283.0
33.6
316.6
Commodity prices used in the above calculations of reserves are as follows:
Year
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
Alberta Gas
Edmonton Reference Price
Plantgate
(Cdn $ per bbl) (Cdn $ per MCF)
Par Price
Propane
(Cdn $ per bbl)
Butane
(Cdn $ per bbl)
Pentane
(Cdn $ per bbl)
65.35
72.78
79.95
86.57
94.97
96.89
98.85
100.84
102.88
104.96
107.08
6.47
7.24
7.56
8.15
9.00
9.21
9.42
9.63
9.85
10.17
10.30
40.70
43.16
47.42
51.34
56.33
57.46
58.62
59.81
61.02
62.25
63.50
51.15
54.25
59.59
64.53
70.79
72.22
73.68
75.16
76.68
78.23
79.81
66.93
74.54
81.88
88.66
97.27
99.23
101.23
103.28
105.36
107.49
109.66
Crude oil, natural gas and liquid prices escalate at two percent per year thereafter
The following cautionary statements are specifically required by NI 51-101.
1)
It should not be assumed that the estimates of future net revenue presented in the above tables represent the fair market value of
the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material.
2) Disclosure provided herein in respect of barrels of oil equivalent (BOE) may be misleading, particularly in used in isolation. A BOE
conversion ratio of 6 MCF: 1 BOE has been used in all cases of this disclosure. This BOE conversion ratio is based on an energy
equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
3) Estimates of reserves and future net revenues for individual properties may not reflect the same confidence level as estimates of
reserves and future net revenues for all properties due to the effects of aggregation.
BON TER RA OI L & GAS LTD. 13
2
9
0
2
0
4
8
5
_
B
o
n
t
e
r
r
a
E
n
e
r
g
y
S
h
e
e
t
w
i
s
e
0
9
-
0
3
-
2
6
1
5
:
2
7
:
0
8
1
F
r
o
n
t
-
-
k
e
r
i
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
B
l
a
c
k
P
A
N
T
O
N
E
6
5
3
C
P
A
N
T
O
N
E
4
1
0
C
CMY
Z
X
slurY
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CMY
CMYC 70MY
Z
X
Y
M
C
B
CMY
Z
X
slurM
CMYB 70
Z
X
Y
M
C
B
CMY
Z
X
CMYY 70X 70
Z
X
Y
M
C
B
CMY
Z
X
slurC
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CY
CM
CMYC 70
Z
X
Y
M
C
B
CMY
Z
X
slurB
CMYB 70
Z
X
C
B
CMY
Z
X
slurY
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CMY
CMYC 70MY
Z
X
Y
M
C
B
CMY
Z
X
slurM
CMYB 70
Z
X
Y
M
C
B
CMY
Z
X
CMYY 70X 70
Z
X
Y
M
C
B
CMY
Z
X
slurC
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CY
CM
CMYC 70
Z
X
Y
M
C
B
CMY
Z
X
slurB
CMYB 70
Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG
Production
The following table provides a summary of production volumes from the Company’s main producing areas:
Pembina area, AB
Shaunavon area, SK
Northeast BC (1)
Other
2,520
313
3
237
3,073
6,376
–
526
735
7,637
2008
Oils and NGLs
(Bbls per day)
Natural Gas
(MCF per day)
Oils and NGLs
2007
(Bbls per day)
2,346
310
–
457
3,113
Natural Gas
(MCF per day)
5,555
–
–
1,072
6,627
(1) The northeast BC properties were acquired in the Silverwing acquisition which closed on November 12, 2008 and thus made little impact on
2008 production volumes.
Land Holdings
Bonterra’s holding of petroleum and natural gas leases and rights are as follows:
Alberta
Saskatchewan
British Columbia
2008
2007
Gross Acres
Net Acres
Gross Acres
Net Acres
152,917
31,182
73,910
258,009
92,438
28,000
30,373
150,811
133,216
33,778
–
166,994
83,609
30,409
–
114,018
Petroleum and Natural Gas Capital Expenditures
The following table summarizes petroleum and natural gas capital expenditures incurred by Bonterra on acquisitions, land, seismic,
exploration and development drilling and production facilities for the years ended December 31:
Acquisitions
Disposals
Exploration and development costs
Net petroleum and natural gas capital expenditures
Drilling History
2008
2007
$
15,347,000 $
–
30,060,000
18,369,000
(17,664,000)
18,595,000
$
45,407,000 $
19,300,001
The following table summarizes the Company’s gross and net drilling activity and success:
2008
Crude oil
Natural gas
Dry
Total
Success rate
Development
Gross
35.0
8.0
–
43.0
100%
Net
25.5
5.9
–
30.6
Exploratory
Gross
1
–
–
1
Net
0.3
–
–
0.3
Total
Gross
36.0
8.0
–
44.0
Net
25.8
5.1
–
30.9
100%
100%
100%
100%
100%
14 BON TERRA OIL & GAS LTD.
CMY
Z
X
slurY
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CMY
CMYC 70MY
Z
X
Y
M
C
B
CMY
Z
X
slurM
CMYB 70
Z
X
Y
M
C
B
CMY
Z
X
CMYY 70X 70
Z
X
Y
M
C
B
CMY
Z
X
slurC
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CY
CM
CMYC 70
Z
X
Y
M
C
B
CMY
Z
X
slurB
CMYB 70
Z
X
C
B
CMY
Z
X
slurY
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CMY
CMYC 70MY
Z
X
Y
M
C
B
CMY
Z
X
slurM
CMYB 70
Z
X
Y
M
C
B
CMY
Z
X
CMYY 70X 70
Z
X
Y
M
C
B
CMY
Z
X
slurC
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CY
CM
CMYC 70
Z
X
Y
M
C
B
CMY
Z
X
slurB
CMYB 70
Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG
2
9
0
2
0
4
8
5
_
B
o
n
t
e
r
r
a
E
n
e
r
g
y
S
h
e
e
t
w
i
s
e
0
9
-
0
3
-
2
6
1
5
:
2
7
:
0
8
1
B
a
c
k
-
-
k
e
r
i
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
B
l
a
c
k
P
A
N
T
O
N
E
4
1
0
C
P
A
N
T
O
N
E
6
5
3
C
2007
Crude oil
Natural gas
Dry
Total
Success rate
2006
Crude oil
Natural gas
Dry
Total
Success rate
Tax Pools
Development
Gross
22.0
2.0
–
24.0
100%
Development
Gross
43.0
9.0
9.0
61.0
85%
Net
15.3
0.7
–
16.0
100%
Net
30.3
6.5
8.8
45.6
81%
Exploratory
Total
Gross
Net
Gross
–
–
–
–
–
–
–
–
–
–
22.0
2.0
–
24.0
Net
15.3
0.7
–
16.0
100%
100%
Exploratory
Total
Gross
Net
Gross
–
–
–
–
–
–
–
–
–
–
43.0
9.0
9.0
61.0
85%
Net
30.3
6.5
8.8
45.6
81%
The Company has the following tax pools, which may be used to reduce taxable income in future years, limited to the applicable
rates of utilization:
Rate of Utilization
($000)
Undepreciated capital costs
Eligible capital expenditures
Share issue costs
Canadian oil and gas property expenditures
Canadian development expenditures
Canadian exploration expenditures
SR&ED expenditures
Income tax losses carried forward (1)
%
Amount
20-100 $
7
20
10
30
100
100
100
$
23,696
1,870
4,581
25,072
50,743
10,530
80,357
271,029
467,878
(1) Income tax losses carried forward expire in the following years; 2014 - $1,069,000, 2025 - $3,179,000, 2026 - $109,244,000,
2027 - $116,787,000, 2028 - $40,750,000.
Share/Trust Unit Trading Statistics
(based on daily closing price)
High
Low
Close
Daily Average Trading Volume
$
$
$
2008
39.50 $
15.50 $
17.27 $
23,031
2007
30.80
22.19
23.99
17,867
BON TER RA OI L & GAS LTD. 15
CMY
Z
X
slurY
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CMY
CMYC 70MY
Z
X
Y
M
C
B
CMY
Z
X
slurM
CMYB 70
Z
X
Y
M
C
B
CMY
Z
X
CMYY 70X 70
Z
X
Y
M
C
B
CMY
Z
X
slurC
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CY
CM
CMYC 70
Z
X
Y
M
C
B
CMY
Z
X
slurB
CMYB 70
Z
X
C
B
CMY
Z
X
slurY
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CMY
CMYC 70MY
Z
X
Y
M
C
B
CMY
Z
X
slurM
CMYB 70
Z
X
Y
M
C
B
CMY
Z
X
CMYY 70X 70
Z
X
Y
M
C
B
CMY
Z
X
slurC
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CY
CM
CMYC 70
Z
X
Y
M
C
B
CMY
Z
X
slurB
CMYB 70
Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG
2
9
0
2
0
4
8
5
_
B
o
n
t
e
r
r
a
E
n
e
r
g
y
S
h
e
e
t
w
i
s
e
0
9
-
0
3
-
2
6
1
5
:
2
7
:
0
8
1
B
a
c
k
-
-
k
e
r
i
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
B
l
a
c
k
P
A
N
T
O
N
E
4
1
0
C
P
A
N
T
O
N
E
6
5
3
C
1 B ON TERRA OIL & GAS LTD.
Financial Report 2008
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
k
c
a
l
B
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
w
e
r
d
n
a
-
-
t
n
o
r
F
1
8
1
:
5
4
:
5
1
6
2
-
3
0
-
9
0
e
s
i
w
t
e
e
h
S
a
r
r
e
t
n
o
B
_
2
9
4
0
2
0
9
2
G
A
n
e
n
i
h
c
s
a
m
k
c
u
r
D
r
e
g
r
e
b
l
e
d
i
e
H
7
0
0
2
©
)
f
d
p
(
e
0
.
3
o
c
p
i
D
5
0
1
/
2
0
1
t
a
m
r
o
F
i
S
G
4
t
c
e
n
i
r
P
B
Y
M
C
Y
r
u
l
s
Y
M
C
B
Y
M
C
0
7
Y
Y
M
C
B
Y
M
C
M
r
u
l
s
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
0
7
C
0
7
B
Y
M
C
B
Y
M
C
Y
M
C
B
Y
M
C
C
r
u
l
s
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
Y
M
C
Y
M
Y
M
C
B
Y
M
C
0
7
Y
Y
M
C
B
Y
M
C
Y
C
M
C
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
Y
M
C
B
Y
M
C
0
7
C
Y
M
C
B
Y
M
C
Y
r
u
l
s
Y
M
C
B
Y
M
C
0
7
Y
Y
M
C
B
Y
M
C
M
r
u
l
s
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
0
7
C
0
7
B
Y
M
C
B
Y
M
C
Y
M
C
B
Y
M
C
C
r
u
l
s
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
Y
M
C
Y
M
Y
M
C
B
Y
M
C
0
7
Y
Y
M
C
B
Y
M
C
Y
C
M
C
Y
M
2
9
0
2
0
4
9
2
_
B
o
n
t
e
r
r
a
S
h
e
e
t
w
i
s
e
0
9
-
0
3
-
2
6
1
5
:
4
5
:
1
8
1
B
a
c
k
-
-
a
n
d
r
e
w
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
B
l
a
c
k
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
M
Y
C
M
C
Y
C
M
Y
B
C
M
Y
Y
7
0
C
M
Y
B
C
M
Y
M
Y
C
M
Y
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
s
l
u
r
C
C
M
Y
B
C
M
Y
C
M
Y
B
C
M
Y
B
7
0
C
7
0
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
s
l
u
r
M
C
M
Y
B
C
M
Y
Y
7
0
C
M
Y
B
C
M
Y
s
l
u
r
Y
C
M
Y
B
C
M
Y
C
7
0
C
M
Y
B
C
M
Y
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
C
M
C
Y
C
M
Y
B
C
M
Y
Y
7
0
C
M
Y
B
C
M
Y
M
Y
C
M
Y
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
s
l
u
r
C
C
M
Y
B
C
M
Y
C
M
Y
B
C
M
Y
B
7
0
C
7
0
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
s
l
u
r
M
C
M
Y
B
C
M
Y
Y
7
0
C
M
Y
B
C
M
Y
s
l
u
r
Y
C
M
Y
B
P
r
i
n
e
c
t
4
G
S
i
F
o
r
m
a
t
1
0
2
/
1
0
5
D
i
p
c
o
3
.
0
e
(
p
d
f
)
©
2
0
0
7
H
e
i
d
e
l
b
e
r
g
e
r
D
r
u
c
k
m
a
s
c
h
i
n
e
n
A
G
2 BONTERRA OIL & GAS LTD.Bonterra Oil & Gas Ltd. is a high-yield, dividend paying oil and gas company headquartered in Calgary, Alberta with a proven history of growth and long term returns for investors. It recently converted to a corporation from an income trust and intends to continue with a cash dividend policy similar to the distribution policy previously followed by the trust. The monthly dividend amount will continue to be determined by commodity prices and production volumes.Bonterra’s asset base consists of stable, producing properties located mainly in the Pembina field in central Alberta and are characterized by a long reserve life and low risk, predictable returns. Bonterra’s proven track record of success is due to its experienced management team, conservative capital structure and sustainable pace of development, resulting in above-average results and returns for investors.Management’s Discussion & Analysis .....................1Consolidated Financial Statements ........................21Notes to the Consolidated Financial Statements ..26Bonterra’s common shares trade on the Toronto Stock Exchange under the symbol BNE.
of $3,085,000.
as follows:
Contract Obligations
($000)
Office leases (1)
c) Risk management contracts
The Company currently has no outstanding risk management contracts:
As of December 31, 2007, the fair value of the outstanding commodity risk management contracts was a net liability
17. COMMITMENTS, CONTINGENCIES AND GUArANTEES
The Company has no contractual obligations that last more than a year other than its office lease agreements which are
Total
Less than
1 year
1 – 3
years
$
2,907 $
589 $
1,238 $
4 – 5
years
1,080
(1)
Includes Silverwing’s former office space which is being sublet at a rate that approximates the rates charged to the Company. The funds
received on the sublease have not been offset against the contractual liability.
18. SUBSEQUENT EvENTS - DIvIDENDS
Subsequent to December 31, 2008, the Company has declared the following dividends:
Date declared
January 6, 2009
February 9, 2009
March 5, 2009
Record date
January 15, 2009
February 18, 2009
March 16, 2009
$ per share
$0.16
$0.12
$0.12
Date payable
January 30, 2009
February 27, 2009
March 31, 2009
G
A
n
e
n
i
h
c
s
a
m
k
c
u
r
D
r
e
g
r
e
b
l
e
d
i
e
H
7
0
0
2
©
)
f
d
p
(
e
0
.
3
o
c
p
i
D
5
0
1
/
2
0
1
t
a
m
r
o
F
i
S
G
4
t
c
e
n
i
r
P
B
Y
M
C
Y
r
u
l
s
Y
M
C
B
Y
M
C
0
7
Y
Y
M
C
B
Y
M
C
M
r
u
l
s
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
0
7
C
0
7
B
Y
M
C
B
Y
M
C
Y
M
C
B
Y
M
C
C
r
u
l
s
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
Y
M
C
Y
M
Y
M
C
B
Y
M
C
0
7
Y
Y
M
C
B
Y
M
C
Y
C
M
C
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
Y
M
C
B
Y
M
C
0
7
C
Y
M
C
B
Y
M
C
Y
r
u
l
s
Y
M
C
B
Y
M
C
0
7
Y
Y
M
C
B
Y
M
C
M
r
u
l
s
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
0
7
C
0
7
B
Y
M
C
B
Y
M
C
Y
M
C
B
Y
M
C
C
r
u
l
s
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
Y
M
C
Y
M
Y
M
C
B
Y
M
C
0
7
Y
Y
M
C
B
Y
M
C
Y
C
M
C
Y
M
40 BONTE R RA OIL & GAS LTD.
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
k
c
a
l
B
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
w
e
r
d
n
a
-
-
k
c
a
B
1
8
1
:
5
4
:
5
1
6
2
-
3
0
-
9
0
e
s
i
w
t
e
e
h
S
a
r
r
e
t
n
o
B
_
2
9
4
0
2
0
9
2
BONTERRA OIL & GAS LTD. 1MANAGEMENT’S DISCUSSION AND ANALYSISThis report dated March 18, 2009 is a review of the operations, current financial position, and outlook for Bonterra Oil & Gas Ltd. (“Bonterra” or the “Company”) and should be read in conjunction with the audited financial statements for the year ended December 31, 2008, together with the notes related thereto.FOrwArD-LOOkING INFOrMATIONCertain statements contained in this Management’s Discussion and Analysis (MD&A) include statements which contain words such as “anticipate”, “could”, “should”, “expect”, “seek”, “may”, “intend”, “likely”, “will”, “believe” and similar expressions, statements relating to matters that are not historical facts, and such statements of our beliefs, intentions and expectations about development, results and events which will or may occur in the future, constitute “forward-looking information” within the meaning of applicable Canadian securities legislation and are based on certain assumptions and analysis made by us derived from our experience and perceptions. Forward-looking information in this MD&A includes, but is not limited to: expected cash provided by continuing operations; dividends; future capital expenditures, including the amount and nature thereof; oil and natural gas prices and demand; expansion and other development trends of the oil and gas industry; business strategy and outlook; expansion and growth of our business and operations; and maintenance of existing customer, supplier and partner relationships; supply channels; accounting policies; credit risks; and other such matters.All such forward-looking information is based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate in the circumstances. The risks, uncertainties, and assumptions are difficult to predict and may affect operations, and may include, without limitation: foreign exchange fluctuations; equipment and labour shortages and inflationary costs; general economic conditions; industry conditions; changes in applicable environmental, taxation and other laws and regulations as well as how such laws and regulations are interpreted and enforced; the ability of oil and natural gas companies to raise capital; the effect of weather conditions on operations and facilities; the existence of operating risks; volatility of oil and natural gas prices; oil and gas product supply and demand; risks inherent in the ability to generate sufficient cash flow from operations to meet current and future obligations; increased competition; stock market volatility; opportunities available to or pursued by us; and other factors, many of which are beyond our control. The foregoing factors are not exhaustive and are further discussed herein under the heading Business Prospects, Risks and Outlooks as well as in the Company’s Annual Information Form filed on SEDAR at www.sedar.com.Actual results, performance or achievements could differ materially from those expressed in, or implied by, this forward-looking information and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking information will transpire or occur, or if any of them do so, what benefits will be derived therefrom. Except as required by law, the Company disclaims any intention or obligation to update or revise any forward-looking information, whether as a result of new information, future events or otherwise.The forward-looking information contained herein is expressly qualified by this cautionary statement.
ANNUAL COMpArISONS
Financial ($000, except $ per unit)
Revenue – realized oil and gas
Cash flow from operations
Per Share/Unit Basic
Per Share/Unit Fully Diluted
Cash payments per share/unit (1)
Payout Ratio (1)
Net Earnings
Per Share/Unit Basic
Per Share/Unit Fully Diluted
Capital Expenditures and Acquisitions
Total Assets
Working Capital Deficiency
Long-term Debt
Shareholders’/Unitholders’ Equity
Operations
Oil and Liquids (barrels per day)
Natural Gas (MCF per day)
Total BOE per day
QUArTErLY COMpArISONS
Financial ($000, except $ per unit)
Revenue – realized oil and gas sales
Cash flow from operations
Per Share/Unit Basic
Per Share/Unit Fully Diluted
Cash payments per share/unit (1)
Payout Ratio (1)
Net Earnings
Per Share/Unit Basic
Per Share/Unit Fully Diluted
Capital Expenditures and Acquisitions
Total Assets
Working Capital Deficiency
Long-term debt
Unitholders’ Equity
Operations
Oil and Liquids (barrels per day)
Natural Gas (MCF per day)
Total BOE per day
2008
2007
2006
•
Investments are generally only with companies that have common management with the Company.
• Agreements for product sales are primarily on 30 day renewal terms; and
121,730
69,570
4.07
4.06
3.12
77%
55,426
3.25
3.23
45,407
265,301
23,878
79,910
56,777
3,073
7,637
4,346
96,431
51,433
3.04
3.04
2.64
87%
30,350
1.79
1.79
19,300
142,326
58,766
–
44,376
3,113
6,627
4,218
88,734
51,944
3.10
3.08
2.82
91%
37,250
2.23
2.21
38,348
134,942
50,187
–
53,359
3,040
6,014
4,042
4th
3rd
2nd
1st
Liquidity risk
2008
22,613
10,336
0.59
0.59
0.62
105%
10,585
0.62
0.62
30,405
265,301
23,878
79,910
56,777
3,105
8,892
4,587
34,226
22,492
1.31
1.30
0.96
73%
21,125
1.23
1.22
6,038
150,120
47,499
–
57,623
3,013
7,233
4,219
34,398
20,530
1.21
1.20
0.84
69%
12,912
0.76
0.75
2,543
153,247
57,148
–
46,612
3,024
7,272
4,236
30,493
16,212
0.96
0.96
0.70
73%
10,804
0.64
0.64
6,421
150,169
57,810
–
48,136
3,153
7,139
4,343
Of the accounts receivable balance of December 31, 2008 ($11,753,000) and December 31, 2007 ($10,575,000) over
82 (2007 – 90) percent relates to product sales with international oil and gas companies, tax receivables from the Canadian
Government or risk contract payments from the Company’s principal banker.
The Company assesses quarterly, if there has been any impairment of the financial assets of the Company. During the year
ended December 31, 2008, there was no impairment provision required on any of the financial assets of the Company
due to historical success of collecting receivables. The Company does have a credit risk exposure as the majority of
the Company’s accounts receivable are with counterparties having similar characteristics. However, payments from the
Company’s largest accounts receivable counter parties have consistently been received within 30 days and the sales
agreements with these parties are cancellable with 30 days notice if payments are not received.
At December 31, 2008 approximately $99,000 or 0.8 percent of the Company’s total accounts receivable are aged over
120 days and considered past due. The majority of these accounts are due from various joint venture partners. The
Company actively monitors past due accounts and takes the necessary actions to expedite collection, which can include
withholding production or net paying when the accounts are with joint venture partners. Should the Company determine
that the ultimate collection of a receivable is in doubt, it will provide the necessary provision in its allowance for doubtful
accounts with a corresponding charge to earnings. If the Company subsequently determines an account is uncollectable,
the account is written off with a corresponding charge to the allowance account. The Company’s allowance for doubtful
accounts balance at December 31, 2008 is $85,000. There were no accounts written off during the year.
The carrying value of accounts receivable approximates their fair value due to the relatively short periods to maturity on
this instrument. The maximum exposure to credit risk is represented by the carrying amount on the balance sheet. There
are no material financial assets that the Company considers past due.
Liquidity risk includes the risk that, as a result of Company’s operational liquidity requirements:
• The Company will not have sufficient funds to settle a transaction on the due date;
• The Company will not have sufficient funds to continue with its dividends;
• The Company will be forced to sell assets at a value which is less than what they are worth; or
• The Company may be unable to settle or recover a financial asset at all.
To help reduce these risks the Company:
• Maintains a portfolio of high-quality, long reserve life oil and gas assets.
The Company has the following maturity schedule for its financial liabilities:
Accounts payable and accrued liabilities
($000)
Due to related party
Short-term bank debt
Long-term bank debt
Office leases
Total
Recognized on Financial
Statements
Less Than
One Year
1-3 Years
4-5 Years
Payments Due By Period
Yes – Liability
Yes – Liability
Yes – Liability
Yes – Liability
No
23,888
6,000
13,325
–
589
43,802
–
–
–
79,910
1,238
81,148
–
–
–
–
1,080
1,080
2 B ON TERRA OIL & GAS LTD.
BONTERRA OIL & GAS LTD. 39
M
Y
C
M
C
Y
C
M
Y
B
C
M
Y
Y
7
0
C
M
Y
B
C
M
Y
M
Y
C
M
Y
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
s
l
u
r
C
C
M
Y
B
C
M
Y
C
M
Y
B
C
M
Y
B
7
0
C
7
0
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
s
l
u
r
M
C
M
Y
B
C
M
Y
Y
7
0
C
M
Y
B
C
M
Y
s
l
u
r
Y
C
M
Y
B
C
M
Y
C
7
0
C
M
Y
B
C
M
Y
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
C
M
C
Y
C
M
Y
B
C
M
Y
Y
7
0
C
M
Y
B
C
M
Y
M
Y
C
M
Y
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
s
l
u
r
C
C
M
Y
B
C
M
Y
C
M
Y
B
C
M
Y
B
7
0
C
7
0
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
s
l
u
r
M
C
M
Y
B
C
M
Y
Y
7
0
C
M
Y
B
C
M
Y
s
l
u
r
Y
C
M
Y
B
P
r
i
n
e
c
t
4
G
S
i
F
o
r
m
a
t
1
0
2
/
1
0
5
D
i
p
c
o
3
.
0
e
(
p
d
f
)
©
2
0
0
7
H
e
i
d
e
l
b
e
r
g
e
r
D
r
u
c
k
m
a
s
c
h
i
n
e
n
A
G
2
9
0
2
0
4
9
2
_
B
o
n
t
e
r
r
a
S
h
e
e
t
w
i
s
e
0
9
-
0
3
-
2
6
1
5
:
4
5
:
1
8
1
F
r
o
n
t
-
-
a
n
d
r
e
w
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
B
l
a
c
k
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
k
c
a
l
B
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
w
e
r
d
n
a
-
-
t
n
o
r
F
1
8
1
:
5
4
:
5
1
6
2
-
3
0
-
9
0
e
s
i
w
t
e
e
h
S
a
r
r
e
t
n
o
B
_
2
9
4
0
2
0
9
2
G
A
n
e
n
i
h
c
s
a
m
k
c
u
r
D
r
e
g
r
e
b
l
e
d
i
e
H
7
0
0
2
©
)
f
d
p
(
e
0
.
3
o
c
p
i
D
5
0
1
/
2
0
1
t
a
m
r
o
F
i
S
G
4
t
c
e
n
i
r
P
B
Y
M
C
Y
r
u
l
s
Y
M
C
B
Y
M
C
0
7
Y
Y
M
C
B
Y
M
C
M
r
u
l
s
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
0
7
C
0
7
B
Y
M
C
B
Y
M
C
Y
M
C
B
Y
M
C
C
r
u
l
s
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
Y
M
C
Y
M
Y
M
C
B
Y
M
C
0
7
Y
Y
M
C
B
Y
M
C
Y
C
M
C
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
Y
M
C
B
Y
M
C
0
7
C
Y
M
C
B
Y
M
C
Y
r
u
l
s
Y
M
C
B
Y
M
C
0
7
Y
Y
M
C
B
Y
M
C
M
r
u
l
s
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
0
7
C
0
7
B
Y
M
C
B
Y
M
C
Y
M
C
B
Y
M
C
C
r
u
l
s
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
Y
M
C
Y
M
Y
M
C
B
Y
M
C
0
7
Y
Y
M
C
B
Y
M
C
Y
C
M
C
Y
M
b) Risks and mitigations
Commodity price risk
Market risk is the risk that the fair value or future cash flow of the Company’s financial instruments will fluctuate because of
changes in market prices. Components of market risk to which the Company is exposed are discussed below.
The Company’s principal operation is the production and sale of crude oil, natural gas and natural gas liquids. Fluctuations
in prices of these commodities directly impact the Company’s performance and ability to continue with its dividends.
The Company has used various risk management contracts to set price parameters for a portion of its production.
Management, in agreement with the Board of Directors, recently decided that at least in the near term it will discontinue
the use of commodity price agreements. The Company will assume full risk in respect of commodity prices.
Sensitivity Analysis
Commodity prices have fluctuated significantly over the recent past. The following table updates the cash flow sensitivity
for movements in the commodity prices of $1 U.S. per barrel WTI for crude oil, $0.10 per MCF AECO for natural gas and
$0.01 fluctuation in exchange rates.
($000)
U.S. $1.00 per barrel
Canadian $0.10 per MCF
Change of Canadian $0.01/U.S. $ exchange rate
Interest rate risk
Cash Flow
870,000
289,000
593,000
$
$
$
Interest rate risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument
will fluctuate due to changes in market interest rates. Interest rate risk arises from interest bearing financial assets and
liabilities that the Company uses. The principal exposure of the Company is on its bank borrowings which have a variable
interest rate which gives rise to a cash flow interest rate risk.
The Company’s debt consists of an $80,000,000 revolving operating line, $20,000,000 demand operating line and
$6,000,000 due to the Company’s CEO and major shareholder. The borrowings under these facilities are at bank prime
plus or minor various percentages as well as by means of banker acceptances (BA’s). The Company manages its exposure
to interest rate risk through entering into various term lengths on its BA’s but in no circumstances do the terms exceed
Based on historic movements and volatilities in the interest rate markets and management’s current assessment of the
financial markets, the Company believes that a one percent variation in the Canadian prime interest rate is reasonably
possible over a 12-month period. No income tax effect has been calculated as the Company has sufficient tax pools such
that it will not be taxable in the near future.
A one percent increase (decrease) in the Canadian prime rate would decrease cash flow by $992,000 (increase by
six months.
Sensitivity analysis
$992,000).
Foreign exchange risk
The Company has no foreign operations and currently sells all its product sales in Canadian currency. The Company
however is exposed to currency risk in that crude oil is priced in U.S. currency then converted to Canadian currency. The
Company currently has no outstanding risk management agreements. Management, in agreement with the Board of
Directors, recently decided that at least in the near term it will discontinue the use of commodity price agreements. The
Company will assume full risk in respect of foreign exchange fluctuations.
Credit risk
sheet. To help mitigate this risk:
Credit risk is the risk that a contracting party will not complete its obligations under a financial instrument and cause the
Company to incur a financial loss. The Company is exposed to credit risk on all financial assets included on the balance
• The Company only enters into material agreements with credit worthy counterparties. These include major oil and
gas companies or major Canadian chartered banks;
Financial ($000, except $ per unit)
Revenue – realized oil and gas sales
Cash flow from operations
Per Unit Basic
Per Unit Fully Diluted
Cash payments per share/unit (1)
Payout Ratio (1)
Net Earnings
Per Unit Basic
Per Unit Fully Diluted
Capital Expenditures and Acquisitions
Total Assets
Working Capital Deficiency
Long-term debt
Unitholders’ Equity
Operations
Oil and Liquids (barrels per day)
Natural Gas (MCF per day)
Total BOE per day
4th
3rd
2nd
1st
2007
26,573
13,369
0.79
0.79
0.66
84%
7,920
0.47
0.47
7,213
142,329
58,766
–
44,218
3,098
7,176
4,295
23,794
11,886
0.70
0.70
0.66
94%
9,086
0.54
0.53
2,763
138,140
50,041
–
50,820
3,054
6,196
4,086
23,462
13,413
0.79
0.79
0.66
84%
4,440
0.26
0.26
1,699
139,432
49,595
–
51,920
3,074
6,663
4,184
22,602
12,765
0.76
0.76
0.66
87%
8,904
0.53
0.53
7,625
140,926
49,288
–
57,646
3,227
6,470
4,305
(1) Cash payments per share/unit are based on payments made in respect of production months within the quarter.
Disclosure Controls and procedures
Disclosure controls and procedures (DC&P) are defined under National Instrument 52-109 – Certification of Disclosure
Controls in Issuers’ Annual and Interim Filings (NI 52-109) as “…controls and other procedures of an issuer that are
designed to provide reasonable assurance that information required to be disclosed by the issuer in its annual filings,
interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized
and reported within the time periods specified in the securities legislation and include controls and procedures designed
to ensure that information required to be disclosed by an issuer in its annual filings, interim filings or other reports filed
or submitted under securities legislation is accumulated and communicated to the issuer’s management, including its
certifying officers as appropriate to allow timely decisions regarding required disclosure.” The Company has conducted a
review and evaluation of its DC&P, with the conclusion that as at December 31, 2008 the Company has an effective system
of DC&P as defined under NI 52-109. In reaching this conclusion, the Company recognizes that two key factors must be
and are present:
1.
the Company is very dependent upon its advisors and consultants (principally its legal counsels) to assist in
recognizing, interpreting, understanding and complying with the various securities regulations disclosure
requirements; and
2.
the Company has an active Board and management with open lines of communications.
Bonterra has a small staff with varying degrees of knowledge concerning the various regulatory disclosure requirements.
In many circumstances, the various regulatory requirements are relatively new, subject to interpretation, and complex.
The Company is not of sufficient size to justify a separate department or one or more staff member specialists in this area.
Therefore the Company must rely upon its advisors/consultants to assist it and as such they form part of the disclosure
controls and procedures.
Proper disclosure necessitates that a person not only be aware of the pertinent disclosure requirements, but must also
be sufficiently involved in the affairs of the Company and/or receives the communication of information to assess any
necessary disclosure requirements. Accordingly, it is essential that there be proper communication among those people
who manage and govern the affairs of the Company, this being the Board of Directors and senior management. The
Company believes this communication exists.
38 BONTE R RA OIL & GAS LTD.
BON TERRA OI L & G AS LTD. 3
2
9
0
2
0
4
9
2
_
B
o
n
t
e
r
r
a
S
h
e
e
t
w
i
s
e
0
9
-
0
3
-
2
6
1
5
:
4
5
:
1
8
1
B
a
c
k
-
-
a
n
d
r
e
w
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
B
l
a
c
k
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
M
Y
C
M
C
Y
C
M
Y
B
C
M
Y
Y
7
0
C
M
Y
B
C
M
Y
M
Y
C
M
Y
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
s
l
u
r
C
C
M
Y
B
C
M
Y
C
M
Y
B
C
M
Y
B
7
0
C
7
0
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
s
l
u
r
M
C
M
Y
B
C
M
Y
Y
7
0
C
M
Y
B
C
M
Y
s
l
u
r
Y
C
M
Y
B
C
M
Y
C
7
0
C
M
Y
B
C
M
Y
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
C
M
C
Y
C
M
Y
B
C
M
Y
Y
7
0
C
M
Y
B
C
M
Y
M
Y
C
M
Y
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
s
l
u
r
C
C
M
Y
B
C
M
Y
C
M
Y
B
C
M
Y
B
7
0
C
7
0
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
s
l
u
r
M
C
M
Y
B
C
M
Y
Y
7
0
C
M
Y
B
C
M
Y
s
l
u
r
Y
C
M
Y
B
P
r
i
n
e
c
t
4
G
S
i
F
o
r
m
a
t
1
0
2
/
1
0
5
D
i
p
c
o
3
.
0
e
(
p
d
f
)
©
2
0
0
7
H
e
i
d
e
l
b
e
r
g
e
r
D
r
u
c
k
m
a
s
c
h
i
n
e
n
A
G
While Bonterra believes it has adequate DC&P in place, lapses in the disclosure controls and procedures could occur
and/or mistakes could happen. Should such occur, the Company intends to take whatever steps it deems necessary to
minimize the consequences thereof.
Internal Controls Over Financial reporting
Internal controls over financial reporting (ICFR) are defined in NI 52-109 as “… a process designed by, or under the
supervision of, an issuer’s certifying officers and effected by the issuer’s board of directors, management and other
personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with the issuer’s Generally Accepted Accounting Practices (GAAP) and
includes those policies and procedures that:
1. pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and
dispositions of the assets of the issuer;
2. are designed to provide reasonable assurance that transactions are recorded as necessary to permit preparation
of financial statements in accordance with the issuer’s GAAP, and that receipts and expenditures of the issuer are
being made only in accordance with authorizations of management and directors of the issuer; and
3. are designed to provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use or disposition of the issuer’s assets that could have a material effect on the annual financial
statements or interim financial statements.”
The Company has conducted a review and evaluation of its ICFR, with the conclusion that as of December 31, 2008 the
Company’s system of ICFR as defined under NI 52-109 is adequately designed to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with
GAAP. The control framework the Company used to design and evaluate its ICFR was COSO. In its evaluation, the
Company identified certain material weaknesses in internal controls over financial reporting:
1. due to the limited number of staff at the Company, it is not feasible to achieve the complete segregation of
incompatible duties; and
2. due to the limited number of staff, the Company relies upon third parties as participants in the Company’s internal
The net debt and cash flow from operations figures are presented in Table 2.
controls over financial reporting.
The Company believes these weaknesses are mitigated by: the active involvement of senior management and the board
of directors in the affairs of the Company; open lines of communication within the Company; the present levels of activities
and transactions within the Company being readily transparent; the thorough review of the Company’s financial statements
by management, the board of directors and by the Company’s auditors (annual statements only); and the establishment of
a whistle-blower policy. However, these mitigating factors will not necessarily prevent a material misstatement occurring
as a result of the aforesaid weaknesses in the Company’s internal controls over financial reporting. A system of internal
controls over financial reporting, no matter how well conceived or operated, can provide only reasonable, not absolute,
assurance that the objectives of the internal controls over financial reporting are met. The Company has no plans for
remediating the above weaknesses.
Limitation on Scope of Design of DC&p and ICFr
The above design of DC&P and ICRF has been limited to exclude controls, policies and procedures of both Silverwing
Energy Inc. (Silverwing) and operations of SRX Post Holdings (SRX) prior to the reorganization of Bonterra Energy Income
Trust into the Company. The following tables summarize the information that has been included in the consolidated
financial statements of the Company.
The following section (a) of this note provides a summary of the Company’s underlying economic positions as represented
by the carrying values, fair values and contractual face values of the Company’s financial assets and financial liabilities.
The Company’s debt to cash flow from operations is also provided.
The following section (b) addresses in more detail the key financial risk factors that arise from the Company’s activities
including its policies for managing these risks.
The following section (c) provides details of the Company’s risk management contracts that are used for financial
risk management.
a) Financial assets, financial liabilities and debt ratio
The carrying amounts, fair value and face values of the Company’s financial assets and liabilities are shown in Table 1.
Table 1
($000)
Financial assets
Restricted term deposit
Accounts receivable
Investment in related party
Financial liabilities
Accounts payable and
accrued liabilities
Due to related party
Short-term debt
Long-term debt
Table 2
($000)
Short-term debt
Long-term debt
Due to related party
Current assets (1)
Net Debt
Accounts payable and accrued liabilities
Cash flow from operations (2)
Net debt to cash flow from operations
As at December 31, 2008
Carrying
value
Fair
value
Face
value
20
11,753
2,131
20
11,753
2,131
20
11,838
N/A
23,888
6,000
13,325
79,910
23,888
6,000
13,325
79,910
23,888
6,000
13,325
79,910
December 31,
2008
13,325
79,910
6,000
23,888
(18,971)
104,152
69,570
1.50
(1) Current assets include restricted term deposit, accounts receivable, crude oil inventory, prepaid expenses and investment in related party.
(2) Cash flow from operations includes annual net earnings less adjustment for non-cash (gain) loss on risk management contracts, stock-
based compensation, depletion, depreciation and accretion, future income taxes, changes in non-cash working capital items and asset
retirement obligations settled.
4 B ON TERRA OIL & GAS LTD.
BONTERRA OIL & GAS LTD. 37
2
9
0
2
0
4
9
2
_
B
o
n
t
e
r
r
a
P
e
r
f
e
c
t
o
r
0
9
-
0
3
-
2
6
1
5
:
4
5
:
1
8
2
F
r
o
n
t
-
-
a
n
d
r
e
w
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
B
l
a
c
k
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
S
B
I
1
15. rELATED pArTY TrANSACTIONS
The Company received a management fee from Comaplex of $330,000 (2007 - $300,000) for management services and
office administration. This fee has been included as a recovery in general and administrative expenses and represents the
fair value of the services rendered.
In order to facilitate the acquisition of Silverwing, the Company borrowed on a short-term basis $20,000,000 from Comaplex
to allow time to finalize documentation for its new bank line of credit. The funds were repaid on November 21, 2008. Total
interest paid on the loan was $21,000.
As at December 31, 2008, the Company had an account receivable from Comaplex of $56,000 (December 31, 2007 - $63,000).
The Company received a management fee from Pine Cliff Energy Ltd., a company with common directors and management
with the Company and its subsidiaries, of $238,000 (2007 - $216,000) for management services and office administration.
This fee has been included in general and administrative expenses as a recovery and represents the fair value of the
services rendered.
As at December 31, 2008 the Company had an account receivable from Pine Cliff of $1,000 (December 31, 2007 - $4,000).
($000)
Restricted cash
Future income tax benefit
Property and equipment
Working capital deficiency
Asset retirement obligations
($000)
Accounts receivable
Prepaids
Accounts payable
16. FINANCIAL AND CApITAL rISk MANAGEMENT
INTErNAL CONTrOL ChANGES
Silverwing
1,252
18,325
15,347
(14,979)
(5,929)
14,016
SRX
2,158
1,701
3,859
Nil
$
$
$
$
The Company undertakes transactions in a range of financial instruments including:
Financial risk Factors
• Receivables
• Payables
• Bank loans
• Derivatives
• Common share investments
The Company’s activities result in exposure to a number of financial risks including market risk (commodity price risk,
interest rate risk, foreign exchange risk, credit risk, and liquidity risk).
The Company’s overall risk management program seeks to mitigate these risks and reduce the volatility on the Company’s
financial performance. Financial risk management is carried out by senior management under the direction of the Directors
of the Company.
The Company enters into various risk management contracts in accordance with Board approval to manage the Company’s
exposure to commodity price fluctuations. Currently no risk management agreements are in place in respect of interest
rate risk. The Company does not speculatively trade in risk management contracts. The Company’s risk management
contracts are entered into to manage the risks relating to commodity prices from its business activities.
Capital risk Management
The Company’s objectives when managing capital are to safeguard the Company’s ability to continue as a going concern,
so that it can continue to provide returns to its shareholders and benefits for other stakeholders and to maintain an
optimal capital structure to reduce the cost of capital. In order to maintain or adjust the capital structure, the Company
may adjust the amount of dividends, the percentage of return of capital or issue new shares.
The Company monitors capital on the basis of the ratio of debt to cash flow. During the year the Company acquired
Silverwing, a public oil and gas producer for cash consideration including negative working capital of $28,795,000. In
addition, the Trust underwent a reorganization resulting in a cash outlay of $11,257,000 plus reorganization costs of
$2,121,000. The Company has also experienced a decrease in cash flow due to the rather significant drop in commodity
prices during the final four months of 2008.
The Company is required to comply with Multilateral Instrument 52-109 “Certification of Disclosure in Issuers’ Annual and
Interim Filings”, otherwise referred to as Canadian SOX (C-Sox). The 2008 certificate requires that the Company disclose
in the MD&A any changes in the Company’s internal control over financial reporting that occurred during the period that
has materially affected, or is reasonably likely to materially affect the Company’s internal control over financial reporting.
The Company confirms that no such changes were made to the internal controls over financial reporting during 2008.
prODUCTION
Crude oil and NGLs (barrels per day)
Natural gas (MCF per day)
Average BOE per day
Three months ended
December September December
31, 2007
30, 2008
31, 2008
Twelve months ended
December
31, 2008
December
31, 2007
3,105
8,892
4,587
3,013
7,233
4,219
3,098
7,176
4,295
3,073
7,637
4,346
3,113
6,627
4,218
Bonterra’s 2008 average production increased three percent on a per BOE basis. Crude oil production decreased by
approximately 1.3 percent while gas production increased by approximately 15.2 percent. The decreased crude oil
production was due to the timing of Bonterra’s 2008 development program in which production came on late in the year
and therefore contributed little to 2008 and the 2007 property swap where the Company exchanged its predominantly
Saskatchewan oil property for additional production in the Pembina area which had higher natural gas production. The
natural gas increase was due to a combination of the successful 2008 development program, the acquisition of Silverwing
on November 12, 2008 and the above mentioned property swap.
The Company’s fourth quarter production in 2008 saw increases in crude oil (92 barrels per day) and natural gas
(1,659 MCF per day) production over Q308 production due to the commencement of production from new wells drilled
as well as the completion of the Silverwing acquisition. The Silverwing acquisition, which closed on November 12, 2008
added approximately 650 BOE per day, mainly natural gas. The Company’s average production volume for December
was approximately 4,950 BOE per day.
Bonterra’s overall annual decline rate for 2008 was approximately 8.5 percent. The Company was able to more than offset
this decline with its 2008 drill program. Bonterra, along with its partners, drilled 33 gross (22.9 net) Cardium oil wells. This
includes 26 gross and 21.9 net Cardium wells drilled directly by the Company. Also the Company drilled 7 gross (5 net)
shallow gas wells in 2008 in the Pembina field and 3 gross (2.9 net) Shaunavon oil wells. The Company also participated in
one (0.1 net) Cardium natural gas well drilled by one of its partners. Bonterra recorded a 100 percent success rate with its
2008 drilling program. The majority of the wells were drilled in the fourth quarter; 14 (10.2 net) Cardium oil wells, 7 gross
(5 net) shallow Pembina gas wells and all three (2.9 net) of the Shaunavon oil wells. The closing date for the Silverwing
acquisition was November 12, 2008 and therefore contributed little to production rates for the full year.
36 BONTE RR A OIL & GAS LTD.
BON TERRA OI L & G AS LTD. 5
As at December 31, 2008, Bonterra had only one gross (0.25 net) Cardium oil well, no natural gas wells, three gross
(2.5 net) coalbed methane (CBM) wells with assigned reserves and three gross (2.9 net) Shaunavon oil wells drilled but
not on production. Subsequent to December 31, 2008 and up to the date of this report, the Company has put all of its oil
wells on production. The timing for the tie-in of the CBM wells has not yet been determined.
rEvENUE
(Cdn $)
Revenue – oil and gas sales (000’s) - cash
Average Realized Prices:
Crude oil and NGLs (per barrel)
Natural gas (per MCF)
Three months ended
December September December
31, 2007
30, 2008
31, 2008
Twelve months ended
December
31, 2008
December
31, 2007
22,613
34,226
26,573
121,730
96,431
58.91
7.00
103.36
8.20
77.60
6.70
87.54
8.21
70.31
6.75
Revenue from petroleum and natural gas sales increased 26 percent in 2008 compared to 2007 due to increased production
volumes and an increase in the average price received for crude oil, natural gas liquids and natural gas. The fourth quarter
of 2008 saw a substantial decrease in realized revenues over the third quarter of 2008 due to the significant decrease in
commodity prices.
Included in revenue is a risk management loss of $7,353,000 (2007 – gain of $621,000) due to lower prices received as a
result of commodity risk management agreements. The Company may continue to hedge future production to assist in
managing its cash flow. As at December 31, 2008, the Company had no outstanding risk management agreements. The
value of the outstanding commodity hedging contracts as of December 31, 2007 was a net liability of $3,085,000.
rOYALTIES
($ 000)
Crown royalties
Freehold royalties, gross overriding
royalties and net carried interests
Total royalty expense
Three months ended
December September December
31, 2007
30, 2008
31, 2008
Twelve months ended
December
31, 2008
December
31, 2007
2,337
3,523
2,634
13,736
9,209
558
2,895
1,134
4,657
682
3,316
3,479
17,215
3,235
12,444
Royalties paid by the Company consist primarily of Crown royalties paid to the Provinces of Alberta, Saskatchewan and
British Columbia. The majority of the Company’s wells are low productivity wells and therefore have low Crown royalty
rates. The Company’s average Crown royalty rate was approximately 10.6 percent (2007 – 10 percent) and approximately
2.7 percent (2007 – 3 percent) for other royalties before hedging adjustments.
During 2007, the Company was advised by the owner of a gross overriding royalty that a production limit was attained
that resulted in an additional gross overriding royalty in respect of certain of its Cardium oil wells. The production limit
was triggered by a calculation on a multitude of Cardium wells including many that were not owned by the Company.
In addition the exact wells that the production limit was applicable to was not readily known by the Company nor easily
determined. In discussions with the payee it was determined that the production limit was reached in late 2005. The
royalty was calculated based on this agreed date and the affected wells for the Company and other operators in the
area were identified. The approximate amount of the adjustment, net to the Company was $570,000 for periods prior to
January 1, 2007. This amount has been included in the 2007 royalty numbers.
Also in 2007 the Company was informed by the operator of its former Dodsland property that it had not been charged a
net profit royalty for the years 2004, 2005 and 2006. In reviewing the agreements it was confirmed the claim was accurate
and an amount of approximately $150,000 was paid by the Company in 2007 for the net profit royalty. This was also
expensed in 2007.
The following table summarizes information about stock options outstanding at December 31, 2008:
Options Outstanding
Options Exercisable
Range of
Exercise
Prices
$20.50
Number Weighted-Average
Number
Oustanding
At 12/31/08
1,390,500
Remaining Weighted-Average
Exercisable Weighted-Average
Contractual Life
Exercise Price
At 12/31/08
Exercise Price
3.9 years
$
20.50
–
$
–
A summary of the former unit option plan as of December 31, 2008 and 2007, and changes during the years is
presented below:
2008
weighted-
Average
2007
Weighted-
Average
Options
Exercise price
Options
Exercise Price
Outstanding at beginning of year
Options granted
Options exercised
Options cancelled
Outstanding at end of year
Options exercisable at end of year
1,177,000 $
29,000
(321,700)
(884,300)
– $
– $
27.59
39.09
24.66
29.03
–
–
721,500 $
553,000
(53,500)
(44,000)
1,177,000 $
530,000 $
The Company records compensation expense over the vesting period based on the fair value of options granted to
employees, directors and consultants. The Company granted 1,390,500 stock options with an estimated fair value of
$1,548,000 ($1.11 per option) using the Black-Scholes option pricing model with the following key assumptions:
Weighted-average risk free interest rate (%)
Expected life (years)
Weighted-average volatility (%)
Dividend yield 2008 and 2007
14. ACCUMULATED OThEr COMprEhENSIvE INCOME
based on the percentage of dividends or distributions paid during the year
26.55
28.11
18.56
27.92
27.59
26.63
2007
4.7
2.3
27.2
2008
2.2
3.5
31.3
Other
Other
January 1, Comprehensive December 31,
2008
Income (Loss)
2008
$
3,031 $
(1,611) $
1,420
January 1, Comprehensive December 31,
2007
Income (Loss)
2007
$
1,566 $
1,465 $
814
$
2,380
$
(814)
651 $
3,031
–
3,031
Unrealized gains (losses) on available for
sale financial assets
($000)
($000)
Unrealized gains on available for
sale financial assets
Unrealized gains and losses on derivatives
designated as cash flow hedges
2
9
0
2
0
4
9
2
_
B
o
n
t
e
r
r
a
P
e
r
f
e
c
t
o
r
0
9
-
0
3
-
2
6
1
5
:
4
5
:
1
9
2
B
a
c
k
-
-
a
n
d
r
e
w
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
B
l
a
c
k
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
S
B
I
1
6 B ON TERRA OIL & GAS LTD.
BONTERRA OIL & GAS LTD. 35
2
9
0
2
0
4
9
2
_
B
o
n
t
e
r
r
a
P
e
r
f
e
c
t
o
r
0
9
-
0
3
-
2
6
1
5
:
4
5
:
1
9
2
B
a
c
k
-
-
a
n
d
r
e
w
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
B
l
a
c
k
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
S
B
I
1
($000)
Issued
Trust Units
Number
Amount
Number
Amount
Balance, beginning of year
16,928,158 $
16,874,658 $
89,488
Transfer of contributed surplus to unit capital
Issued pursuant to Trust unit option plan
Issued on acquisition of Silverwing
–
321,700
7,745
Cancelled on conversion to a corporation
(17,257,603)
(99,530)
53,500
–
–
–
109
993
–
–
90,590
805
7,935
200
Balance, end of year
– $
–
16,928,158 $
90,590
The Company is authorized to issue an unlimited number of Class “A” redeemable Preferred Shares and an unlimited
number of Class “B” Preferred Shares. There are currently no outstanding Class “A” redeemable preferred shares or
Class “B” preferred shares.
The number of common shares (formerly trust units) used to calculate diluted net earnings per share (formerly per unit) for
the year ended December 31, 2008 of 17,119,517 shares (2007 – 16,942,036 Units) included the basic weighted average
number of common shares outstanding of 17,075,647 shares (2007 – 16,908,266 Units) plus 43,870 shares (2007 – 33,770
Units) related to the dilutive effect of common share options.
A summary of the changes of the Company’s contributed surplus is presented below:
Contributed surplus
($000)
Balance, beginning of year
Stock-based compensation expensed (non-cash)
Stock-based options exercised (non-cash)
Balance, end of year
The deficit balance is composed of the following items:
($000)
Deficit
Accumulated earnings
Accumulated cash dividends and distributions
Outstanding at beginning of year
Options granted
Outstanding at end of year
Options exercisable at end of year
2008
2,140 $
1,207
(805)
2,542 $
2007
1,116
1,133
(109)
2,140
2008
208,182 $
(254,897)
(46,715) $
2007
152,756
(204,299)
(51,543)
$
$
$
$
2008
weighted-
Average
Options
Exercise price
– $
1,390,500
1,390,500 $
– $
20.50
20.50
–
–
The Company provides an option plan for its directors, officers, employees and consultants. Under the plan, the
Company may grant options for up to 1,725,760 common shares (2007 – 1,692,800 Trust Units). The exercise price of each
option granted equals the market price of the common shares on the date of grant and the option’s maximum term is
A summary of the status of the Company’s stock option plan as of December 31, 2008 and changes during the year is
five years.
presented below:
2008
2007
New Alberta Crown royalty Framework (NrF)
Royalty rates in the fourth quarter averaged approximately 13.4 percent; slightly higher than preceding quarters. The
NRF rates vary by prices as well as productivity levels. With the current low prices the new royalty rates should result in
a significant reduction in the amount the Company will pay to the Province of Alberta. This combined with the Silvering
acquisition (mostly BC production with lower Crown royalty rates) should result in a lower average Crown royalty rate for
the Company in 2009.
The effect of the NRF on the Company’s oil and liquid reserves was a reduction of 77,200 barrels for proved and a
reduction of 132,800 barrels for proved plus probable reserves. For natural gas, the NRF accounted for a reduction of
56,500 MCF for proved and 128,800 MCF for proved plus probable reserves. On a BOE basis, this reduction represented
approximately 0.6 percent of the Company gross reserves on a proved plus probable basis.
prODUCTION COSTS
($ 000)
Production costs
$ per BOE
Three months ended
December September December
31, 2007
30, 2008
31, 2008
Twelve months ended
December
31, 2008
December
31, 2007
6,859
16.25
6,148
15.84
5,535
14.01
25,413
15.98
24,073
15.64
Barrels of oil equivalent (BOE) are calculated using a conversion ratio of 6 MCF to 1 barrel of oil. The conversion is based
on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead and as such may be misleading if used in isolation. Operating costs on the Company’s newly
acquired British Columbia (BC) properties as well as on the newly drilled wells are lower on a BOE basis than on its older
low productivity wells and this may result in lower operating costs per BOE in the future.
Operating costs increased slightly in the fourth quarter of 2008 compared to the prior quarter due primarily to the acquisition
of Silverwing and from new wells put on production in the fourth quarter of 2008 and large industry wide increases
for oilfield services especially for oil producing properties. Average production costs per BOE increased marginally in
Q408 compared with the previous quarter due mainly to winterization programs performed on the Company’s wells
and facilities.
As discussed above, Bonterra’s production comes primarily from low productivity wells. These wells generally result in
higher operating costs on a per unit-of-production basis as costs such as municipal taxes, surface leases, power and
personnel costs are not variable with production volumes. The Company is continually examining ways to reduce
operating costs.
With the acquisition of Silverwing and the Company’s recent drilling success and expected declines in oilfield service
costs, the Company anticipates operating costs in the $14 to $15 per BOE range for 2009. The higher operating costs
for the Company are substantially offset by lower royalty rates and results in higher cash net backs on a combined basis
despite higher than average operating costs.
GENErAL AND ADMINISTrATIvE ExpENSE
($ 000)
G&A Expense
$ per BOE
Three months ended
December September December
31, 2007
30, 2008
31, 2008
Twelve months ended
December
31, 2008
December
31, 2007
824
1.95
845
2.18
739
1.69
3,401
2.14
2,603
1.69
General and administrative (G&A) expenses increased 31 percent in 2008 compared to 2007. The Company provides
administrative services to Comaplex Minerals Corp. (Comaplex) and Pine Cliff Energy Ltd. (Pine Cliff), companies that
share common directors and management. Please refer to discussion under Related Party Transactions for details.
34 BONTE R RA OIL & GAS LTD.
BON TERRA OI L & G AS LTD. 7
The Company’s only significant general and administrative costs are employee compensation and professional services
such as legal, engineering and accounting. Employee compensation expense increased by approximately 29 percent
($856,000). The increase is due primarily to the Company’s bonus plan which resulted in additional employee compensation
of $610,000 (20.7 percent) with the remainder due to increased staffing levels (3.8 percent) and 2008 salary increases
(4.5 percent). The Company’s bonus plan consists of cash payments equal to three percent of before tax net earnings to
be paid to employees and key consultants based on performance throughout the year.
Costs associated with professional services increased by approximately $90,000. Increases in other general and
administrative areas have been offset by increased administration recovery charges to capital programs.
The quarter over quarter decrease was primarily due to a lower bonus accrual but was almost fully offset by increased
professional fees related to the internal control review and costs related to managing the integration of the Silverwing
acquisition and reorganization.
($000)
Undepreciated capital costs
Eligible capital expenditures
Share issue costs
Canadian oil and gas property expenditures
Canadian development expenditures
Canadian exploration expenditures
SR&ED expenditures
Income tax losses carried forward (1)
The Company and its subsidiaries have the following tax pools, which may be used to reduce taxable income in future
years, limited to the applicable rates of utilization:
INTErEST ExpENSE
($ 000)
Interest Expense
Three months ended
December September December
31, 2007
30, 2008
31, 2008
Twelve months ended
December
31, 2008
December
31, 2007
(1)
Income tax losses carried forward expire in the following years; 2014 - $1,069,000, 2025 - $3,179,000, 2026 - $109,244,000,
2027 - $116,787,000, 2028 - $40,750,000.
The Company has $27,670,000 of investment tax credits (ITC) that expire in the following years; 2009 - $3,469,000, 2010 -
746
545
878
2,740
3,028
$3,059,000, 2011 - $4,667,000, 2012 - $3,909,000, 2013 - $3,155,000, 2014 - $1,995,000, 2015 - $2,257,000, 2016 - $2,405,000,
Utilization %
Amount
Rate of
20-100 $
7
20
10
30
100
100
100
23,696
1,870
4,581
25,072
50,743
10,530
80,357
271,029
$
467,878
The decrease in interest expense in 2008 as compared to 2007 was due to much lower borrowing costs, offset partially
by increased loan balances resulting from the Company’s acquisition of Silverwing and its reorganization. Interest
rates during the year on the outstanding debt averaged approximately 4.5 percent (2007 - 5.9 percent). The Company
maintained an average outstanding debt balance of approximately $60,600,000 (2007 - $51,600,000). Total debt (including
negative working capital) as of December 31, 2008 represents approximately 17.9 months of 2008 annual cash flow from
operations or 30.1 months based on annualized 2008 fourth quarter cash flow from operations. The ratio of bank debt
only as of December 31, 2008 based on the annualized 2008 Q4 base was 27.1 months. Also in the fourth quarter of 2008
the Company had one time reorganization costs of approximately $1,369,000 reducing cash flow to $10,336,000 from
approximately $11,700,000. This one item has significant implications on the ratio of bank debt to cash flow and would
reduce the Q4 numbers of 30.1 to 26.6 and 27.1 to 23.9 months.
During the year the Company acquired Silverwing a public oil and gas producer for cash consideration including negative
working capital of $28,995,000. In addition, the Trust underwent a reorganization resulting in a cash outlay of $11,257,000
plus reorganization costs of $2,121,000. The Company also experienced a decrease in cash flow due to the rather significant
drop in commodity prices during the final four months of 2008.
The Company ended 2008 with a debt to cash flow ratio that is higher than usual even though it is in a range that is
normal with its peers at the present time. The main reason for the higher debt level is that early in the third quarter of
2008, when the Company announced its reorganization and Silverwing acquisition, it had share options outstanding that
were well in the money for approximately $25 million. At closing of the reorganization on November 12, 2008, the world
economy had changed substantially resulting in large reductions in share prices, including Bonterra’s and the majority of
the outstanding options not being exercised. The debt level is still very manageable for Bonterra but plans for 2009 are
to reduce the debt to equity ratio that presently exceeds 2:1.
2017 - $2,009,000, 2018 - $745,000.
The amount and timing of reversals of temporary differences will also depend on the Company’s future operating results,
acquisitions and dispositions of assets and liabilities, and distrubution policy. A significant change in any of the preceding
assumptions could materially affect the Company’s estimate of the future income tax asset.
12. ASSET rETIrEMENT OBLIGATIONS
At December 31, 2008, the estimated total undiscounted amount required to settle the asset retirement obligations was
$58,903,000 (2007 - $54,622,000). Costs for asset retirement have been calculated assuming a two percent inflation rate.
These obligations will be settled based on the useful lives of the underlying assets, which extend up to 50 years into the
future. This amount has been discounted using a credit-adjusted risk-free interest rate of five percent (2007 – five percent).
Changes to asset retirement obligations were as follows:
($000)
Asset retirement obligations, January 1
Adjustment to asset retirement obligations
Adjustment related to asset additions (net of disposals)
Liabilities settled during the year
Accretion
$
2008
14,904 $
(217)
5,929
(3,063)
785
2007
14,819
(399)
563
(820)
741
Asset retirement obligations, December 31
$
18,338 $
14,904
The Company is authorized to issue an unlimited number of common shares without nominal or par value.
13. ShArEhOLDErS’ EQUITY
Authorized
($000)
Issued
Common Shares
Balance, beginning of year
Issued on reorganization to a corporation
Balance, end of year
2008
2007
Number
Amount
Number
Amount
– $
17,257,603
17,257,603 $
–
99,530
99,530
– $
–
– $
–
–
–
2
9
0
2
0
4
9
2
_
B
o
n
t
e
r
r
a
P
e
r
f
e
c
t
o
r
0
9
-
0
3
-
2
6
1
5
:
4
5
:
1
8
2
F
r
o
n
t
-
-
a
n
d
r
e
w
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
B
l
a
c
k
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
S
B
I
1
8 B ON TERRA OIL & GAS LTD.
BONTERRA OIL & GAS LTD. 33
1
I
B
S
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
k
c
a
l
B
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
w
e
r
d
n
a
-
-
t
n
o
r
F
2
8
1
:
5
4
:
5
1
6
2
-
3
0
-
9
0
r
o
t
c
e
f
r
e
P
a
r
r
e
t
n
o
B
_
2
9
4
0
2
0
9
2
The following is a list of the material covenants:
• The Company as of December 31, 2008 is required to not exceed $100,000,000 in consolidated debt (includes
negative working capital but excludes debt to related parties).
• Dividends paid in any quarter shall not exceed 80 percent of the average previous four quarters cash flow as
The Company has recorded a future income tax asset related to assets and liabilities and related tax amounts:
defined under GAAP.
11. INCOME TAXES
($000)
Future tax liability related to investments:
Future tax liability related to property and equipment:
Future tax asset related to asset retirement obiligations:
Future tax asset related to finance costs:
Future tax asset related to corporate tax losses and SR&ED claims
Future tax asset (Liability) – Long-term
Current portion of future income tax asset related
to corporate tax losses and SR&ED claims:
Future income tax asset related to current portion of derivative liability
Future Tax Asset - Current
As a result of the reorganization the Company recorded a deferred credit of $71,303,000 relating to the difference
between the future income tax asset generated on the reorganization and the amount of the cash payment made to SRX
immediately before the reorganization. This credit is being amortized (2008 - $4,240,000) on the same basis as the related
future income tax asset (2008 - $4,909,000).
A reconciliation of the deferred credit is as follows:
Amount recorded on reorganization
Amortized in current year
Balance as of December 31, 2008
Current portion
Long-term portion
2008
(212) $
(7,097)
4,593
1,134 $
86,998
85,416 $
2,669 $
–
2,669 $
2007
(448)
(14,828)
3,759
79
3,843
(7,595)
–
913
913
$
71,303,000
(4,240,000)
$
67,063,000
$
2,305,000
64,758,000
$
67,063,000
$
$
$
$
$
$
Income tax expense varies from the amounts that would be computed by applying Canadian federal and provincial
income tax rates as follows:
($000)
Earnings before income taxes
Combined federal and provincial income tax rates
Income tax provision calculated using statutory tax rates
Increase (decrease) in taxes resulting from:
Saskatchewan resource surcharge
Stock-based compensation
Change in effective tax rate
Trust income allocated to Unitholders prior to conversion
Others
Income tax expense
2008
58,014 $
29.62%
17,184
437
357
(4,739)
(10,291)
(360)
2007
33,434
32.27%
10,789
512
366
4,076
(13,176)
517
3,084
$
2,588 $
Bank debt at December 31, 2008 was $93,235,000 (December 31, 2007 - $57,422,000). The Company’s banking
arrangements allow it to use Bankers Acceptances (BA’s) as part of its loan facility. Interest charges on BA’s are generally
one half percent lower than that charged on the general loan account. The interest rate on the credit facilities is calculated
as follows:
Level I
Level II
Level III
Level IV
Level V
Level VI
Consolidated Total Funded
Debt (1) to Consolidated
Cash flow ratio
Below
0.50:1
Over 0.5:1
to 1.0:1
Over 1.0:1
to 1.5:1
Over 1.5:1
to 2.0:1
Over 2.0:1
to 2.5:1
Over 2.5:1
Canadian Prime Rate Plus
Bankers’ Acceptances Rate Plus
50
150
75
175
85
185
100
200
125
225
150
250
(1) Consolidated total funded debt excludes related party amounts but includes working capital.
Consolidated total funded debt to consolidated cash flow ratio shall be adjusted effective as of the first day of the third
month following the end of each fiscal quarter, except for the end of a fiscal year in respect of which the adjustment shall
be made effective as of the first day of the fifth month following the end of such fiscal year, with each such adjustment to
be effective until the next such adjustment.
rEOrGANIzATION COSTS
Based on current accounting rules, costs associated with the Trust’s reorganization into Bonterra Oil and Gas Ltd. must be
expensed. The costs consist of a $1,000,000 finders fee paid to a company that facilitated the reorganization, $931,000 of
professional fees, $150,000 stock exchange fees and $40,000 of costs associated with the distribution of the reorganization
document. These costs are all one time costs and no further costs are anticipated by the Company in direct relation to the
reorganization. Of these total costs of $2,121,000, the Company expensed $1,369,000 in the fourth quarter of 2008 and
$752,000 was expensed in the third quarter of 2008.
STOCk-BASED COMpENSATION
Stock-based compensation is a statistically calculated value representing the estimated expense of issuing employee
stock options. The Company records a compensation expense over the vesting period based on the fair value of options
granted to employees, directors and consultants. Due to the reorganization, all existing employee unit options vested
and were either exercised or were cancelled. This resulted in approximately an additional $195,000 of stock-based
compensation being recorded in the fourth quarter on the automatic vesting of outstanding options. Also the Company
issued 1,390,500 stock options during 2008 resulting in a further expense of $97,000.
The 1,390,500 common share options were issued at the end of November 2008 with an exercise price of $20.50 per share
and a fair value of $1.11 per option. The fair value of the options granted has been estimated using the Black-Scholes
option pricing model, assuming a weighted risk free interest rate of 2.2 percent (2007 – 4.7 percent), expected weighted
average volatility of 31 percent (2007 – 27 percent), expected weighted average life of 3.5 years (2007 – 2.3 years) and an
annual dividend/distribution rate based on the dividends paid to the Shareholders/Unitholders during the year. The future
stock-based compensation impact of these options is approximately $225,000 per quarter over the next four quarters.
DEpLETION, DEprECIATION, ACCrETION AND DrY hOLE COSTS
The Company follows the successful efforts method of accounting for petroleum and natural gas exploration and
development costs. Under this method, the costs associated with dry holes are charged to operations. For intangible
capital costs that result in the addition of reserves, the Company depletes its oil and natural gas intangible assets using
the unit-of-production basis by field.
For tangible assets such as well equipment, a life span of ten years is estimated and the related tangible costs are
depreciated at one tenth of original cost per year. The use of a ten year life span instead of calculating depreciation over
the life of reserves was determined to be more representative of actual costs of tangible property. Given the Company’s
long production life, wells generally require replacement of tangible assets more than once during their life time. Most of
the Company’s wells have been producing since the 1960’s and are expected to continue to produce for at least another
twenty years.
32 B ONTER R A O IL & GAS LTD.
BON TERRA OI L & G AS LTD. 9
1
I
B
S
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
k
c
a
l
B
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
w
e
r
d
n
a
-
-
k
c
a
B
2
9
1
:
5
4
:
5
1
6
2
-
3
0
-
9
0
r
o
t
c
e
f
r
e
P
a
r
r
e
t
n
o
B
_
2
9
4
0
2
0
9
2
Provisions are made for asset retirement obligations through the recognition of the fair value of obligations associated
with the retirement of tangible long-life assets being recorded in the period the asset is put into use, with a corresponding
increase to the carrying amount of the related asset. The obligations recognized are statutory, contractual or legal
obligations. The liability is adjusted over time for changes in the value of the liability through accretion charges which are
included in depletion, depreciation and accretion expense. The costs capitalized to the related assets are amortized to
earnings in a manner consistent with the depletion and depreciation of the underlying asset.
At December 31, 2008, the estimated total undiscounted amount required to settle the asset retirement obligations was
$58,903,000 (2007 - $54,622,000). Of the $4,281,000 increase, the majority is due to the Silverwing acquisition.
These obligations will be settled based on the useful lives of the underlying assets, which extend up to 50 years into
the future. This amount has been discounted using a credit-adjusted risk-free interest rate of five percent. The discount
rate is reviewed annually and adjusted if considered necessary. A change in the rate would have a significant impact on
the amount recorded for asset retirement obligations. Based on the current provision, a one percent increase in the risk
adjusted rate would decrease the asset retirement obligation by $2,706,000. While a one percent decrease in the risk
adjusted rate would increase the asset retirement obligation by $3,639,000.
The above calculation requires an estimation of the amount of the Company’s petroleum reserves by field. This figure
is calculated annually by an independent engineering firm and is used to calculate depletion. This calculation is to a
large extent subjective. Reserve adjustments are affected by economic assumptions as well as estimates of petroleum
products in place and methods of recovering those reserves. To the extent reserves are increased or decreased, depletion
costs will vary.
For the fiscal year ending December 31, 2008, the Company expensed $14,749,000 (2007 - $16,675,000) for the
above-described items including $Nil (2007 - $3,078,000) for dry hole costs. During 2007 the Company wrote off all costs
related to eight wells which no reserves were attributed by the independent third party engineers.
The Company continues to have relatively low finding and development costs (see discussion under Finding
and Development Costs). Based on year end reserves, the Company’s average cost of proved reserves is $6.40
(2007 - $5.84) per BOE.
The Company currently has an estimated reserve life for its proved developed producing reserves of 12.5 (2007 – 11.3)
years calculated using the Company’s gross reserves (prior to allowance for royalties) based on the third party engineering
report dated December 31, 2008 and using fourth quarter 2008 average production rates of 4,587 BOE per day
(2007 – 4,295 BOE per day). Based on total proved reserves the Company has a 14.4 (2007 – 13.7) year reserve life and if
proved and probable are used the reserve life increases to 18.7 (2007 – 17.4) years. These figures are some of the longest
reserve life indexes (excluding oil sands) in the Canadian oil and gas industry.
INCOME TAxES
On November 12, 2008, Bonterra Energy Income Trust converted to a corporation. Due to the conversion and the
acquisition of Silverwing, the Company increased its usable tax pools to approximately $468,000,000 (see below). As
a result of the reorganization, the Company has recorded a future income tax asset and a corresponding deferred tax
credit. These amounts will be amortized into future tax expense as the associated tax pools are consumed.
The current tax provision relates to resource surcharge payable by the Company to the Province of Saskatchewan.
The surcharge is calculated as a flat percent of revenues generated from the sale of petroleum products produced in
Saskatchewan. The provincial government of Saskatchewan reduced the resource surcharge rate from 3.1 percent to
3.0 percent on July 1, 2008.
8. prOpErTY AND EQUIpMENT
($000)
Undeveloped land
Petroleum and natural gas properties
and related equipment
Furniture, equipment and other
9. DUE TO rELATED pArTY
2008
2007
Accumulated
Depletion and
Accumulated
Depletion and
Cost
Depreciation
Cost
Depreciation
$
2,295 $
– $
316 $
–
229,136
1,254
74,844
848
185,947
1,025
$
232,685 $
75,692 $
187,288 $
61,105
700
61,805
As of December 31, 2008, the Company’s CEO and major shareholder has loaned the Company $6,000,000. The loan
is unsecured, bears interest at Canadian chartered bank prime less one half of a percent and has no set repayment
terms. The loan can only be repaid should the Company have sufficient available borrowing limits under the Company’s
credit facility.
Interest paid on this loan during 2008 was $7,000.
Please refer to note 15 for additional related party transactions.
10. BANk DEBT
Due to the corporate reorganization and acquisition of Silverwing, the Company amended its bank facility to consist of an
$80,000,000 syndicated revolving credit facility and a $20,000,000 non-syndicated demand credit facility (December 31,
2007 - $69,900,000) (non-syndicated demand facility). Amounts drawn under these facilities at December 31, 2008 were
$93,235,000 (December 31, 2007 - $57,422,000). The interest rates on the outstanding debt as of December 31, 2008 were
4.35 percent and 3.49 percent on the Company’s Canadian prime rate loan (short-term debt) and Bankers’ Acceptances
(long-term debt), respectively. The terms of the syndicated revolving credit facility provide that the loan is revolving to
May 30, 2010 and is subject to annual review. The revolving credit facility has no fixed payment requirements. The terms
of the non-syndicated demand credit facility provide that the loan is due on demand and is subject to annual review and
has no fixed repayment terms.
The amount available for borrowing under the credit facilities is reduced by outstanding letters of credit. Letters of credit
totaling $525,000 were issued at December 31, 2008 (December 31, 2007 - $355,000). Of the letters of credit, $20,000
is secured by a restricted term deposit. Security for the credit facilities consists of various fixed and floating demand
debentures totaling $200,000,000 over all of the Company’s assets, and a general security agreement with first ranking
over all personal and real property.
The interest rate on the credit facilities is calculated as follows:
Consolidated Total Funded
Debt (1) to Consolidated
Cash flow ratio
Level I
Level II
Level III
Level IV
Level V
Level VI
Below
Over 0.5:1
Over 1.0:1
Over 1.5:1
Over 2.0:1
0.50:1
to 1.0:1
to 1.5:1
to 2.0:1
to 2.5:1
Over 2.5:1
Canadian Prime Rate Plus (2)
Bankers’ Acceptances Rate Plus (2)
50
150
75
175
85
185
100
200
125
225
150
250
(1) Consolidated total funded debt excludes related party amounts but includes working capital.
(2) Numbers in table represent basis points.
Consolidated total funded debt to consolidated cash flow ratio shall be adjusted effective as of the first day of the third
month following the end of each fiscal quarter, except for the end of a fiscal year in respect of which the adjustment shall
be made effective as of the first day of the fifth month following the end of such fiscal year, with each such adjustment to
be effective until the next such adjustment:
10 BONTERRA OIL & GAS LTD.
BONTERRA OIL & GAS LTD. 31
1
I
B
S
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
k
c
a
l
B
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
w
e
r
d
n
a
-
-
k
c
a
B
2
9
1
:
5
4
:
5
1
6
2
-
3
0
-
9
0
r
o
t
c
e
f
r
e
P
a
r
r
e
t
n
o
B
_
2
9
4
0
2
0
9
2
4. rEOrGANIzATION
As part of the reorganization of the Trust, SRX acquired all the issued and outstanding trust units of Bonterra Energy
Income Trust on a basis of one Trust Unit for one Common Share of SRX. Immediately preceding the reorganization, SRX
was in receivership. Prior to the conversion, the Trust advanced $11,257,000 to SRX for settlement of claims pursuant to
the CCAA proceedings. Upon completion of the CCAA procedures, SRX was owed $2,224,000 in outstanding tax and
legal claims that will be used by the CCAA Monitor to settle secured creditor claims. This amount has been recorded as
an outstanding account receivable by the Company.
In addition, SRX paid an advance of $1,800,000 to the CCAA Monitor for costs and payment of the unsecured creditors.
This amount has been recorded as a prepaid expense in the accounts of the Company.
Included in accounts payable is $4,024,000 to account for the amount due to the secured and unsecured creditors.
Of the tax claims, $66,000 had been received and repaid to the Monitor by December 31, 2008. In addition, $99,000 of
expense claims had been paid by the Monitor and deducted from the advance.
5. BUSINESS COMBINATION
On November 12, 2008, the Company acquired all the common shares of Silverwing for cash consideration of $13,816,000
(including acquisition costs of $334,000) plus the issuance of 7,745 common shares at a value of $25.85 per common share
plus the assumption of $14,979,000 of negative working capital. The results of Silverwing’s operations have been included
in the consolidated financial statements since that date. The acquisition was funded through the Company’s new bank
The acquisition was accounted for using the purchase method and the purchase price was allocated to the fair value of
the assets acquired and the liabilities assumed as follows:
facility (see Note 10).
Cost of acquisition (000’s)
Cash paid
Value of common stock
Acquisition costs
Allocation of purchase price:
Restricted cash
Future income tax benefit
Property and equipment
Working capital deficiency
Asset retirement obligations
$
13,482
200
334
$
14,016
$
$
1,252
18,325
15,347
(14,979)
(5,929)
14,016
6. INvESTMENT IN rELATED pArTY
The investment consists of 689,682 (December 31, 2007 – 689,682) common shares in Comaplex Minerals Corp (Comaplex),
a company with common directors and management with the Company and its subsidiaries. The investment is recorded
at fair market value. The common shares trade on the Toronto Stock Exchange under the symbol CMF. The investment
represents less than a one and a half percent ownership in the outstanding shares of Comaplex.
7. rESTrICTED CASh
An escrow account was held by Silverwing prior to its acquisition by the Company. The escrow account was created to
support eligible expenditures related to a farm-in agreement. The Company may access the funds upon completion and
tie-in or abandonment and reclamation of 20 wells. The funds are administered by the farmors’ legal counsel. The funds
in the escrow account are invested in interest bearing term deposits.
The Company has the following tax pools, which may be used to reduce taxable income in future years, limited to the
applicable rates of utilization:
($000)
Undepreciated capital costs
Eligible capital expenditures
Share issue costs
Canadian oil and gas property expenditures
Canadian development expenditures
Canadian exploration expenditures
SR&ED expenditures
Income tax losses carried forward (1)
Rate of Utilization
%
20-100
7
20
10
30
100
100
100
$
Amount
23,696
1,870
4,581
25,072
50,743
10,530
80,357
271,029
$
467,878
(1)
Income tax losses carried forward expire in the following years; 2014 - $1,069,000, 2025 - $3,179,000, 2026 - $109,244,000,
2027 - $116,787,000, 2028 - $40,750,000.
Prior to becoming a corporation, the Trust paid nine distributions for the 2008 tax year. The Canadian tax breakdown of
those distributions is as follows:
Taxable Income (Other Income)
Return of Capital
Percentage
85.16
14.84
100.00
With respect to cash distributions paid during the year to U.S. individual unitholders, 17.71 percent should be reported
as a return of capital (to the extent of the Unitholder’s U.S. tax basis in their respective units) and 82.29 percent should be
reported as qualified dividends.
NET EArNINGS
($ 000)
Net Earnings
Three months ended
December September December
31, 2007
30, 2008
31, 2008
Twelve months ended
December
31, 2008
December
31, 2007
10,585
21,125
8,372
55,426
30,350
Bonterra’s net earnings for the year ended December 31, 2008 represents an 82 percent increase over the Company’s
2007 net earnings. The Company recorded net earnings per share on a fully diluted basis in 2008 of $3.23 verses $1.79 in
the 2007 year. This represents a return on Shareholders’ equity of approximately 97.6 percent (2007 – 68.6 percent) based
on year end Shareholders’ equity.
Strong crude oil and natural gas prices for most of 2008 along with a three percent increase in production volumes
were driving factors behind the increased profit. However, during the fourth quarter and continuing into the first quarter
and likely beyond, commodity prices have plunged to under $40 U.S. ($50 Cdn). This along with natural gas prices in
the $4 to $5 dollar range will significantly reduce the Company’s future net earnings. The Company’s low capital costs
combined with the Company’s low production decline rates should allow for continued positive earnings even in the
above mentioned price environment.
COMprEhENSIvE INCOME
On January 1, 2007, Bonterra became obliged to adopt the new accounting standards regarding the accounting for
financial instruments. On adoption, the Company increased its investment in related party by $1,836,000 for the fair value
of this investment. On January 1, 2007, Bonterra further recognized a current asset of $1,189,000 for the fair value of its
commodity derivative contracts. These adjustments resulted in a further increase in the future income tax liability and
accumulated other comprehensive income of $645,000 and $2,380,000, respectively.
30 BONTE RR A OIL & GAS LTD.
BON TERRA OI L & G AS LTD. 11
1
I
B
S
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
k
c
a
l
B
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
w
e
r
d
n
a
-
-
t
n
o
r
F
2
8
1
:
5
4
:
5
1
6
2
-
3
0
-
9
0
r
o
t
c
e
f
r
e
P
a
r
r
e
t
n
o
B
_
2
9
4
0
2
0
9
2
Other comprehensive income for 2008 consists of an unrealized loss on investment in a related party of $1,611,000 (2007
gain of $1,465,000) including a fourth quarter loss of $1,123,000 relating to a reduction in the related company’s fair value.
Effective October 1, 2007, the Company discontinued the use of hedge accounting due to the difficulty in determining
the effective portion of the commodity risk management contracts.
CASh FLOw FrOM OpErATIONS
($ 000)
Three months ended
December September December
31, 2007
30, 2008
31, 2008
Twelve months ended
December
31, 2008
December
31, 2007
3. NEw ACCOUNTING pOLICIES
Cash flow from operations
10,336
22,492
13,369
69,570
51,433
Capital Disclosures
Basic and Diluted per Share (formerly per Unit) Calculations
Basic earnings per share are computed by dividing earnings by the weighted average number of shares outstanding
during the year. Diluted per share amounts reflect the potential dilution that could occur if options to purchase shares
were exercised. The treasury stock method is used to determine the dilutive effect of common share options, whereby
proceeds from the exercise of common share options or other dilutive instruments are assumed to be used to purchase
common shares at the average market price during the period.
Cash flow from operations increased 35 percent year over year, mainly due to increased commodity prices received
during the first nine months of 2008. The fourth quarter of 2008 saw significant price declines in all commodity categories.
Although the Company was able to increase production in the fourth quarter of 2008 by almost nine percent over the
previous quarter, cash flow from operations decreased approximately 54 percent. One time costs of $1,369,000 incurred
in Q4 (Q3 - $752,000) related to the reorganization also contributed to the decline.
With the continuing depressed crude oil and natural gas prices, cash flow for 2009 is expected to be significantly negatively
affected. The price declines are expected to be partially offset by anticipated production volumes in excess of 5,000 BOE
per day for 2009, and anticipated decreases in G&A costs (lower employee compensation) and in corporate resource
surcharge (tax on revenues). Also, Bonterra does not expect any further costs associated with the acquisition of Silverwing
or the reorganization.
CASh NETBACkS
The following table illustrates the Company’s cash netback:
$ per Barrel of Oil Equivalent (BOE)
Production volumes (BOE)
Gross production revenue
Realized gain (loss) on risk management contracts
Royalties
Field operating
Field netback
General and administrative
Interest and taxes
Cash netback
2008
2007
1,590,666
1,539,461
$
81.15 $
(4.62)
(10.82)
(15.98)
49.73
(2.14)
(2.00)
$
45.59 $
62.24
0.40
(8.08)
(15.64)
38.92
(1.69)
(2.30)
34.93
The following table illustrates the Company’s cash netback for the three months ended:
$ per Barrel of Oil Equivalent (BOE)
Production volumes (BOE)
Gross production revenue
Realized gain (loss) on risk management contracts
Royalties
Field operating
Field netback
General and administrative
Interest and taxes
Cash netback
December 31,
2008
September 30,
2008
422,008
395,962
$
51.27 $
2.31
(6.86)
(16.25)
30.47
(1.95)
(1.90)
$
26.62 $
95.80
(7.60)
(12.00)
(15.84)
60.36
(2.18)
(1.73)
56.45
Effective January 1, 2008, the Company prospectively adopted the Canadian Institute of Chartered Accountants (CICA)
Section 1535, “Capital Disclosures” which establishes standards for disclosing information about the Company’s capital
and how it is managed. It requires disclosures of the Company’s objectives, policies and processes for managing capital,
the quantitative data about what the Company regards as capital, whether the Company has complied with any capital
requirements and if it has not complied, the consequences of such non-compliance. The only effect of adopting this
standard is disclosures about the Company’s capital and how it is managed (see Note 16).
Financial Instruments Disclosures and presentation
Effective January 1, 2008, the Company prospectively adopted Section 3862, “Financial Instruments – Disclosures” and
Section 3863, “Financial Instruments – Presentation.” These new accounting standards replaced Section 3861, “Financial
Instruments – Disclosure and Presentation.” Section 3862 requires additional information regarding the significance of
financial instruments for the entity’s financial position and performance, and the nature, extent and management of
risks arising from financial instruments to which the entity is exposed. The additional disclosures required under these
standards are included in Note 16.
recent Accounting pronouncements
In February 2008, the CICA issued Section 3064, “Goodwill and Intangible Assets”, replacing Section 3062, “Goodwill and
Other Intangible Assets” and Section 3450, “Research and Development Costs”. Various changes have been made to
other sections of the CICA Handbook for consistency purposes. The new section will be applicable to financial statements
relating to fiscal years beginning on or after October 1, 2008. The Company adopted these standards for its fiscal year
beginning January 1, 2009 with no impact on its consolidated financial statements.
In January 2009, the CICA issued Section 1582, “Business Combinations”, which replaces former guidance on business
combinations. Section 1582 establishes principles and requirements of the acquisition method for business combinations
and related disclosures. This statement applies prospectively to business combinations for which the acquisition date is
on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier adoption
permitted. The Company plans to adopt this standard prospectively effective January 1, 2009 and does not expect the
adoption of this statement to have a material impact on the Company’s results of operations or financial position.
In January 2009, the CICA issued Sections 1601, “Consolidated Financial Statements”, and 1602, “Non-controlling
Interests”, which replaces existing guidance. Section 1601 establishes standards for the preparation of consolidated
financial statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in
consolidated financial statements subsequent to a business combination. These standards are effective on or after the
beginning of the first annual reporting period beginning on or after January 2011 with earlier application permitted. The
Company plans to adopt these standards effective January 1, 2009 and does not expect the adoption will have a material
impact on the results of operations or financial position.
The Accounting Standards Board has confirmed the convergence of Canadian GAAP with International Financial Reporting
Standards (IFRS) will be effective January 1, 2011. The Company has performed an initial scoping process in order to
ensure successful implementation within the required timeframe. The impact on the Company’s consolidated financial
statements is not reasonably determinable at this time. Key information will be disclosed as it becomes available during
the transition period.
12 BONTERRA OIL & GAS LTD.
BONTERRA OIL & GAS LTD. 29
2
9
0
2
0
4
9
2
_
B
o
n
t
e
r
r
a
P
e
r
f
e
c
t
o
r
0
9
-
0
3
-
2
6
1
5
:
4
5
:
1
9
3
F
r
o
n
t
-
-
a
n
d
r
e
w
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
B
l
a
c
k
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
S
B
I
1
The Company accounts for stock based compensation using the fair-value method of accounting for stock options
granted to directors, officers, employees and other service providers using the Black-Scholes option pricing model.
Stock-based compensation expense is recorded over the vesting period with a corresponding amount reflected in
contributed surplus. Stock-based compensation expense is calculated as the estimated fair value of the options at the
time of grant, amortized over their vesting period. When stock options are exercised, the associated amounts previously
recorded as contributed surplus are reclassified to common share capital. The Company has not incorporated an estimated
forfeiture rate for stock options that will not vest, rather, the Company accounts for actual forfeitures as they occur.
Financial Instruments
other financial liabilities.
Financial instruments are measured at fair value on initial recognition of the instrument, into one of the following five
categories: held-for trading, loans and receivables, held-to-maturity investments, available-for-sale financial assets or
Subsequent measurement of financial instruments is based on their initial classification. Held-for-trading financial assets
are measured at fair value and changes in fair value are recognized in net earnings. Available-for-sale financial instruments
are measured at fair value with changes in fair value recorded in other comprehensive income until the instrument is
derecognized or impaired. The remaining categories of financial instruments are recognized at amortized cost using the
effective interest rate method.
All risk management contracts are recorded in the balance sheet at fair value unless they qualify for the normal sale
and normal purchase exemption. All changes in their fair value are recorded in net earnings unless cash flow hedge
accounting is used, in which case changes in fair value are recorded in other comprehensive income until the underlying
hedged transaction is recognized in net earnings. Any hedge ineffectiveness is immediately recognized in net earnings.
The Company has elected not to use cash flow hedge accounting on its risk management contracts with financial
counterparties resulting in all changes in fair value being recorded in net earnings.
Cash and restricted cash are classified as held-for-trading and are measured at fair value which equals the carrying value
and any gains or losses are recognized in earnings in the period they occur. Accounts receivable are classified as loans
and receivables which are measured at amortized costs. Investments in related party are classified as available-for-sale
which are measured at fair value and any gains or losses are recognized in other comprehensive income in the period
they occur. Accounts payable and accrued liabilities and bank debt are classified as other financial liabilities, which are
measured at amortized cost.
risk Management Contracts
The Company is exposed to market risks resulting from fluctuations in commodity prices, foreign currency exchange
rates and interest rates in the normal course of its business. The Company may use a variety of instruments to manage
these exposures. For transactions where hedge accounting is not applied, the Company accounts for such instruments
using the fair value method by initially recording an asset or liability, and recognizing changes in the fair value of the
instruments in earnings as unrealized gains or losses on risk management contracts. Fair values of financial instruments
are determined from third party quotes or valuations provided by independent third parties. Any realized gains or losses
on risk management contracts are recognized in earnings in the period they occur.
The Company may elect to use hedge accounting when there is a high degree of correlation between the price movements
in the financial instruments and the items designated as being hedged and has documented the relationship between
the instruments and the hedged item as well as its risk management objective and strategy for undertaking hedge
transactions. During the year ended December 31, 2008, the Company did not designate any of its financial instruments
as hedges. There are no risk management contracts outstanding as at December 31, 2008.
Stock-Based Compensation
FINDING AND DEvELOpMENT COSTS (F&D COSTS)
The Company has been active in its capital development program over the past three years. Over this time period
Bonterra has incurred the following F&D Costs:
2008 F&D
2007 F&D
Costs per Costs per
BOE (1)(2)
BOE (1)(2)
2006 F&D
Costs per
BOE (1)(2)
2008
Three Year
Average
2007
Three Year
Average
Proved Reserve Additions
Proved plus Probable Reserve Additions
$
$
8.67 $
7.47 $
2.74 $
2.68 $
25.51 $
18.21 $
12.30 $
9.45 $
14.37
11.07
The above figures have been calculated in accordance with National Instrument 51-101 (NI 51-101) where the F&D Costs
equate to the total exploration and development costs incurred by the Company during the year plus the yearly change
in estimated future development costs as calculated by Sproule Associates Limited. The following precautionary notes
have been provided as required by NI 51-101.
(1) Barrels of Oil Equivalent may be misleading, particularly if used in isolation. A BOE conversion ratio of 6MCF:1bbl is
based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a
value equivalency at the wellhead.
(2) The aggregate of the exploration and development costs incurred in the most recent financial year and the change
during that year in estimated future development costs generally will not reflect total finding and development
costs related to reserve additions for that year.
Results from the Company’s Cardium oil drilling program continue to be better than anticipated resulting in an increase in
the third party engineering reports estimated recoverable reserves from existing wells but also from future development.
Continued low decline rates have also resulted in increased reserves due to technical revisions. Both these factors
contributed to an overall F&D cost in 2008 of $7.47 per BOE on a proved plus probable basis.
rELATED pArTY TrANSACTIONS
The Company holds 689,682 (2007 – 689,682) common shares in Comaplex which have a fair market value as of
December 31, 2008 of $2,131,000 (2007 - $4,014,000). Comaplex is a publically traded mineral company on the Toronto
Stock Exchange. The Company’s ownership in Comaplex represents approximately 1.3 percent of the issued and
outstanding common shares of Comaplex. The Company has common directors and management with Comaplex.
Comaplex paid a management fee to the Company of $330,000 (2007 - $300,000). Comaplex also shares office rental
costs and reimburses the Company for costs related to employee benefits and office materials. In addition, Comaplex
owns 204,633 (December 31, 2007 – 204,633) common shares in the Company. Services provided by the Company include
executive services (president and vice president, finance duties), accounting services, oil and gas administration and
office administration. All services performed are charged at estimated fair value. At December 31, 2008, Comaplex owed
the Company $56,000 (December 31, 2007 - $63,000).
In order to facilitate the acquisition of Silverwing, the Company borrowed on a short-term basis $20,000,000 from Comaplex
to allow time to finalize documentation for its new bank line of credit. The funds were repaid on November 21, 2008. Total
interest paid on the loan was $21,000.
The Company also has a management agreement with Pine Cliff. Pine Cliff has common directors and management
with the Company. Pine Cliff trades on the TSX Venture Exchange. Pine Cliff paid a management fee to the Company of
$238,000 (2007 - $216,000). Services provided by the Company include executive services (president and vice president,
finance duties), accounting services, oil and gas administration and office administration. All services performed are
charged at estimated fair value. The Company has no share ownership in Pine Cliff. As at December 31, 2008 the Company
had an account receivable from Pine Cliff of $1,000 (December 31, 2007 – $4,000).
As of December 31, 2008, the Company’s CEO and major shareholder had loaned the Company $6,000,000. The loan is
unsecured, bears interest at Canadian chartered bank prime less one half of a percent and has no set repayment terms.
The loan can only be repaid should the Company have sufficient available borrowing limits within its bank debt. Interest
paid on this loan during 2008 was $7,000.
28 BONTE R RA OIL & GAS LTD.
BON TERRA OI L & G AS LTD. 13
COMMITMENTS
Inventories
The Company has no contractual obligations that last more than a year other than its office lease agreements which are
as follows:
Contract Obligations
($000)
Office leases (1)
Total
Less than
1 year
1 – 3
years
$
2,907
$
589 $
1,238
$
4 – 5
years
1,080
Inventories consist of crude oil. Crude oil stored in the Company’s tanks are valued on a first in first out basis at the lower
of cost or net realizable value. Inventory cost for crude oil is determined based on combined average per barrel operating
costs, royalties and depletion and depreciation for the year and net realizable value is determined based on sales price
(1)
Includes Silverwing’s former office space which is being sublet at a rate that approximates the rates charged to the Company. The funds
Investments are carried at fair value. Fair value is determined by multiplying the year end trading price of the investments
received on the sublease have not been offset against the contractual liability.
by the number of common shares held as at period end.
FINANCIAL rEpOrTING UpDATE
During 2007, the Company completed the implementation of the new CICA Handbook Section 3855, Financial Instruments
– Recognition and Measurement, Section 1530, Comprehensive Income and Section 3865, Hedges that deal with the
recognition and measurement of financial instruments at fair value and comprehensive income. See Notes 2 and 14 in the
Notes to the audited Consolidated Financial Statements for further details.
Accounting Changes
During 2008, the Company adopted Section 1535 “Capital Disclosures”, Section 3862, “Financial Instruments - Disclosures”
and Section 3863, “Financial Instruments - Presentation”. All the above Sections were required to be adopted for fiscal
years beginning on or after October 1, 2007. As a result, the Company has added Note 16 providing the required
disclosures regarding the Company’s objectives, policies and processes for managing capital and the significance of
financial instruments for the entity’s financial position and performance; and the nature, extent and management of risks
arising from financial instruments to which the entity is exposed.
Future Accounting Changes
In February 2008, the CICA issued Section 3064, “Goodwill and Intangible Assets”, replacing Section 3062, “Goodwill and
Other Intangible Assets” and Section 3450, “Research and Development Costs”. Various changes have been made to
other sections of the CICA Handbook for consistency purposes. The new section will be applicable to financial statements
relating to fiscal years beginning on or after October 1, 2008. Accordingly, the Company will adopt the new standards
for its fiscal year beginning January 1, 2009. This standard establishes standards for the recognition, measurement,
presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets by profit-oriented
enterprises. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062.
The Company does not expect that the adoption of this new Section will have a material impact on its consolidated
financial statements.
In January 2009, the CICA issued Section 1582, “Business Combinations”, which replaces former guidance on business
combinations. Section 1582 establishes principles and requirements of the acquisition method for business combinations
and related disclosures. This statement applies prospectively to business combinations for which the acquisition date
is on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier adoption
permitted. The Company plans to adopt this standard prospectively effective January 1, 2009 and does not expect the
adoption of this statement to have a material impact on the Company’s results of operations or financial position.
In January 2009, the CICA issued Sections 1601, “Consolidated Financial Statements”, and 1602, “Non-controlling
Interests”, which replaces existing guidance. Section 1601 establishes standards for the preparation of consolidated
financial statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in
consolidated financial statements subsequent to a business combination. These standards are effective on or after the
beginning of the first annual reporting period beginning on or after January 2011 with earlier application permitted. The
Company plans to adopt these standards effective January 1, 2009 and does not expect the adoption will have a material
impact on the results of operations or financial position.
in the month preceding year end.
Investments
property and Equipment
Petroleum and Natural Gas Properties and Related Equipment
The Company follows the successful efforts method of accounting for petroleum and natural gas properties and related
equipment. Costs of exploratory wells are initially capitalized pending determination of proved reserves. Costs of wells
which are assigned proved reserves remain capitalized, while costs of unsuccessful wells are charged to earnings. All other
exploration costs including geological and geophysical costs are charged to earnings as incurred. Development costs,
including the cost of all wells, are capitalized.
Producing properties are assessed annually or more frequently as economic events dictate, for potential impairment.
Impairment is assessed by comparing the estimated net undiscounted future cash flows to the carrying value of the asset.
If required, the impairment recorded is the amount by which the carrying value of the asset exceeds its fair value.
Costs related to undeveloped properties are excluded from the depletion base until it is determined whether or not
proved reserves exist or if impairment of such costs has occurred. These properties are assessed at least annually to
determine whether impairment has occurred.
Depreciation and depletion of capitalized costs of oil and gas producing properties are calculated using the unit of
production method. Development and exploration drilling and equipment costs are depleted over the remaining proved
developed reserves. Depreciation of other plant and equipment is provided on the straight line method. Straight line
depreciation is based on the estimated service lives of the related assets which is estimated to be ten years.
Furniture, Fixtures and Office Equipment
These assets are recorded at cost and depreciated over a three to ten year period representing their estimated useful lives.
Income Taxes
The Company accounts for income taxes using the liability method. Under this method, the Company records a future
income tax asset or liability to reflect any difference between the accounting and tax basis of assets and liabilities,
using substantively enacted income tax rates. The effect on future tax assets and liabilities of a change in tax rates is
recognized in net earnings in the period in which the change occurs. Future income tax assets are only recognized to the
extent it is more likely than not that sufficient future taxable income will be available to allow the future income tax asset
to be realized.
Asset retirement Obligations
The Company recognizes an Asset Retirement Obligation (ARO) in the period in which it is incurred when a reasonable
estimate of the fair value can be made. On a periodic basis, management will review these estimates and changes, if any,
will be applied prospectively. The fair value of the estimated ARO is recorded as a long-term liability, with a corresponding
increase in the carrying amount of the related asset. The capitalized amount is depleted on a unit-of-production basis
over the life of the reserves. The liability amount is increased each reporting period due to the passage of time and
the amount of accretion is charged to earnings in the period. Revisions to the estimated timing of cash flows or to the
original estimated undiscounted cost would also result in an increase or decrease to the ARO. Actual costs incurred upon
settlement of the obligations are charged against the ARO to the extent of the liability recorded.
2
9
0
2
0
4
9
2
_
B
o
n
t
e
r
r
a
P
e
r
f
e
c
t
o
r
0
9
-
0
3
-
2
6
1
5
:
4
5
:
1
9
3
B
a
c
k
-
-
a
n
d
r
e
w
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
B
l
a
c
k
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
S
B
I
1
14 BONTERRA OIL & GAS LTD.
BONTERRA OIL & GAS LTD. 27
2
9
0
2
0
4
9
2
_
B
o
n
t
e
r
r
a
P
e
r
f
e
c
t
o
r
0
9
-
0
3
-
2
6
1
5
:
4
5
:
1
9
3
B
a
c
k
-
-
a
n
d
r
e
w
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
B
l
a
c
k
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
S
B
I
1
CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO ThE
For the Years Ended December 31, 2008 and 2007
1. ChANGE OF OrGANIzATION
On November 12, 2008, Bonterra Energy Income Trust (the “Trust”) converted to Bonterra Oil & Gas Ltd. (the “Company”)
through a reverse takeover by the Trust of SRX Post Holdings Inc. (SRX). In conjunction with the reorganization, the Trust
acquired all the issued and outstanding shares of Silverwing Energy Inc. (Silverwing). Concurrently, all of the Company’s
subsidiaries, including Silverwing were amalgamated into Bonterra Energy Corp.
Prior to the Arrangement on November 12, 2008, the consolidated financial statements included the accounts of the Trust
and its subsidiaries. After giving effect to the Arrangement, the consolidated financial statements have been prepared on
a continuity of interest basis, which recognizes Bonterra Oil & Gas Ltd. as the successor entity to the Trust. The continuity of
interest basis requires that the 2007 comparative consolidated financial statement figures are those previously presented
by the Trust. The continuity of interest basis requires that the 2007 comparative consolidated financial statement figures
are those previously presented by the Trust.
2. SIGNIFICANT ACCOUNTING pOLICIES
Basis of presentation
Consolidation
are eliminated upon consolidation.
Measurement Uncertainty
The consolidated financial statements have been prepared by management in accordance with Canadian generally
accepted accounting principles (GAAP) as described below.
These consolidated financial statements include the accounts of the “Company”, the Trust (wholly owned by the
Company) and its wholly owned subsidiary Bonterra Energy Corp. (Bonterra). Inter-company transactions and balances
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as at the date of
the balance sheets as well as the reported amounts of revenues, expenses, and cash flows during the periods presented.
Such estimates relate primarily to unsettled transactions and events as of the date of the financial statements. Actual
results could differ materially from estimated amounts.
Amounts recorded for depletion, depreciation and accretion costs and amounts used for ceiling test calculations
are based on estimates of crude oil and natural gas reserves and future costs required to develop those reserves.
Stock-based compensation is based upon expected volatility and option life estimates. Asset retirement obligations are
based on estimates of abandonment costs, timing of abandonment, inflation and interest rates. The provision for income
taxes is based on judgements in applying income tax law and estimates on the timing, likelihood and reversal of temporary
differences between the accounting and tax basis of assets and liabilities. These estimates are subject to measurement
uncertainty and changes in these estimates could materially impact the financial statements of future periods.
Revenues associated with sales of petroleum and natural gas are recorded when title passes to the customer.
revenue recognition
Joint Interest Operations
Significant portions of the Company’s oil and gas operations are conducted jointly with other parties and accordingly the
financial statements reflect only the Company’s proportionate interest in such activities.
International Financial reporting Standards (IFrS)
The Accounting Standards Board (AcSB) has announced that Canadian GAAP, as we currently know them, will cease
to exist for all Publicly Accountable Entities (PAE’s) as of January 1, 2011. From that point onward the Company will be
required to account for and report under IFRS.
Although the International Accounting Standards Board (IASB) intends to revise several standards between now and
2011, IFRS will be adopted in Canada utilizing a “big bang” approach, with the exception of some Canadian GAAP
changes that have occurred or will occur in periods leading up to the transition date.
The IASB has undertaken a number of projects, many being joint projects with the Financial Accounting Standards Board
in the U.S., that may significantly change existing international standards.
This degree of activity currently being undertaken by the standard setters makes the convergence from Canadian GAAP
to IFRS a moving target. Due to these likely changes, careful monitoring of developments will be required in order to
understand fully the accounting and business implications of the new requirements.
The Company in the fourth quarter of 2008 has commenced the process of conversion to IFRS by engaging its external
auditors to perform a preliminary high-level scoping study to consider the potential impact of the implementation of IFRS
on the Company. Based on the findings to date the following areas have been identified as high impact areas:
•
•
•
•
IFRS 1 – First time adoption of IFRS
IFRS 3 – Business combinations
IAS 16 – Property and equipment
IAS 36 – Impairment of assets
Medium impact areas include:
•
•
•
•
•
•
•
•
•
IFRS 6 – Exploration and evaluation of mineral resources
IFRS 2 – Share-based payments
IAS 1 – Presentation of financial statements
IAS 10 – Events after the balance sheet date
IAS 12 – Income Taxes
IAS 18 – Revenues
IAS 23 – Borrowing costs
IAS 39 – Financial instruments, recognition and measurement
IAS 37 – Provisions, contingent liabilities and contingent assets
The impact of IFRS will be significant; however the Company has always maintained an accounting policy of successful
efforts for property and equipment that will result in a major reduction in the level of conversion compared to most oil and
gas companies who used the full cost accounting policy.
Over the course of 2009, the Company will be completing a more detailed analysis of the above areas and making
decisions in respect of accounting policies that will be followed in respect of the above identified areas, documenting
those policies, and calculating the impact of those policies on existing financial statement items and presentations.
The Company has recently implemented a new financial accounting system that provides for sufficient detail to comply
with the IFRS requirements. As the Company has been using successful efforts since its inception, detail at a well level has
been maintained under its past and current financial accounting systems as well as procedures are in place to capture this
information at the operational level.
26 BONTE R RA OIL & GAS LTD.
BON TERRA OI L & G AS LTD. 15
Implications to the Company’s controls for DC&P and ICFR are being reviewed; however the Company believes that
the majority of the procedures in place will apply once IFRS is implemented. Training will be required and is ongoing.
Individuals within the Company have been and will continue to attend courses, seminars and other training activities to
ensure the Company is adequately prepared for IFRS. Use of external legal expertise will be used to ensure compliance
is maintained with all contractual agreements.
LIQUIDITY AND CApITAL rESOUrCES
During 2008, Bonterra participated in drilling 44 gross wells (30.9 net) at a total cost of $29,466,000. Included in the above
figure is approximately $1,200,000 of costs associated with the completion and tie-in of wells the Company drilled in
2007 and prior years. As discussed in the Production section, only four gross oil wells (3.2 net) were not on production by
December 31, 2008. These wells have subsequently been placed on production at a capital cost of less than $1,000,000
being spent in 2009.
The Company currently has plans to drill approximately 30 gross (18 net) oil and gas wells in 2009 at an estimated budget
figure of $15,000,000. The current plan, if Alberta suitably adjusts its royalty structure, includes 18 gross (14 net) Cardium
vertical oil wells and two gross (0.65 net) Cardium horizontal oil wells. The balance of the drilling is anticipated to consist of
wells in BC and Saskatchewan. The majority of the drilling is anticipated to occur during the third and fourth quarters due
in part to the Company’s position that it is prudent to wait for the Alberta government to disclose its incentive programs
and potential modifications to its high royalty rates so that Alberta will be competitive for certain types of wells.
Bonterra anticipates funding the 2009 capital program out of cash flow and if necessary an increase in the Company’s
line of credit. Should the need arise, the Company is prepared to raise sufficient equity to complete its planned capital
expenditures. However, the current capital budget is predicated on commodity prices recovering to above $50 U.S. for
crude oil and $6 per MCF for natural gas and an $0.82 dollar for the last six months of 2009.
Bonterra is continuing with its efforts to acquire producing and non producing properties through either property or
entity acquisitions. Funding for any acquisition would depend on items such as the type of acquisition, quality of the
assets, size of the purchase and Bonterra’s trading price at the time of the acquisition.
Due to the corporate reorganization and acquisition of Silverwing, the Company amended its bank facility to consist of
an $80,000,000 syndicated revolving credit facility and a $20,000,000 non-syndicated demand credit facility (December
31, 2007 - $69,900,000) (non-syndicated demand facility). The terms of the syndicated revolving credit facility provide that
the loan is revolving to May 30, 2010 and is subject to annual review. The revolving credit facility has no fixed payment
requirements. The terms of the non-syndicated demand credit facility provide that the loan is due on demand and is
subject to annual review and has no fixed repayment terms.
At December 31, 2008 the Company had bank debt of $93,235,000 (2007 – $57,422,000). For the interest rates charged on
the facilities please refer to the Interest Expense section of this MD&A.
The amount available for borrowing under the credit facilities is reduced by outstanding letters of credit. Letters of credit
totaling $525,000 (December 31, 2007 - $355,000) were issued at December 31, 2008. Of the letters of credit, $20,000
is secured by a restricted term deposit. Security for the credit facilities consists of various fixed and floating demand
debentures totaling $200,000,000 over all of the Company’s assets and a general security agreement with first ranking
over all personal and real property.
The facility contains few covenants due to the substantial asset value (see review of operations) of the Company’s assets
and the long business relationship established by the Company with its principal banker.
The following is a list of the material covenants:
• The Company as of December 31, 2008 is required to not exceed $100,000,000 in consolidated debt (includes
negative working capital but excludes debt to related parties).
• Dividends paid in any quarter shall not exceed 80 percent of the average previous four quarters cash flow as
defined under GAAP.
CONSOLIDATED STATEMENTS
OF CASh FLOw
For the Years Ended December 31
($000)
Operating Activities
Net earnings for the year
Items not affecting cash
(Gain) loss on risk management contracts - non-cash
Stock-based compensation
Dry hole costs
Depletion, depreciation and accretion
Future income taxes
Change in non-cash working capital
Accounts receivable
Crude oil inventory
Prepaid expenses
Accounts payable and accrued liabilities
Asset retirement obligations settled
Financing Activities
Increase in debt
Due to related party
Stock option proceeds
Unit distributions
Dividends
Investing Activities
Property and equipment expenditures
Acquisition (Note 5)
Reorganization (Note 4)
Restricted term deposit
Change in non-cash working capital
Accounts receivable
Accounts payable and accrued liabilities
Net cash inflow
Cash, beginning of year
Cash, End of Year
Cash Interest Paid
Cash Taxes Paid
2008
2007
$
55,426 $
30,350
(3,085)
1,207
–
14,749
2,151
70,448
2,642
(40)
(360)
(57)
(3,063)
(878)
69,570
20,698
6,000
7,935
(46,384)
(7,938)
(19,689)
(30,060)
(13,816)
(11,257)
20
5,272
(49,881)
–
–
–
3,085
1,133
3,078
13,597
2,572
53,815
(1,082)
51
(262)
(269)
(820)
(2,382)
51,433
12,043
–
993
(44,974)
(31,938)
(19,300)
993
(1,188)
(19,495)
–
–
–
–
–
–
–
3,028
292
$
$
$
– $
2,740 $
582 $
2
9
0
2
0
4
9
2
_
B
o
n
t
e
r
r
a
P
e
r
f
e
c
t
o
r
0
9
-
0
3
-
2
6
1
5
:
4
5
:
1
9
3
F
r
o
n
t
-
-
a
n
d
r
e
w
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
B
l
a
c
k
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
S
B
I
1
16 BONTERRA OIL & GAS LTD.
BONTERRA OIL & GAS LTD. 25
1
I
B
S
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
k
c
a
l
B
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
w
e
r
d
n
a
-
-
t
n
o
r
F
3
9
1
:
5
4
:
5
1
6
2
-
3
0
-
9
0
r
o
t
c
e
f
r
e
P
a
r
r
e
t
n
o
B
_
2
9
4
0
2
0
9
2
CONSOLIDATED STATEMENTS
OF COMprEhENSIvE INCOME
For the Years Ended December 31
($000)
Net Earnings for the period
Other comprehensive income, net of income tax
Unrealized (loss) gain on investments
(net of income taxes of $(272), (2007 - $252))
Gains and losses on derivatives designated as cash flow hedges
transferred to net earnings (net of income taxes of ($334))
Other Comprehensive Income (Loss)
Comprehensive Income
Comprehensive Income per Share – Basic (Note 13)
Comprehensive Income per Share – Diluted (Note 13)
2008
$
55,426 $
2007
30,350
(1,611)
1,465
–
(1,611)
53,815 $
3.15 $
3.14 $
(814)
651
31,001
1.83
1.83
$
$
$
The Company is authorized to issue an unlimited number of common shares without nominal or par value.
($000)
Issued
Common Shares
Balance, beginning of year
Issued on reorganization to a corporation
Balance, end of year
($000)
Issued
Trust Units
Balance, beginning of year
Transfer of contributed surplus to unit capital
Issued pursuant to Trust unit option plan
Issued on acquisition of Silverwing
Cancelled on conversion to a corporation
Balance, end of year
2008
2007
Number
Amount
Number
Amount
– $
17,257,603
–
99,530
17,257,603 $
99,530
2008
– $
–
– $
2007
–
–
–
Number
Amount
Number
Amount
16,928,158 $
–
321,700
7,745
(17,257,603)
90,590
805
7,935
200
(99,530)
16,874,658 $
–
53,500
–
–
– $
–
16,928,158 $
89,488
109
993
–
–
90,590
The Company provides an option plan for its directors, officers, employees and consultants. Under the plan, the
Company may grant options for up to 1,725,760 common shares (2007 – 1,692,800 Trust Units). The exercise price of each
option granted equals the market price of the common shares on the date of grant and the option’s maximum term is
five years.
A summary of the status of the Company’s stock option plan as of December 31, 2008 and changes during the year is
presented below:
Outstanding at beginning of year
Options granted
Outstanding at end of year
Options exercisable at end of year
2008
weighted-
Average
Options
Exercise price
– $
1,390,500
1,390,500 $
– $
–
20.50
20.50
–
The following table summarizes information about common stock options outstanding at December 31, 2008:
Options Outstanding
Options Exercisable
Range of
Exercise
Prices
$20.50
Oustanding
At 12/31/08
1,390,500
Number Weighted-Average
Remaining Weighted-Average
Exercise Price
Contractual Life
Number
Exercisable Weighted-Average
At 12/31/08
Exercise Price
3.9 years
$
20.50
–
$
–
24 BONTE RR A OIL & GAS LTD.
BON TERRA OI L & G AS LTD. 17
1
I
B
S
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
k
c
a
l
B
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
w
e
r
d
n
a
-
-
k
c
a
B
3
9
1
:
5
4
:
5
1
6
2
-
3
0
-
9
0
r
o
t
c
e
f
r
e
P
a
r
r
e
t
n
o
B
_
2
9
4
0
2
0
9
2
A summary of the former unit option plan as of December 31, 2008 and 2007, and changes during the years is
presented below:
Outstanding at beginning of year
Options granted
Options exercised
Options cancelled
Outstanding at end of year
Options exercisable at end of year
2008
weighted-
Average
Exercise price
Options
2007
Weighted-
Average
Options
Exercise Price
1,177,000 $
29,000
(321,700)
(884,300)
– $
– $
27.59
39.09
24.66
29.03
–
–
721,500 $
553,000
(53,500)
(44,000)
1,177,000 $
530,000 $
26.55
28.11
18.56
27.92
27.59
26.63
BUSINESS prOSpECTS, rISkS, AND OUTLOOkS
The resource industry operates with a great deal of risk. The most significant risks may come from oil and natural gas price
swings, the uncertainty of finding new reserves from drilling programs or acquisitions, competition within the industry
and increasing environmental controls and regulations. The prices received for crude oil are established by world market
forces and for natural gas by forces within North America. Fluctuations in pricing can have extremely positive or negative
effects on the Company’s cash flow or in the value of its producing and non-producing oil and natural gas properties.
The Company presently attempts to minimize these risks by pursuing both oil and natural gas activities and operates
its oil and natural gas interests in areas which have long life reserves, where it has the technical expertise to enhance
production, control operating costs and to increase margins of profit.
SENSITIvITY ANALYSIS
Sensitivity analysis, as estimated for 2009:
U.S. $1.00 per barrel
Canadian $0.10 per MCF
Change of Canadian $0.01/U.S. $ exchange rate
ADDITIONAL INFOrMATION
Cash Flow
870,000 $
289,000 $
593,000 $
$
$
$
Cash Flow
Per Share
0.050
0.017
0.034
Additional information relating to the Company may be found on www.sedar.com as well as on the Company’s website
at www.bonterraenergy.com.
CONSOLIDATED STATEMENTS
OF OpErATIONS AND DEFICIT
For the Years Ended December 31
($000)
revenue
Oil and gas sales
Gain (loss) on risk management contracts - cash
Gain (loss) on risk management contracts - non-cash
Royalties
Interest and other
Expenses
Production costs
General and administrative
Interest on debt
Reorganization costs (Note 4)
Stock-based compensation
Dry hole costs
Depletion, depreciation and accretion
Earnings Before Taxes
Taxes (Note 11)
Current
Future
Net Earnings for the Year
Deficit, beginning of year
Distributions declared
Dividends declared
Deficit, end of year
Net Earnings per Share – Basic (Note 13)
Net Earnings per Share – Diluted (Note 13)
2008
2007
$
129,083
$
(7,353)
3,085
(17,215)
45
107,645
25,413
3,401
2,740
2,121
1,207
–
14,749
49,631
58,014
437
2,151
2,588
55,426
(51,543)
(42,660)
(7,938)
3.25 $
3.23 $
95,810
621
(3,085)
(12,444)
44
80,946
24,073
2,603
3,028
–
1,133
3,078
13,597
47,512
33,434
512
2,572
3,084
30,350
(37,245)
(44,648)
–
1.79
1.79
(46,715) $
(51,543)
$
$
$
18 BONTERRA OIL & GAS LTD.
BONTERRA OIL & GAS LTD. 23
1
I
B
S
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
k
c
a
l
B
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
w
e
r
d
n
a
-
-
k
c
a
B
3
9
1
:
5
4
:
5
1
6
2
-
3
0
-
9
0
r
o
t
c
e
f
r
e
P
a
r
r
e
t
n
o
B
_
2
9
4
0
2
0
9
2
CONSOLIDATED STATEMENTS
OF ShArEhOLDErS’ EQUITY
MANAGEMENT’S rESpONSIBILITY
FOr FINANCIAL STATEMENTS
For the Years Ended December 31
($000)
Unitholders’ equity, beginning of year
Comprehensive income for the year
Adjustment of opening accumulated other
comprehensive income
Net capital contributions (Note 13)
Stock-based compensation
Distributions declared
Conversion of the Trust to a Corporation (Note 4)
Unitholders’ Equity
Dividends declared
$
2008
44,218 $
53,815
–
8,135
1,207
(42,660)
64,715
–
(7,938)
2007
53,359
31,001
2,380
993
1,133
(44,648)
44,218
(44,218)
–
–
Shareholders’ Equity, End of Year
$
56,777 $
The information provided in this report, including the financial statements, is the responsibility of management. In the
preparation of the statements, estimates are sometimes necessary to make a determination of future values for certain
assets or liabilities. Management believes such estimates have been based on careful judgements and have been properly
reflected in the accompanying financial statements.
Management maintains a system of internal controls to provide reasonable assurance that the Company’s assets are
safeguarded and to facilitate the preparation of relevant and timely information.
Deloitte & Touche LLP has been appointed by the Shareholders to serve as the Company’s external auditors. They have
examined the financial statements and provided their auditors’ report. The audit committee has reviewed these financial
statements with management and the auditors, and has reported to the Board of Directors. The Board of Directors has
approved the financial statements as presented in this annual report.
GEOrGE F. FINk
CEO
March 11, 2009
GArTh E. SChULTz
vice president, Finance and CFO
March 11, 2009
22 BONTE R RA OIL & GAS LTD.
BON TERRA OI L & G AS LTD. 19
1
I
B
S
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
k
c
a
l
B
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
w
e
r
d
n
a
-
-
t
n
o
r
F
3
9
1
:
5
4
:
5
1
6
2
-
3
0
-
9
0
r
o
t
c
e
f
r
e
P
a
r
r
e
t
n
o
B
_
2
9
4
0
2
0
9
2
AUDITOrS’ rEpOrT
CONSOLIDATED BALANCE ShEETS
To the Shareholders of Bonterra Oil & Gas Ltd. (formerly Bonterra Energy Income Trust):
We have audited the consolidated balance sheets of Bonterra Oil & Gas Ltd. as at December 31, 2008 and 2007 and the
consolidated statements of shareholders’ equity, operations and deficit, comprehensive income and cash flow for the
years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is
to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require
that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the
Company as at December 31, 2008 and 2007 and the results of its operations and its cash flows for the years then ended
in accordance with Canadian generally accepted accounting principles.
As at December 31
($000)
ASSETS
Current
Restricted term deposit (Note 10)
Accounts receivable (Notes 4 & 15)
Crude oil inventory
Prepaid expenses (Note 4)
Future income tax asset (Note 11)
Investment in related party (Note 6)
Restricted cash (Note 7)
Future income tax asset (Note 11)
property and Equipment (Note 8)
Chartered Accountants
Calgary, Alberta
March 11, 2009
2008
2007
$
20 $
$
265,301 $
$
– $
11,753
845
4,222
2,669
2,131
21,640
1,252
85,416
232,685
(75,692)
156,993
23,888
–
6,000
2,305
13,325
45,518
79,910
–
64,758
18,338
208,524
99,530
–
2,542
102,072
(46,715)
1,420
(45,295)
56,777
–
10,575
792
1,462
913
4,014
17,756
–
–
187,288
(61,805)
125,483
143,239
3,724
12,291
3,085
–
–
–
–
57,422
76,522
7,595
14,904
99,021
–
90,590
2,140
92,730
(51,543)
3,031
(48,512)
44,218
143,239
$
265,301 $
Petroleum and natural gas properties and related equipment
Accumulated depletion and depreciation
LIABILITIES
Current
Distribution payable
Accounts payable and accrued liabilities (Note 4)
Derivative liability (Note 16)
Due to related party (Note 9)
Deferred credit (Note 11)
Short-term bank debt (Note 10)
Long-term bank debt (Note 10)
Future income tax liability (Note 11)
Deferred credit (Note 11)
Asset retirement obligations (Note 12)
Commitments, Contingencies and Guarantees (Note 17)
ShArEhOLDErS’ EQUITY (Note 13)
Share capital
Unit capital
Contributed surplus
Deficit
Accumulated other comprehensive income (Note 14)
Total Shareholders’ Equity
On behalf of the Board:
Director
Director
20 BONTERRA OIL & GAS LTD.
BONTERRA OIL & GAS LTD. 21
1
I
B
S
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
k
c
a
l
B
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
w
e
r
d
n
a
-
-
t
n
o
r
F
3
9
1
:
5
4
:
5
1
6
2
-
3
0
-
9
0
r
o
t
c
e
f
r
e
P
a
r
r
e
t
n
o
B
_
2
9
4
0
2
0
9
2
AUDITOrS’ rEpOrT
CONSOLIDATED BALANCE ShEETS
To the Shareholders of Bonterra Oil & Gas Ltd. (formerly Bonterra Energy Income Trust):
We have audited the consolidated balance sheets of Bonterra Oil & Gas Ltd. as at December 31, 2008 and 2007 and the
consolidated statements of shareholders’ equity, operations and deficit, comprehensive income and cash flow for the
years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is
to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require
that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the
Company as at December 31, 2008 and 2007 and the results of its operations and its cash flows for the years then ended
in accordance with Canadian generally accepted accounting principles.
Chartered Accountants
Calgary, Alberta
March 11, 2009
As at December 31
($000)
ASSETS
Current
Restricted term deposit (Note 10)
Accounts receivable (Notes 4 & 15)
Crude oil inventory
Prepaid expenses (Note 4)
Future income tax asset (Note 11)
Investment in related party (Note 6)
Restricted cash (Note 7)
Future income tax asset (Note 11)
property and Equipment (Note 8)
Petroleum and natural gas properties and related equipment
Accumulated depletion and depreciation
LIABILITIES
Current
Distribution payable
Accounts payable and accrued liabilities (Note 4)
Derivative liability (Note 16)
Due to related party (Note 9)
Deferred credit (Note 11)
Short-term bank debt (Note 10)
Long-term bank debt (Note 10)
Future income tax liability (Note 11)
Deferred credit (Note 11)
Asset retirement obligations (Note 12)
Commitments, Contingencies and Guarantees (Note 17)
ShArEhOLDErS’ EQUITY (Note 13)
Share capital
Unit capital
Contributed surplus
Deficit
Accumulated other comprehensive income (Note 14)
Total Shareholders’ Equity
On behalf of the Board:
Director
Director
2008
2007
$
20 $
11,753
845
4,222
2,669
2,131
21,640
1,252
85,416
232,685
(75,692)
156,993
$
265,301 $
$
– $
23,888
–
6,000
2,305
13,325
45,518
79,910
–
64,758
18,338
208,524
99,530
–
2,542
102,072
(46,715)
1,420
(45,295)
56,777
$
265,301 $
–
10,575
792
1,462
913
4,014
17,756
–
–
187,288
(61,805)
125,483
143,239
3,724
12,291
3,085
–
–
57,422
76,522
–
7,595
–
14,904
99,021
–
90,590
2,140
92,730
(51,543)
3,031
(48,512)
44,218
143,239
20 BONTE R RA OIL & GAS LTD.
BON TERRA OI L & G AS LTD. 21
1
I
B
S
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
k
c
a
l
B
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
w
e
r
d
n
a
-
-
k
c
a
B
3
9
1
:
5
4
:
5
1
6
2
-
3
0
-
9
0
r
o
t
c
e
f
r
e
P
a
r
r
e
t
n
o
B
_
2
9
4
0
2
0
9
2
CONSOLIDATED STATEMENTS
OF ShArEhOLDErS’ EQUITY
MANAGEMENT’S rESpONSIBILITY
FOr FINANCIAL STATEMENTS
For the Years Ended December 31
($000)
Unitholders’ equity, beginning of year
Comprehensive income for the year
Adjustment of opening accumulated other
comprehensive income
Net capital contributions (Note 13)
Stock-based compensation
Distributions declared
Unitholders’ Equity
Conversion of the Trust to a Corporation (Note 4)
Dividends declared
Shareholders’ Equity, End of Year
$
2008
44,218 $
53,815
–
8,135
1,207
(42,660)
64,715
–
(7,938)
$
56,777 $
2007
53,359
31,001
2,380
993
1,133
(44,648)
44,218
(44,218)
–
–
The information provided in this report, including the financial statements, is the responsibility of management. In the
preparation of the statements, estimates are sometimes necessary to make a determination of future values for certain
assets or liabilities. Management believes such estimates have been based on careful judgements and have been properly
reflected in the accompanying financial statements.
Management maintains a system of internal controls to provide reasonable assurance that the Company’s assets are
safeguarded and to facilitate the preparation of relevant and timely information.
Deloitte & Touche LLP has been appointed by the Shareholders to serve as the Company’s external auditors. They have
examined the financial statements and provided their auditors’ report. The audit committee has reviewed these financial
statements with management and the auditors, and has reported to the Board of Directors. The Board of Directors has
approved the financial statements as presented in this annual report.
GEOrGE F. FINk
CEO
March 11, 2009
GArTh E. SChULTz
vice president, Finance and CFO
March 11, 2009
22 BONTERRA OIL & GAS LTD.
BONTERRA OIL & GAS LTD. 19
1
I
B
S
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
k
c
a
l
B
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
w
e
r
d
n
a
-
-
k
c
a
B
3
9
1
:
5
4
:
5
1
6
2
-
3
0
-
9
0
r
o
t
c
e
f
r
e
P
a
r
r
e
t
n
o
B
_
2
9
4
0
2
0
9
2
A summary of the former unit option plan as of December 31, 2008 and 2007, and changes during the years is
presented below:
CONSOLIDATED STATEMENTS
OF OpErATIONS AND DEFICIT
For the Years Ended December 31
($000)
revenue
Oil and gas sales
Gain (loss) on risk management contracts - cash
Gain (loss) on risk management contracts - non-cash
Royalties
Interest and other
Expenses
Production costs
General and administrative
Interest on debt
Reorganization costs (Note 4)
Stock-based compensation
Dry hole costs
Depletion, depreciation and accretion
Earnings Before Taxes
Taxes (Note 11)
Current
Future
Net Earnings for the Year
Deficit, beginning of year
Distributions declared
Dividends declared
Deficit, end of year
Net Earnings per Share – Basic (Note 13)
Net Earnings per Share – Diluted (Note 13)
2008
2007
$
129,083
$
(7,353)
3,085
(17,215)
45
107,645
25,413
3,401
2,740
2,121
1,207
–
14,749
49,631
58,014
437
2,151
2,588
55,426
(51,543)
(42,660)
(7,938)
(46,715) $
3.25 $
3.23 $
$
$
$
95,810
621
(3,085)
(12,444)
44
80,946
24,073
2,603
3,028
–
1,133
3,078
13,597
47,512
33,434
512
2,572
3,084
30,350
(37,245)
(44,648)
–
(51,543)
1.79
1.79
Outstanding at beginning of year
Options granted
Options exercised
Options cancelled
Outstanding at end of year
Options exercisable at end of year
2008
weighted-
Average
2007
Weighted-
Average
Options
Exercise price
Options
Exercise Price
1,177,000 $
29,000
(321,700)
(884,300)
– $
– $
27.59
39.09
24.66
29.03
–
–
721,500 $
553,000
(53,500)
(44,000)
1,177,000 $
530,000 $
26.55
28.11
18.56
27.92
27.59
26.63
BUSINESS prOSpECTS, rISkS, AND OUTLOOkS
The resource industry operates with a great deal of risk. The most significant risks may come from oil and natural gas price
swings, the uncertainty of finding new reserves from drilling programs or acquisitions, competition within the industry
and increasing environmental controls and regulations. The prices received for crude oil are established by world market
forces and for natural gas by forces within North America. Fluctuations in pricing can have extremely positive or negative
effects on the Company’s cash flow or in the value of its producing and non-producing oil and natural gas properties.
The Company presently attempts to minimize these risks by pursuing both oil and natural gas activities and operates
its oil and natural gas interests in areas which have long life reserves, where it has the technical expertise to enhance
production, control operating costs and to increase margins of profit.
SENSITIvITY ANALYSIS
Sensitivity analysis, as estimated for 2009:
U.S. $1.00 per barrel
Canadian $0.10 per MCF
Change of Canadian $0.01/U.S. $ exchange rate
ADDITIONAL INFOrMATION
at www.bonterraenergy.com.
Cash Flow
870,000 $
289,000 $
593,000 $
$
$
$
Cash Flow
Per Share
0.050
0.017
0.034
Additional information relating to the Company may be found on www.sedar.com as well as on the Company’s website
18 BONTE RR A OIL & GAS LTD.
BON TERRA OI L & G AS LTD. 23
1
I
B
S
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
k
c
a
l
B
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
w
e
r
d
n
a
-
-
t
n
o
r
F
3
9
1
:
5
4
:
5
1
6
2
-
3
0
-
9
0
r
o
t
c
e
f
r
e
P
a
r
r
e
t
n
o
B
_
2
9
4
0
2
0
9
2
CONSOLIDATED STATEMENTS
OF COMprEhENSIvE INCOME
The Company is authorized to issue an unlimited number of common shares without nominal or par value.
2008
2007
Number
Amount
Number
Amount
For the Years Ended December 31
($000)
Net Earnings for the period
Other comprehensive income, net of income tax
Unrealized (loss) gain on investments
(net of income taxes of $(272), (2007 - $252))
Gains and losses on derivatives designated as cash flow hedges
transferred to net earnings (net of income taxes of ($334))
Other Comprehensive Income (Loss)
Comprehensive Income
Comprehensive Income per Share – Basic (Note 13)
Comprehensive Income per Share – Diluted (Note 13)
2008
$
55,426 $
2007
30,350
(1,611)
1,465
–
(1,611)
53,815 $
3.15 $
3.14 $
(814)
651
31,001
1.83
1.83
$
$
$
($000)
Issued
($000)
Issued
Trust Units
Common Shares
Balance, beginning of year
Issued on reorganization to a corporation
17,257,603
Balance, end of year
17,257,603 $
99,530
– $
–
99,530
– $
–
– $
2007
2008
Number
Amount
Number
Amount
Balance, beginning of year
Transfer of contributed surplus to unit capital
Issued pursuant to Trust unit option plan
Issued on acquisition of Silverwing
16,928,158 $
–
321,700
7,745
90,590
805
7,935
200
Cancelled on conversion to a corporation
(17,257,603)
(99,530)
53,500
–
–
–
16,874,658 $
89,488
Balance, end of year
– $
–
16,928,158 $
90,590
The Company provides an option plan for its directors, officers, employees and consultants. Under the plan, the
Company may grant options for up to 1,725,760 common shares (2007 – 1,692,800 Trust Units). The exercise price of each
option granted equals the market price of the common shares on the date of grant and the option’s maximum term is
A summary of the status of the Company’s stock option plan as of December 31, 2008 and changes during the year is
five years.
presented below:
2008
weighted-
Average
Options
Exercise price
– $
1,390,500
1,390,500 $
– $
20.50
20.50
Outstanding at beginning of year
Options granted
Outstanding at end of year
Options exercisable at end of year
The following table summarizes information about common stock options outstanding at December 31, 2008:
Options Outstanding
Options Exercisable
Range of
Exercise
Prices
$20.50
Number Weighted-Average
Number
Oustanding
At 12/31/08
1,390,500
Remaining Weighted-Average
Exercisable Weighted-Average
Contractual Life
Exercise Price
At 12/31/08
Exercise Price
3.9 years
$
20.50
–
$
–
–
–
109
993
–
–
–
–
–
24 BONTERRA OIL & GAS LTD.
BONTERRA OIL & GAS LTD. 17
Implications to the Company’s controls for DC&P and ICFR are being reviewed; however the Company believes that
the majority of the procedures in place will apply once IFRS is implemented. Training will be required and is ongoing.
Individuals within the Company have been and will continue to attend courses, seminars and other training activities to
ensure the Company is adequately prepared for IFRS. Use of external legal expertise will be used to ensure compliance
CONSOLIDATED STATEMENTS
OF CASh FLOw
is maintained with all contractual agreements.
LIQUIDITY AND CApITAL rESOUrCES
During 2008, Bonterra participated in drilling 44 gross wells (30.9 net) at a total cost of $29,466,000. Included in the above
figure is approximately $1,200,000 of costs associated with the completion and tie-in of wells the Company drilled in
2007 and prior years. As discussed in the Production section, only four gross oil wells (3.2 net) were not on production by
December 31, 2008. These wells have subsequently been placed on production at a capital cost of less than $1,000,000
being spent in 2009.
The Company currently has plans to drill approximately 30 gross (18 net) oil and gas wells in 2009 at an estimated budget
figure of $15,000,000. The current plan, if Alberta suitably adjusts its royalty structure, includes 18 gross (14 net) Cardium
vertical oil wells and two gross (0.65 net) Cardium horizontal oil wells. The balance of the drilling is anticipated to consist of
wells in BC and Saskatchewan. The majority of the drilling is anticipated to occur during the third and fourth quarters due
in part to the Company’s position that it is prudent to wait for the Alberta government to disclose its incentive programs
and potential modifications to its high royalty rates so that Alberta will be competitive for certain types of wells.
Bonterra anticipates funding the 2009 capital program out of cash flow and if necessary an increase in the Company’s
line of credit. Should the need arise, the Company is prepared to raise sufficient equity to complete its planned capital
expenditures. However, the current capital budget is predicated on commodity prices recovering to above $50 U.S. for
crude oil and $6 per MCF for natural gas and an $0.82 dollar for the last six months of 2009.
Bonterra is continuing with its efforts to acquire producing and non producing properties through either property or
entity acquisitions. Funding for any acquisition would depend on items such as the type of acquisition, quality of the
assets, size of the purchase and Bonterra’s trading price at the time of the acquisition.
Due to the corporate reorganization and acquisition of Silverwing, the Company amended its bank facility to consist of
an $80,000,000 syndicated revolving credit facility and a $20,000,000 non-syndicated demand credit facility (December
31, 2007 - $69,900,000) (non-syndicated demand facility). The terms of the syndicated revolving credit facility provide that
the loan is revolving to May 30, 2010 and is subject to annual review. The revolving credit facility has no fixed payment
requirements. The terms of the non-syndicated demand credit facility provide that the loan is due on demand and is
subject to annual review and has no fixed repayment terms.
At December 31, 2008 the Company had bank debt of $93,235,000 (2007 – $57,422,000). For the interest rates charged on
the facilities please refer to the Interest Expense section of this MD&A.
The amount available for borrowing under the credit facilities is reduced by outstanding letters of credit. Letters of credit
totaling $525,000 (December 31, 2007 - $355,000) were issued at December 31, 2008. Of the letters of credit, $20,000
is secured by a restricted term deposit. Security for the credit facilities consists of various fixed and floating demand
debentures totaling $200,000,000 over all of the Company’s assets and a general security agreement with first ranking
over all personal and real property.
The facility contains few covenants due to the substantial asset value (see review of operations) of the Company’s assets
and the long business relationship established by the Company with its principal banker.
The following is a list of the material covenants:
• The Company as of December 31, 2008 is required to not exceed $100,000,000 in consolidated debt (includes
negative working capital but excludes debt to related parties).
• Dividends paid in any quarter shall not exceed 80 percent of the average previous four quarters cash flow as
defined under GAAP.
For the Years Ended December 31
($000)
Operating Activities
Net earnings for the year
Items not affecting cash
(Gain) loss on risk management contracts - non-cash
Stock-based compensation
Dry hole costs
Depletion, depreciation and accretion
Future income taxes
Change in non-cash working capital
Accounts receivable
Crude oil inventory
Prepaid expenses
Accounts payable and accrued liabilities
Asset retirement obligations settled
Financing Activities
Increase in debt
Due to related party
Stock option proceeds
Unit distributions
Dividends
Investing Activities
Property and equipment expenditures
Acquisition (Note 5)
Reorganization (Note 4)
Restricted term deposit
Change in non-cash working capital
Accounts receivable
Accounts payable and accrued liabilities
Net cash inflow
Cash, beginning of year
Cash, End of Year
Cash Interest Paid
Cash Taxes Paid
2008
2007
$
55,426 $
30,350
(3,085)
1,207
–
14,749
2,151
70,448
2,642
(40)
(360)
(57)
(3,063)
(878)
69,570
20,698
6,000
7,935
(46,384)
(7,938)
(19,689)
(30,060)
(13,816)
(11,257)
20
–
5,272
(49,881)
–
–
– $
3,085
1,133
3,078
13,597
2,572
53,815
(1,082)
51
(262)
(269)
(820)
(2,382)
51,433
12,043
–
993
(44,974)
–
(31,938)
(19,300)
–
–
–
993
(1,188)
(19,495)
–
–
–
2,740 $
582 $
3,028
292
$
$
$
2
9
0
2
0
4
9
2
_
B
o
n
t
e
r
r
a
P
e
r
f
e
c
t
o
r
0
9
-
0
3
-
2
6
1
5
:
4
5
:
1
9
3
F
r
o
n
t
-
-
a
n
d
r
e
w
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
B
l
a
c
k
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
S
B
I
1
16 BONTE R RA OIL & GAS LTD.
BON TERRA OI L & G AS LTD. 25
2
9
0
2
0
4
9
2
_
B
o
n
t
e
r
r
a
P
e
r
f
e
c
t
o
r
0
9
-
0
3
-
2
6
1
5
:
4
5
:
1
9
3
B
a
c
k
-
-
a
n
d
r
e
w
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
B
l
a
c
k
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
S
B
I
1
NOTES TO ThE
CONSOLIDATED FINANCIAL STATEMENTS
For the Years Ended December 31, 2008 and 2007
1. ChANGE OF OrGANIzATION
On November 12, 2008, Bonterra Energy Income Trust (the “Trust”) converted to Bonterra Oil & Gas Ltd. (the “Company”)
through a reverse takeover by the Trust of SRX Post Holdings Inc. (SRX). In conjunction with the reorganization, the Trust
acquired all the issued and outstanding shares of Silverwing Energy Inc. (Silverwing). Concurrently, all of the Company’s
subsidiaries, including Silverwing were amalgamated into Bonterra Energy Corp.
Prior to the Arrangement on November 12, 2008, the consolidated financial statements included the accounts of the Trust
and its subsidiaries. After giving effect to the Arrangement, the consolidated financial statements have been prepared on
a continuity of interest basis, which recognizes Bonterra Oil & Gas Ltd. as the successor entity to the Trust. The continuity of
interest basis requires that the 2007 comparative consolidated financial statement figures are those previously presented
by the Trust. The continuity of interest basis requires that the 2007 comparative consolidated financial statement figures
are those previously presented by the Trust.
2. SIGNIFICANT ACCOUNTING pOLICIES
Basis of presentation
The consolidated financial statements have been prepared by management in accordance with Canadian generally
accepted accounting principles (GAAP) as described below.
Consolidation
These consolidated financial statements include the accounts of the “Company”, the Trust (wholly owned by the
Company) and its wholly owned subsidiary Bonterra Energy Corp. (Bonterra). Inter-company transactions and balances
are eliminated upon consolidation.
Measurement Uncertainty
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as at the date of
the balance sheets as well as the reported amounts of revenues, expenses, and cash flows during the periods presented.
Such estimates relate primarily to unsettled transactions and events as of the date of the financial statements. Actual
results could differ materially from estimated amounts.
Amounts recorded for depletion, depreciation and accretion costs and amounts used for ceiling test calculations
are based on estimates of crude oil and natural gas reserves and future costs required to develop those reserves.
Stock-based compensation is based upon expected volatility and option life estimates. Asset retirement obligations are
based on estimates of abandonment costs, timing of abandonment, inflation and interest rates. The provision for income
taxes is based on judgements in applying income tax law and estimates on the timing, likelihood and reversal of temporary
differences between the accounting and tax basis of assets and liabilities. These estimates are subject to measurement
uncertainty and changes in these estimates could materially impact the financial statements of future periods.
revenue recognition
Revenues associated with sales of petroleum and natural gas are recorded when title passes to the customer.
Joint Interest Operations
Significant portions of the Company’s oil and gas operations are conducted jointly with other parties and accordingly the
financial statements reflect only the Company’s proportionate interest in such activities.
International Financial reporting Standards (IFrS)
The Accounting Standards Board (AcSB) has announced that Canadian GAAP, as we currently know them, will cease
to exist for all Publicly Accountable Entities (PAE’s) as of January 1, 2011. From that point onward the Company will be
required to account for and report under IFRS.
Although the International Accounting Standards Board (IASB) intends to revise several standards between now and
2011, IFRS will be adopted in Canada utilizing a “big bang” approach, with the exception of some Canadian GAAP
changes that have occurred or will occur in periods leading up to the transition date.
The IASB has undertaken a number of projects, many being joint projects with the Financial Accounting Standards Board
in the U.S., that may significantly change existing international standards.
This degree of activity currently being undertaken by the standard setters makes the convergence from Canadian GAAP
to IFRS a moving target. Due to these likely changes, careful monitoring of developments will be required in order to
understand fully the accounting and business implications of the new requirements.
The Company in the fourth quarter of 2008 has commenced the process of conversion to IFRS by engaging its external
auditors to perform a preliminary high-level scoping study to consider the potential impact of the implementation of IFRS
on the Company. Based on the findings to date the following areas have been identified as high impact areas:
•
•
•
•
•
•
•
•
•
•
•
•
•
IFRS 1 – First time adoption of IFRS
IFRS 3 – Business combinations
IAS 16 – Property and equipment
IAS 36 – Impairment of assets
Medium impact areas include:
IFRS 6 – Exploration and evaluation of mineral resources
IFRS 2 – Share-based payments
IAS 1 – Presentation of financial statements
IAS 10 – Events after the balance sheet date
IAS 12 – Income Taxes
IAS 18 – Revenues
IAS 23 – Borrowing costs
IAS 39 – Financial instruments, recognition and measurement
IAS 37 – Provisions, contingent liabilities and contingent assets
The impact of IFRS will be significant; however the Company has always maintained an accounting policy of successful
efforts for property and equipment that will result in a major reduction in the level of conversion compared to most oil and
gas companies who used the full cost accounting policy.
Over the course of 2009, the Company will be completing a more detailed analysis of the above areas and making
decisions in respect of accounting policies that will be followed in respect of the above identified areas, documenting
those policies, and calculating the impact of those policies on existing financial statement items and presentations.
The Company has recently implemented a new financial accounting system that provides for sufficient detail to comply
with the IFRS requirements. As the Company has been using successful efforts since its inception, detail at a well level has
been maintained under its past and current financial accounting systems as well as procedures are in place to capture this
information at the operational level.
26 BONTERRA OIL & GAS LTD.
BONTERRA OIL & GAS LTD. 15
COMMITMENTS
as follows:
Contract Obligations
($000)
Office leases (1)
The Company has no contractual obligations that last more than a year other than its office lease agreements which are
Total
Less than
1 year
1 – 3
years
$
2,907
$
589 $
1,238
$
4 – 5
years
1,080
Inventories
Inventories consist of crude oil. Crude oil stored in the Company’s tanks are valued on a first in first out basis at the lower
of cost or net realizable value. Inventory cost for crude oil is determined based on combined average per barrel operating
costs, royalties and depletion and depreciation for the year and net realizable value is determined based on sales price
in the month preceding year end.
Investments
(1)
Includes Silverwing’s former office space which is being sublet at a rate that approximates the rates charged to the Company. The funds
received on the sublease have not been offset against the contractual liability.
Investments are carried at fair value. Fair value is determined by multiplying the year end trading price of the investments
by the number of common shares held as at period end.
FINANCIAL rEpOrTING UpDATE
property and Equipment
During 2007, the Company completed the implementation of the new CICA Handbook Section 3855, Financial Instruments
– Recognition and Measurement, Section 1530, Comprehensive Income and Section 3865, Hedges that deal with the
recognition and measurement of financial instruments at fair value and comprehensive income. See Notes 2 and 14 in the
Notes to the audited Consolidated Financial Statements for further details.
Accounting Changes
During 2008, the Company adopted Section 1535 “Capital Disclosures”, Section 3862, “Financial Instruments - Disclosures”
and Section 3863, “Financial Instruments - Presentation”. All the above Sections were required to be adopted for fiscal
years beginning on or after October 1, 2007. As a result, the Company has added Note 16 providing the required
disclosures regarding the Company’s objectives, policies and processes for managing capital and the significance of
financial instruments for the entity’s financial position and performance; and the nature, extent and management of risks
arising from financial instruments to which the entity is exposed.
Future Accounting Changes
In February 2008, the CICA issued Section 3064, “Goodwill and Intangible Assets”, replacing Section 3062, “Goodwill and
Other Intangible Assets” and Section 3450, “Research and Development Costs”. Various changes have been made to
other sections of the CICA Handbook for consistency purposes. The new section will be applicable to financial statements
relating to fiscal years beginning on or after October 1, 2008. Accordingly, the Company will adopt the new standards
for its fiscal year beginning January 1, 2009. This standard establishes standards for the recognition, measurement,
presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets by profit-oriented
enterprises. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062.
The Company does not expect that the adoption of this new Section will have a material impact on its consolidated
financial statements.
In January 2009, the CICA issued Section 1582, “Business Combinations”, which replaces former guidance on business
combinations. Section 1582 establishes principles and requirements of the acquisition method for business combinations
and related disclosures. This statement applies prospectively to business combinations for which the acquisition date
is on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier adoption
permitted. The Company plans to adopt this standard prospectively effective January 1, 2009 and does not expect the
adoption of this statement to have a material impact on the Company’s results of operations or financial position.
In January 2009, the CICA issued Sections 1601, “Consolidated Financial Statements”, and 1602, “Non-controlling
Interests”, which replaces existing guidance. Section 1601 establishes standards for the preparation of consolidated
financial statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in
consolidated financial statements subsequent to a business combination. These standards are effective on or after the
beginning of the first annual reporting period beginning on or after January 2011 with earlier application permitted. The
Company plans to adopt these standards effective January 1, 2009 and does not expect the adoption will have a material
impact on the results of operations or financial position.
Petroleum and Natural Gas Properties and Related Equipment
The Company follows the successful efforts method of accounting for petroleum and natural gas properties and related
equipment. Costs of exploratory wells are initially capitalized pending determination of proved reserves. Costs of wells
which are assigned proved reserves remain capitalized, while costs of unsuccessful wells are charged to earnings. All other
exploration costs including geological and geophysical costs are charged to earnings as incurred. Development costs,
including the cost of all wells, are capitalized.
Producing properties are assessed annually or more frequently as economic events dictate, for potential impairment.
Impairment is assessed by comparing the estimated net undiscounted future cash flows to the carrying value of the asset.
If required, the impairment recorded is the amount by which the carrying value of the asset exceeds its fair value.
Costs related to undeveloped properties are excluded from the depletion base until it is determined whether or not
proved reserves exist or if impairment of such costs has occurred. These properties are assessed at least annually to
determine whether impairment has occurred.
Depreciation and depletion of capitalized costs of oil and gas producing properties are calculated using the unit of
production method. Development and exploration drilling and equipment costs are depleted over the remaining proved
developed reserves. Depreciation of other plant and equipment is provided on the straight line method. Straight line
depreciation is based on the estimated service lives of the related assets which is estimated to be ten years.
Furniture, Fixtures and Office Equipment
These assets are recorded at cost and depreciated over a three to ten year period representing their estimated useful lives.
Income Taxes
The Company accounts for income taxes using the liability method. Under this method, the Company records a future
income tax asset or liability to reflect any difference between the accounting and tax basis of assets and liabilities,
using substantively enacted income tax rates. The effect on future tax assets and liabilities of a change in tax rates is
recognized in net earnings in the period in which the change occurs. Future income tax assets are only recognized to the
extent it is more likely than not that sufficient future taxable income will be available to allow the future income tax asset
to be realized.
Asset retirement Obligations
The Company recognizes an Asset Retirement Obligation (ARO) in the period in which it is incurred when a reasonable
estimate of the fair value can be made. On a periodic basis, management will review these estimates and changes, if any,
will be applied prospectively. The fair value of the estimated ARO is recorded as a long-term liability, with a corresponding
increase in the carrying amount of the related asset. The capitalized amount is depleted on a unit-of-production basis
over the life of the reserves. The liability amount is increased each reporting period due to the passage of time and
the amount of accretion is charged to earnings in the period. Revisions to the estimated timing of cash flows or to the
original estimated undiscounted cost would also result in an increase or decrease to the ARO. Actual costs incurred upon
settlement of the obligations are charged against the ARO to the extent of the liability recorded.
2
9
0
2
0
4
9
2
_
B
o
n
t
e
r
r
a
P
e
r
f
e
c
t
o
r
0
9
-
0
3
-
2
6
1
5
:
4
5
:
1
9
3
B
a
c
k
-
-
a
n
d
r
e
w
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
B
l
a
c
k
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
S
B
I
1
14 BONTE R RA OIL & GAS LTD.
BON TERRA OI L & G AS LTD. 27
2
9
0
2
0
4
9
2
_
B
o
n
t
e
r
r
a
P
e
r
f
e
c
t
o
r
0
9
-
0
3
-
2
6
1
5
:
4
5
:
1
9
3
F
r
o
n
t
-
-
a
n
d
r
e
w
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
B
l
a
c
k
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
S
B
I
1
Stock-Based Compensation
FINDING AND DEvELOpMENT COSTS (F&D COSTS)
The Company accounts for stock based compensation using the fair-value method of accounting for stock options
granted to directors, officers, employees and other service providers using the Black-Scholes option pricing model.
Stock-based compensation expense is recorded over the vesting period with a corresponding amount reflected in
contributed surplus. Stock-based compensation expense is calculated as the estimated fair value of the options at the
time of grant, amortized over their vesting period. When stock options are exercised, the associated amounts previously
recorded as contributed surplus are reclassified to common share capital. The Company has not incorporated an estimated
forfeiture rate for stock options that will not vest, rather, the Company accounts for actual forfeitures as they occur.
Financial Instruments
Financial instruments are measured at fair value on initial recognition of the instrument, into one of the following five
categories: held-for trading, loans and receivables, held-to-maturity investments, available-for-sale financial assets or
other financial liabilities.
Subsequent measurement of financial instruments is based on their initial classification. Held-for-trading financial assets
are measured at fair value and changes in fair value are recognized in net earnings. Available-for-sale financial instruments
are measured at fair value with changes in fair value recorded in other comprehensive income until the instrument is
derecognized or impaired. The remaining categories of financial instruments are recognized at amortized cost using the
effective interest rate method.
All risk management contracts are recorded in the balance sheet at fair value unless they qualify for the normal sale
and normal purchase exemption. All changes in their fair value are recorded in net earnings unless cash flow hedge
accounting is used, in which case changes in fair value are recorded in other comprehensive income until the underlying
hedged transaction is recognized in net earnings. Any hedge ineffectiveness is immediately recognized in net earnings.
The Company has elected not to use cash flow hedge accounting on its risk management contracts with financial
counterparties resulting in all changes in fair value being recorded in net earnings.
Cash and restricted cash are classified as held-for-trading and are measured at fair value which equals the carrying value
and any gains or losses are recognized in earnings in the period they occur. Accounts receivable are classified as loans
and receivables which are measured at amortized costs. Investments in related party are classified as available-for-sale
which are measured at fair value and any gains or losses are recognized in other comprehensive income in the period
they occur. Accounts payable and accrued liabilities and bank debt are classified as other financial liabilities, which are
measured at amortized cost.
risk Management Contracts
The Company is exposed to market risks resulting from fluctuations in commodity prices, foreign currency exchange
rates and interest rates in the normal course of its business. The Company may use a variety of instruments to manage
these exposures. For transactions where hedge accounting is not applied, the Company accounts for such instruments
using the fair value method by initially recording an asset or liability, and recognizing changes in the fair value of the
instruments in earnings as unrealized gains or losses on risk management contracts. Fair values of financial instruments
are determined from third party quotes or valuations provided by independent third parties. Any realized gains or losses
on risk management contracts are recognized in earnings in the period they occur.
The Company may elect to use hedge accounting when there is a high degree of correlation between the price movements
in the financial instruments and the items designated as being hedged and has documented the relationship between
the instruments and the hedged item as well as its risk management objective and strategy for undertaking hedge
transactions. During the year ended December 31, 2008, the Company did not designate any of its financial instruments
as hedges. There are no risk management contracts outstanding as at December 31, 2008.
The Company has been active in its capital development program over the past three years. Over this time period
Bonterra has incurred the following F&D Costs:
2008 F&D
2007 F&D
2006 F&D
2008
2007
Costs per Costs per
Costs per
Three Year
Three Year
BOE (1)(2)
BOE (1)(2)
BOE (1)(2)
Average
Average
Proved Reserve Additions
Proved plus Probable Reserve Additions
$
$
8.67 $
7.47 $
2.74 $
2.68 $
25.51 $
18.21 $
12.30 $
9.45 $
14.37
11.07
The above figures have been calculated in accordance with National Instrument 51-101 (NI 51-101) where the F&D Costs
equate to the total exploration and development costs incurred by the Company during the year plus the yearly change
in estimated future development costs as calculated by Sproule Associates Limited. The following precautionary notes
have been provided as required by NI 51-101.
(1) Barrels of Oil Equivalent may be misleading, particularly if used in isolation. A BOE conversion ratio of 6MCF:1bbl is
based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a
value equivalency at the wellhead.
(2) The aggregate of the exploration and development costs incurred in the most recent financial year and the change
during that year in estimated future development costs generally will not reflect total finding and development
costs related to reserve additions for that year.
Results from the Company’s Cardium oil drilling program continue to be better than anticipated resulting in an increase in
the third party engineering reports estimated recoverable reserves from existing wells but also from future development.
Continued low decline rates have also resulted in increased reserves due to technical revisions. Both these factors
contributed to an overall F&D cost in 2008 of $7.47 per BOE on a proved plus probable basis.
rELATED pArTY TrANSACTIONS
The Company holds 689,682 (2007 – 689,682) common shares in Comaplex which have a fair market value as of
December 31, 2008 of $2,131,000 (2007 - $4,014,000). Comaplex is a publically traded mineral company on the Toronto
Stock Exchange. The Company’s ownership in Comaplex represents approximately 1.3 percent of the issued and
outstanding common shares of Comaplex. The Company has common directors and management with Comaplex.
Comaplex paid a management fee to the Company of $330,000 (2007 - $300,000). Comaplex also shares office rental
costs and reimburses the Company for costs related to employee benefits and office materials. In addition, Comaplex
owns 204,633 (December 31, 2007 – 204,633) common shares in the Company. Services provided by the Company include
executive services (president and vice president, finance duties), accounting services, oil and gas administration and
office administration. All services performed are charged at estimated fair value. At December 31, 2008, Comaplex owed
the Company $56,000 (December 31, 2007 - $63,000).
In order to facilitate the acquisition of Silverwing, the Company borrowed on a short-term basis $20,000,000 from Comaplex
to allow time to finalize documentation for its new bank line of credit. The funds were repaid on November 21, 2008. Total
interest paid on the loan was $21,000.
The Company also has a management agreement with Pine Cliff. Pine Cliff has common directors and management
with the Company. Pine Cliff trades on the TSX Venture Exchange. Pine Cliff paid a management fee to the Company of
$238,000 (2007 - $216,000). Services provided by the Company include executive services (president and vice president,
finance duties), accounting services, oil and gas administration and office administration. All services performed are
charged at estimated fair value. The Company has no share ownership in Pine Cliff. As at December 31, 2008 the Company
had an account receivable from Pine Cliff of $1,000 (December 31, 2007 – $4,000).
As of December 31, 2008, the Company’s CEO and major shareholder had loaned the Company $6,000,000. The loan is
unsecured, bears interest at Canadian chartered bank prime less one half of a percent and has no set repayment terms.
The loan can only be repaid should the Company have sufficient available borrowing limits within its bank debt. Interest
paid on this loan during 2008 was $7,000.
28 BONTERRA OIL & GAS LTD.
BONTERRA OIL & GAS LTD. 13
1
I
B
S
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
k
c
a
l
B
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
w
e
r
d
n
a
-
-
t
n
o
r
F
2
8
1
:
5
4
:
5
1
6
2
-
3
0
-
9
0
r
o
t
c
e
f
r
e
P
a
r
r
e
t
n
o
B
_
2
9
4
0
2
0
9
2
Other comprehensive income for 2008 consists of an unrealized loss on investment in a related party of $1,611,000 (2007
gain of $1,465,000) including a fourth quarter loss of $1,123,000 relating to a reduction in the related company’s fair value.
Effective October 1, 2007, the Company discontinued the use of hedge accounting due to the difficulty in determining
the effective portion of the commodity risk management contracts.
Basic and Diluted per Share (formerly per Unit) Calculations
Basic earnings per share are computed by dividing earnings by the weighted average number of shares outstanding
during the year. Diluted per share amounts reflect the potential dilution that could occur if options to purchase shares
were exercised. The treasury stock method is used to determine the dilutive effect of common share options, whereby
proceeds from the exercise of common share options or other dilutive instruments are assumed to be used to purchase
common shares at the average market price during the period.
Cash flow from operations
10,336
22,492
13,369
69,570
51,433
Capital Disclosures
Three months ended
Twelve months ended
December September December
December
December
31, 2008
30, 2008
31, 2007
31, 2008
31, 2007
3. NEw ACCOUNTING pOLICIES
CASh FLOw FrOM OpErATIONS
($ 000)
Cash flow from operations increased 35 percent year over year, mainly due to increased commodity prices received
during the first nine months of 2008. The fourth quarter of 2008 saw significant price declines in all commodity categories.
Although the Company was able to increase production in the fourth quarter of 2008 by almost nine percent over the
previous quarter, cash flow from operations decreased approximately 54 percent. One time costs of $1,369,000 incurred
in Q4 (Q3 - $752,000) related to the reorganization also contributed to the decline.
With the continuing depressed crude oil and natural gas prices, cash flow for 2009 is expected to be significantly negatively
affected. The price declines are expected to be partially offset by anticipated production volumes in excess of 5,000 BOE
per day for 2009, and anticipated decreases in G&A costs (lower employee compensation) and in corporate resource
surcharge (tax on revenues). Also, Bonterra does not expect any further costs associated with the acquisition of Silverwing
or the reorganization.
CASh NETBACkS
The following table illustrates the Company’s cash netback:
$ per Barrel of Oil Equivalent (BOE)
Production volumes (BOE)
Gross production revenue
Realized gain (loss) on risk management contracts
Royalties
Field operating
Field netback
General and administrative
Interest and taxes
Cash netback
$ per Barrel of Oil Equivalent (BOE)
Production volumes (BOE)
Gross production revenue
Realized gain (loss) on risk management contracts
Royalties
Field operating
Field netback
General and administrative
Interest and taxes
Cash netback
The following table illustrates the Company’s cash netback for the three months ended:
2008
2007
1,590,666
1,539,461
$
81.15 $
$
45.59 $
December 31,
September 30,
2008
422,008
2008
395,962
$
(4.62)
(10.82)
(15.98)
49.73
(2.14)
(2.00)
51.27 $
2.31
(6.86)
(16.25)
30.47
(1.95)
(1.90)
62.24
0.40
(8.08)
(15.64)
38.92
(1.69)
(2.30)
34.93
95.80
(7.60)
(12.00)
(15.84)
60.36
(2.18)
(1.73)
56.45
$
26.62 $
Effective January 1, 2008, the Company prospectively adopted the Canadian Institute of Chartered Accountants (CICA)
Section 1535, “Capital Disclosures” which establishes standards for disclosing information about the Company’s capital
and how it is managed. It requires disclosures of the Company’s objectives, policies and processes for managing capital,
the quantitative data about what the Company regards as capital, whether the Company has complied with any capital
requirements and if it has not complied, the consequences of such non-compliance. The only effect of adopting this
standard is disclosures about the Company’s capital and how it is managed (see Note 16).
Financial Instruments Disclosures and presentation
Effective January 1, 2008, the Company prospectively adopted Section 3862, “Financial Instruments – Disclosures” and
Section 3863, “Financial Instruments – Presentation.” These new accounting standards replaced Section 3861, “Financial
Instruments – Disclosure and Presentation.” Section 3862 requires additional information regarding the significance of
financial instruments for the entity’s financial position and performance, and the nature, extent and management of
risks arising from financial instruments to which the entity is exposed. The additional disclosures required under these
standards are included in Note 16.
recent Accounting pronouncements
In February 2008, the CICA issued Section 3064, “Goodwill and Intangible Assets”, replacing Section 3062, “Goodwill and
Other Intangible Assets” and Section 3450, “Research and Development Costs”. Various changes have been made to
other sections of the CICA Handbook for consistency purposes. The new section will be applicable to financial statements
relating to fiscal years beginning on or after October 1, 2008. The Company adopted these standards for its fiscal year
beginning January 1, 2009 with no impact on its consolidated financial statements.
In January 2009, the CICA issued Section 1582, “Business Combinations”, which replaces former guidance on business
combinations. Section 1582 establishes principles and requirements of the acquisition method for business combinations
and related disclosures. This statement applies prospectively to business combinations for which the acquisition date is
on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier adoption
permitted. The Company plans to adopt this standard prospectively effective January 1, 2009 and does not expect the
adoption of this statement to have a material impact on the Company’s results of operations or financial position.
In January 2009, the CICA issued Sections 1601, “Consolidated Financial Statements”, and 1602, “Non-controlling
Interests”, which replaces existing guidance. Section 1601 establishes standards for the preparation of consolidated
financial statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in
consolidated financial statements subsequent to a business combination. These standards are effective on or after the
beginning of the first annual reporting period beginning on or after January 2011 with earlier application permitted. The
Company plans to adopt these standards effective January 1, 2009 and does not expect the adoption will have a material
impact on the results of operations or financial position.
The Accounting Standards Board has confirmed the convergence of Canadian GAAP with International Financial Reporting
Standards (IFRS) will be effective January 1, 2011. The Company has performed an initial scoping process in order to
ensure successful implementation within the required timeframe. The impact on the Company’s consolidated financial
statements is not reasonably determinable at this time. Key information will be disclosed as it becomes available during
the transition period.
12 BONTE RR A OIL & GAS LTD.
BON TERRA OI L & G AS LTD. 29
1
I
B
S
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
k
c
a
l
B
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
w
e
r
d
n
a
-
-
k
c
a
B
2
9
1
:
5
4
:
5
1
6
2
-
3
0
-
9
0
r
o
t
c
e
f
r
e
P
a
r
r
e
t
n
o
B
_
2
9
4
0
2
0
9
2
4. rEOrGANIzATION
The Company has the following tax pools, which may be used to reduce taxable income in future years, limited to the
As part of the reorganization of the Trust, SRX acquired all the issued and outstanding trust units of Bonterra Energy
Income Trust on a basis of one Trust Unit for one Common Share of SRX. Immediately preceding the reorganization, SRX
was in receivership. Prior to the conversion, the Trust advanced $11,257,000 to SRX for settlement of claims pursuant to
the CCAA proceedings. Upon completion of the CCAA procedures, SRX was owed $2,224,000 in outstanding tax and
legal claims that will be used by the CCAA Monitor to settle secured creditor claims. This amount has been recorded as
an outstanding account receivable by the Company.
In addition, SRX paid an advance of $1,800,000 to the CCAA Monitor for costs and payment of the unsecured creditors.
This amount has been recorded as a prepaid expense in the accounts of the Company.
Included in accounts payable is $4,024,000 to account for the amount due to the secured and unsecured creditors.
Of the tax claims, $66,000 had been received and repaid to the Monitor by December 31, 2008. In addition, $99,000 of
expense claims had been paid by the Monitor and deducted from the advance.
5. BUSINESS COMBINATION
On November 12, 2008, the Company acquired all the common shares of Silverwing for cash consideration of $13,816,000
(including acquisition costs of $334,000) plus the issuance of 7,745 common shares at a value of $25.85 per common share
plus the assumption of $14,979,000 of negative working capital. The results of Silverwing’s operations have been included
in the consolidated financial statements since that date. The acquisition was funded through the Company’s new bank
facility (see Note 10).
The acquisition was accounted for using the purchase method and the purchase price was allocated to the fair value of
the assets acquired and the liabilities assumed as follows:
Cost of acquisition (000’s)
Cash paid
Value of common stock
Acquisition costs
Allocation of purchase price:
Restricted cash
Future income tax benefit
Property and equipment
Working capital deficiency
Asset retirement obligations
$
$
$
$
13,482
200
334
14,016
1,252
18,325
15,347
(14,979)
(5,929)
14,016
6. INvESTMENT IN rELATED pArTY
The investment consists of 689,682 (December 31, 2007 – 689,682) common shares in Comaplex Minerals Corp (Comaplex),
a company with common directors and management with the Company and its subsidiaries. The investment is recorded
at fair market value. The common shares trade on the Toronto Stock Exchange under the symbol CMF. The investment
represents less than a one and a half percent ownership in the outstanding shares of Comaplex.
7. rESTrICTED CASh
An escrow account was held by Silverwing prior to its acquisition by the Company. The escrow account was created to
support eligible expenditures related to a farm-in agreement. The Company may access the funds upon completion and
tie-in or abandonment and reclamation of 20 wells. The funds are administered by the farmors’ legal counsel. The funds
in the escrow account are invested in interest bearing term deposits.
Rate of Utilization
%
Amount
20-100
$
7
20
10
30
100
100
100
23,696
1,870
4,581
25,072
50,743
10,530
80,357
271,029
$
467,878
Percentage
85.16
14.84
100.00
applicable rates of utilization:
($000)
Undepreciated capital costs
Eligible capital expenditures
Share issue costs
Canadian oil and gas property expenditures
Canadian development expenditures
Canadian exploration expenditures
SR&ED expenditures
Income tax losses carried forward (1)
those distributions is as follows:
Taxable Income (Other Income)
Return of Capital
reported as qualified dividends.
NET EArNINGS
($ 000)
Net Earnings
(1)
Income tax losses carried forward expire in the following years; 2014 - $1,069,000, 2025 - $3,179,000, 2026 - $109,244,000,
2027 - $116,787,000, 2028 - $40,750,000.
Prior to becoming a corporation, the Trust paid nine distributions for the 2008 tax year. The Canadian tax breakdown of
With respect to cash distributions paid during the year to U.S. individual unitholders, 17.71 percent should be reported
as a return of capital (to the extent of the Unitholder’s U.S. tax basis in their respective units) and 82.29 percent should be
Three months ended
Twelve months ended
December September December
December
December
31, 2008
30, 2008
31, 2007
31, 2008
31, 2007
10,585
21,125
8,372
55,426
30,350
Bonterra’s net earnings for the year ended December 31, 2008 represents an 82 percent increase over the Company’s
2007 net earnings. The Company recorded net earnings per share on a fully diluted basis in 2008 of $3.23 verses $1.79 in
the 2007 year. This represents a return on Shareholders’ equity of approximately 97.6 percent (2007 – 68.6 percent) based
on year end Shareholders’ equity.
Strong crude oil and natural gas prices for most of 2008 along with a three percent increase in production volumes
were driving factors behind the increased profit. However, during the fourth quarter and continuing into the first quarter
and likely beyond, commodity prices have plunged to under $40 U.S. ($50 Cdn). This along with natural gas prices in
the $4 to $5 dollar range will significantly reduce the Company’s future net earnings. The Company’s low capital costs
combined with the Company’s low production decline rates should allow for continued positive earnings even in the
above mentioned price environment.
COMprEhENSIvE INCOME
On January 1, 2007, Bonterra became obliged to adopt the new accounting standards regarding the accounting for
financial instruments. On adoption, the Company increased its investment in related party by $1,836,000 for the fair value
of this investment. On January 1, 2007, Bonterra further recognized a current asset of $1,189,000 for the fair value of its
commodity derivative contracts. These adjustments resulted in a further increase in the future income tax liability and
accumulated other comprehensive income of $645,000 and $2,380,000, respectively.
30 BONTERRA OIL & GAS LTD.
BONTERRA OIL & GAS LTD. 11
1
I
B
S
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
k
c
a
l
B
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
w
e
r
d
n
a
-
-
k
c
a
B
2
9
1
:
5
4
:
5
1
6
2
-
3
0
-
9
0
r
o
t
c
e
f
r
e
P
a
r
r
e
t
n
o
B
_
2
9
4
0
2
0
9
2
Provisions are made for asset retirement obligations through the recognition of the fair value of obligations associated
with the retirement of tangible long-life assets being recorded in the period the asset is put into use, with a corresponding
increase to the carrying amount of the related asset. The obligations recognized are statutory, contractual or legal
obligations. The liability is adjusted over time for changes in the value of the liability through accretion charges which are
included in depletion, depreciation and accretion expense. The costs capitalized to the related assets are amortized to
earnings in a manner consistent with the depletion and depreciation of the underlying asset.
At December 31, 2008, the estimated total undiscounted amount required to settle the asset retirement obligations was
$58,903,000 (2007 - $54,622,000). Of the $4,281,000 increase, the majority is due to the Silverwing acquisition.
These obligations will be settled based on the useful lives of the underlying assets, which extend up to 50 years into
the future. This amount has been discounted using a credit-adjusted risk-free interest rate of five percent. The discount
rate is reviewed annually and adjusted if considered necessary. A change in the rate would have a significant impact on
the amount recorded for asset retirement obligations. Based on the current provision, a one percent increase in the risk
adjusted rate would decrease the asset retirement obligation by $2,706,000. While a one percent decrease in the risk
adjusted rate would increase the asset retirement obligation by $3,639,000.
The above calculation requires an estimation of the amount of the Company’s petroleum reserves by field. This figure
is calculated annually by an independent engineering firm and is used to calculate depletion. This calculation is to a
large extent subjective. Reserve adjustments are affected by economic assumptions as well as estimates of petroleum
products in place and methods of recovering those reserves. To the extent reserves are increased or decreased, depletion
costs will vary.
For the fiscal year ending December 31, 2008, the Company expensed $14,749,000 (2007 - $16,675,000) for the
above-described items including $Nil (2007 - $3,078,000) for dry hole costs. During 2007 the Company wrote off all costs
related to eight wells which no reserves were attributed by the independent third party engineers.
The Company continues to have relatively low finding and development costs (see discussion under Finding
and Development Costs). Based on year end reserves, the Company’s average cost of proved reserves is $6.40
(2007 - $5.84) per BOE.
The Company currently has an estimated reserve life for its proved developed producing reserves of 12.5 (2007 – 11.3)
years calculated using the Company’s gross reserves (prior to allowance for royalties) based on the third party engineering
report dated December 31, 2008 and using fourth quarter 2008 average production rates of 4,587 BOE per day
(2007 – 4,295 BOE per day). Based on total proved reserves the Company has a 14.4 (2007 – 13.7) year reserve life and if
proved and probable are used the reserve life increases to 18.7 (2007 – 17.4) years. These figures are some of the longest
reserve life indexes (excluding oil sands) in the Canadian oil and gas industry.
INCOME TAxES
On November 12, 2008, Bonterra Energy Income Trust converted to a corporation. Due to the conversion and the
acquisition of Silverwing, the Company increased its usable tax pools to approximately $468,000,000 (see below). As
a result of the reorganization, the Company has recorded a future income tax asset and a corresponding deferred tax
credit. These amounts will be amortized into future tax expense as the associated tax pools are consumed.
The current tax provision relates to resource surcharge payable by the Company to the Province of Saskatchewan.
The surcharge is calculated as a flat percent of revenues generated from the sale of petroleum products produced in
Saskatchewan. The provincial government of Saskatchewan reduced the resource surcharge rate from 3.1 percent to
3.0 percent on July 1, 2008.
8. prOpErTY AND EQUIpMENT
($000)
Undeveloped land
Petroleum and natural gas properties
and related equipment
Furniture, equipment and other
9. DUE TO rELATED pArTY
2008
2007
Accumulated
Depletion and
Depreciation
Cost
Accumulated
Depletion and
Depreciation
Cost
$
2,295 $
– $
316 $
–
229,136
1,254
74,844
848
185,947
1,025
$
232,685 $
75,692 $
187,288 $
61,105
700
61,805
As of December 31, 2008, the Company’s CEO and major shareholder has loaned the Company $6,000,000. The loan
is unsecured, bears interest at Canadian chartered bank prime less one half of a percent and has no set repayment
terms. The loan can only be repaid should the Company have sufficient available borrowing limits under the Company’s
credit facility.
Interest paid on this loan during 2008 was $7,000.
Please refer to note 15 for additional related party transactions.
10. BANk DEBT
Due to the corporate reorganization and acquisition of Silverwing, the Company amended its bank facility to consist of an
$80,000,000 syndicated revolving credit facility and a $20,000,000 non-syndicated demand credit facility (December 31,
2007 - $69,900,000) (non-syndicated demand facility). Amounts drawn under these facilities at December 31, 2008 were
$93,235,000 (December 31, 2007 - $57,422,000). The interest rates on the outstanding debt as of December 31, 2008 were
4.35 percent and 3.49 percent on the Company’s Canadian prime rate loan (short-term debt) and Bankers’ Acceptances
(long-term debt), respectively. The terms of the syndicated revolving credit facility provide that the loan is revolving to
May 30, 2010 and is subject to annual review. The revolving credit facility has no fixed payment requirements. The terms
of the non-syndicated demand credit facility provide that the loan is due on demand and is subject to annual review and
has no fixed repayment terms.
The amount available for borrowing under the credit facilities is reduced by outstanding letters of credit. Letters of credit
totaling $525,000 were issued at December 31, 2008 (December 31, 2007 - $355,000). Of the letters of credit, $20,000
is secured by a restricted term deposit. Security for the credit facilities consists of various fixed and floating demand
debentures totaling $200,000,000 over all of the Company’s assets, and a general security agreement with first ranking
over all personal and real property.
The interest rate on the credit facilities is calculated as follows:
Consolidated Total Funded
Debt (1) to Consolidated
Cash flow ratio
Level I
Level II
Level III
Level IV
Level V
Level VI
Below
0.50:1
Over 0.5:1
to 1.0:1
Over 1.0:1
to 1.5:1
Over 1.5:1
to 2.0:1
Over 2.0:1
to 2.5:1
Over 2.5:1
Canadian Prime Rate Plus (2)
Bankers’ Acceptances Rate Plus (2)
50
150
75
175
85
185
100
200
125
225
150
250
(1) Consolidated total funded debt excludes related party amounts but includes working capital.
(2) Numbers in table represent basis points.
Consolidated total funded debt to consolidated cash flow ratio shall be adjusted effective as of the first day of the third
month following the end of each fiscal quarter, except for the end of a fiscal year in respect of which the adjustment shall
be made effective as of the first day of the fifth month following the end of such fiscal year, with each such adjustment to
be effective until the next such adjustment:
10 BONTE R RA OIL & GAS LTD.
BON TERRA OI L & G AS LTD. 31
1
I
B
S
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
k
c
a
l
B
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
w
e
r
d
n
a
-
-
t
n
o
r
F
2
8
1
:
5
4
:
5
1
6
2
-
3
0
-
9
0
r
o
t
c
e
f
r
e
P
a
r
r
e
t
n
o
B
_
2
9
4
0
2
0
9
2
The following is a list of the material covenants:
• The Company as of December 31, 2008 is required to not exceed $100,000,000 in consolidated debt (includes
negative working capital but excludes debt to related parties).
• Dividends paid in any quarter shall not exceed 80 percent of the average previous four quarters cash flow as
defined under GAAP.
11. INCOME TAXES
The Company has recorded a future income tax asset related to assets and liabilities and related tax amounts:
($000)
Future tax liability related to investments:
Future tax liability related to property and equipment:
Future tax asset related to asset retirement obiligations:
Future tax asset related to finance costs:
Future tax asset related to corporate tax losses and SR&ED claims
Future tax asset (Liability) – Long-term
Current portion of future income tax asset related
to corporate tax losses and SR&ED claims:
Future income tax asset related to current portion of derivative liability
Future Tax Asset - Current
2008
(212) $
(7,097)
4,593
1,134 $
86,998
85,416 $
2,669 $
–
2,669 $
2007
(448)
(14,828)
3,759
79
3,843
(7,595)
–
913
913
$
$
$
$
$
As a result of the reorganization the Company recorded a deferred credit of $71,303,000 relating to the difference
between the future income tax asset generated on the reorganization and the amount of the cash payment made to SRX
immediately before the reorganization. This credit is being amortized (2008 - $4,240,000) on the same basis as the related
future income tax asset (2008 - $4,909,000).
A reconciliation of the deferred credit is as follows:
Amount recorded on reorganization
Amortized in current year
Balance as of December 31, 2008
Current portion
Long-term portion
$
71,303,000
(4,240,000)
$
67,063,000
$
2,305,000
64,758,000
$
67,063,000
Income tax expense varies from the amounts that would be computed by applying Canadian federal and provincial
income tax rates as follows:
($000)
Earnings before income taxes
Combined federal and provincial income tax rates
Income tax provision calculated using statutory tax rates
Increase (decrease) in taxes resulting from:
Saskatchewan resource surcharge
Stock-based compensation
Change in effective tax rate
Trust income allocated to Unitholders prior to conversion
Others
$
2008
58,014 $
29.62%
17,184
437
357
(4,739)
(10,291)
(360)
Income tax expense
$
2,588 $
2007
33,434
32.27%
10,789
512
366
4,076
(13,176)
517
3,084
Bank debt at December 31, 2008 was $93,235,000 (December 31, 2007 - $57,422,000). The Company’s banking
arrangements allow it to use Bankers Acceptances (BA’s) as part of its loan facility. Interest charges on BA’s are generally
one half percent lower than that charged on the general loan account. The interest rate on the credit facilities is calculated
as follows:
Consolidated Total Funded
Debt (1) to Consolidated
Cash flow ratio
Level I
Level II
Level III
Level IV
Level V
Level VI
Below
Over 0.5:1
Over 1.0:1
Over 1.5:1
Over 2.0:1
0.50:1
to 1.0:1
to 1.5:1
to 2.0:1
to 2.5:1
Over 2.5:1
Canadian Prime Rate Plus
Bankers’ Acceptances Rate Plus
50
150
75
175
85
185
100
200
125
225
150
250
(1) Consolidated total funded debt excludes related party amounts but includes working capital.
Consolidated total funded debt to consolidated cash flow ratio shall be adjusted effective as of the first day of the third
month following the end of each fiscal quarter, except for the end of a fiscal year in respect of which the adjustment shall
be made effective as of the first day of the fifth month following the end of such fiscal year, with each such adjustment to
be effective until the next such adjustment.
rEOrGANIzATION COSTS
Based on current accounting rules, costs associated with the Trust’s reorganization into Bonterra Oil and Gas Ltd. must be
expensed. The costs consist of a $1,000,000 finders fee paid to a company that facilitated the reorganization, $931,000 of
professional fees, $150,000 stock exchange fees and $40,000 of costs associated with the distribution of the reorganization
document. These costs are all one time costs and no further costs are anticipated by the Company in direct relation to the
reorganization. Of these total costs of $2,121,000, the Company expensed $1,369,000 in the fourth quarter of 2008 and
$752,000 was expensed in the third quarter of 2008.
STOCk-BASED COMpENSATION
Stock-based compensation is a statistically calculated value representing the estimated expense of issuing employee
stock options. The Company records a compensation expense over the vesting period based on the fair value of options
granted to employees, directors and consultants. Due to the reorganization, all existing employee unit options vested
and were either exercised or were cancelled. This resulted in approximately an additional $195,000 of stock-based
compensation being recorded in the fourth quarter on the automatic vesting of outstanding options. Also the Company
issued 1,390,500 stock options during 2008 resulting in a further expense of $97,000.
The 1,390,500 common share options were issued at the end of November 2008 with an exercise price of $20.50 per share
and a fair value of $1.11 per option. The fair value of the options granted has been estimated using the Black-Scholes
option pricing model, assuming a weighted risk free interest rate of 2.2 percent (2007 – 4.7 percent), expected weighted
average volatility of 31 percent (2007 – 27 percent), expected weighted average life of 3.5 years (2007 – 2.3 years) and an
annual dividend/distribution rate based on the dividends paid to the Shareholders/Unitholders during the year. The future
stock-based compensation impact of these options is approximately $225,000 per quarter over the next four quarters.
DEpLETION, DEprECIATION, ACCrETION AND DrY hOLE COSTS
The Company follows the successful efforts method of accounting for petroleum and natural gas exploration and
development costs. Under this method, the costs associated with dry holes are charged to operations. For intangible
capital costs that result in the addition of reserves, the Company depletes its oil and natural gas intangible assets using
the unit-of-production basis by field.
For tangible assets such as well equipment, a life span of ten years is estimated and the related tangible costs are
depreciated at one tenth of original cost per year. The use of a ten year life span instead of calculating depreciation over
the life of reserves was determined to be more representative of actual costs of tangible property. Given the Company’s
long production life, wells generally require replacement of tangible assets more than once during their life time. Most of
the Company’s wells have been producing since the 1960’s and are expected to continue to produce for at least another
twenty years.
32 BONT ERRA OIL & GAS LT D.
BONTERRA OIL & GAS LTD. 9
The Company’s only significant general and administrative costs are employee compensation and professional services
such as legal, engineering and accounting. Employee compensation expense increased by approximately 29 percent
($856,000). The increase is due primarily to the Company’s bonus plan which resulted in additional employee compensation
of $610,000 (20.7 percent) with the remainder due to increased staffing levels (3.8 percent) and 2008 salary increases
(4.5 percent). The Company’s bonus plan consists of cash payments equal to three percent of before tax net earnings to
be paid to employees and key consultants based on performance throughout the year.
Costs associated with professional services increased by approximately $90,000. Increases in other general and
administrative areas have been offset by increased administration recovery charges to capital programs.
The quarter over quarter decrease was primarily due to a lower bonus accrual but was almost fully offset by increased
professional fees related to the internal control review and costs related to managing the integration of the Silverwing
acquisition and reorganization.
INTErEST ExpENSE
($ 000)
Interest Expense
Three months ended
Twelve months ended
December September December
December
December
31, 2008
30, 2008
31, 2007
31, 2008
31, 2007
746
545
878
2,740
3,028
The decrease in interest expense in 2008 as compared to 2007 was due to much lower borrowing costs, offset partially
by increased loan balances resulting from the Company’s acquisition of Silverwing and its reorganization. Interest
rates during the year on the outstanding debt averaged approximately 4.5 percent (2007 - 5.9 percent). The Company
maintained an average outstanding debt balance of approximately $60,600,000 (2007 - $51,600,000). Total debt (including
negative working capital) as of December 31, 2008 represents approximately 17.9 months of 2008 annual cash flow from
operations or 30.1 months based on annualized 2008 fourth quarter cash flow from operations. The ratio of bank debt
only as of December 31, 2008 based on the annualized 2008 Q4 base was 27.1 months. Also in the fourth quarter of 2008
the Company had one time reorganization costs of approximately $1,369,000 reducing cash flow to $10,336,000 from
approximately $11,700,000. This one item has significant implications on the ratio of bank debt to cash flow and would
reduce the Q4 numbers of 30.1 to 26.6 and 27.1 to 23.9 months.
working capital of $28,995,000. In addition, the Trust underwent a reorganization resulting in a cash outlay of $11,257,000
plus reorganization costs of $2,121,000. The Company also experienced a decrease in cash flow due to the rather significant
drop in commodity prices during the final four months of 2008.
The Company ended 2008 with a debt to cash flow ratio that is higher than usual even though it is in a range that is
normal with its peers at the present time. The main reason for the higher debt level is that early in the third quarter of
2008, when the Company announced its reorganization and Silverwing acquisition, it had share options outstanding that
were well in the money for approximately $25 million. At closing of the reorganization on November 12, 2008, the world
economy had changed substantially resulting in large reductions in share prices, including Bonterra’s and the majority of
the outstanding options not being exercised. The debt level is still very manageable for Bonterra but plans for 2009 are
to reduce the debt to equity ratio that presently exceeds 2:1.
The Company and its subsidiaries have the following tax pools, which may be used to reduce taxable income in future
years, limited to the applicable rates of utilization:
($000)
Undepreciated capital costs
Eligible capital expenditures
Share issue costs
Canadian oil and gas property expenditures
Canadian development expenditures
Canadian exploration expenditures
SR&ED expenditures
Income tax losses carried forward (1)
Rate of
Utilization %
20-100 $
7
20
10
30
100
100
100
Amount
23,696
1,870
4,581
25,072
50,743
10,530
80,357
271,029
$
467,878
(1)
Income tax losses carried forward expire in the following years; 2014 - $1,069,000, 2025 - $3,179,000, 2026 - $109,244,000,
2027 - $116,787,000, 2028 - $40,750,000.
The Company has $27,670,000 of investment tax credits (ITC) that expire in the following years; 2009 - $3,469,000, 2010 -
$3,059,000, 2011 - $4,667,000, 2012 - $3,909,000, 2013 - $3,155,000, 2014 - $1,995,000, 2015 - $2,257,000, 2016 - $2,405,000,
2017 - $2,009,000, 2018 - $745,000.
The amount and timing of reversals of temporary differences will also depend on the Company’s future operating results,
acquisitions and dispositions of assets and liabilities, and distrubution policy. A significant change in any of the preceding
assumptions could materially affect the Company’s estimate of the future income tax asset.
12. ASSET rETIrEMENT OBLIGATIONS
At December 31, 2008, the estimated total undiscounted amount required to settle the asset retirement obligations was
$58,903,000 (2007 - $54,622,000). Costs for asset retirement have been calculated assuming a two percent inflation rate.
These obligations will be settled based on the useful lives of the underlying assets, which extend up to 50 years into the
future. This amount has been discounted using a credit-adjusted risk-free interest rate of five percent (2007 – five percent).
During the year the Company acquired Silverwing a public oil and gas producer for cash consideration including negative
Changes to asset retirement obligations were as follows:
($000)
Asset retirement obligations, January 1
Adjustment to asset retirement obligations
Adjustment related to asset additions (net of disposals)
Liabilities settled during the year
Accretion
$
2008
14,904 $
(217)
5,929
(3,063)
785
Asset retirement obligations, December 31
$
18,338 $
2007
14,819
(399)
563
(820)
741
14,904
13. ShArEhOLDErS’ EQUITY
Authorized
The Company is authorized to issue an unlimited number of common shares without nominal or par value.
($000)
Issued
Common Shares
Balance, beginning of year
Issued on reorganization to a corporation
Balance, end of year
2008
2007
Number
Amount
Number
Amount
– $
17,257,603
17,257,603 $
–
99,530
99,530
– $
–
– $
–
–
–
8 B ONTE RR A OIL & GAS LTD.
BON TERRA OI L & G AS LTD. 33
2
9
0
2
0
4
9
2
_
B
o
n
t
e
r
r
a
P
e
r
f
e
c
t
o
r
0
9
-
0
3
-
2
6
1
5
:
4
5
:
1
8
2
F
r
o
n
t
-
-
a
n
d
r
e
w
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
B
l
a
c
k
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
S
B
I
1
2
9
0
2
0
4
9
2
_
B
o
n
t
e
r
r
a
P
e
r
f
e
c
t
o
r
0
9
-
0
3
-
2
6
1
5
:
4
5
:
1
9
2
B
a
c
k
-
-
a
n
d
r
e
w
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
B
l
a
c
k
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
S
B
I
1
($000)
Issued
Trust Units
Balance, beginning of year
Transfer of contributed surplus to unit capital
Issued pursuant to Trust unit option plan
Issued on acquisition of Silverwing
Cancelled on conversion to a corporation
Balance, end of year
2008
2007
New Alberta Crown royalty Framework (NrF)
Number
Amount
Number
Amount
16,928,158 $
–
321,700
7,745
(17,257,603)
90,590
805
7,935
200
(99,530)
16,874,658 $
–
53,500
–
–
– $
–
16,928,158 $
89,488
109
993
–
–
90,590
The Company is authorized to issue an unlimited number of Class “A” redeemable Preferred Shares and an unlimited
number of Class “B” Preferred Shares. There are currently no outstanding Class “A” redeemable preferred shares or
Class “B” preferred shares.
The number of common shares (formerly trust units) used to calculate diluted net earnings per share (formerly per unit) for
the year ended December 31, 2008 of 17,119,517 shares (2007 – 16,942,036 Units) included the basic weighted average
number of common shares outstanding of 17,075,647 shares (2007 – 16,908,266 Units) plus 43,870 shares (2007 – 33,770
Units) related to the dilutive effect of common share options.
A summary of the changes of the Company’s contributed surplus is presented below:
Contributed surplus
($000)
Balance, beginning of year
Stock-based compensation expensed (non-cash)
Stock-based options exercised (non-cash)
Balance, end of year
The deficit balance is composed of the following items:
($000)
Accumulated earnings
Accumulated cash dividends and distributions
Deficit
2008
2,140 $
1,207
(805)
2,542 $
2007
1,116
1,133
(109)
2,140
2008
208,182 $
(254,897)
(46,715) $
2007
152,756
(204,299)
(51,543)
$
$
$
$
The Company provides an option plan for its directors, officers, employees and consultants. Under the plan, the
Company may grant options for up to 1,725,760 common shares (2007 – 1,692,800 Trust Units). The exercise price of each
option granted equals the market price of the common shares on the date of grant and the option’s maximum term is
five years.
A summary of the status of the Company’s stock option plan as of December 31, 2008 and changes during the year is
presented below:
Outstanding at beginning of year
Options granted
Outstanding at end of year
Options exercisable at end of year
2008
weighted-
Average
Exercise price
Options
– $
1,390,500
1,390,500 $
– $
–
20.50
20.50
–
Royalty rates in the fourth quarter averaged approximately 13.4 percent; slightly higher than preceding quarters. The
NRF rates vary by prices as well as productivity levels. With the current low prices the new royalty rates should result in
a significant reduction in the amount the Company will pay to the Province of Alberta. This combined with the Silvering
acquisition (mostly BC production with lower Crown royalty rates) should result in a lower average Crown royalty rate for
the Company in 2009.
The effect of the NRF on the Company’s oil and liquid reserves was a reduction of 77,200 barrels for proved and a
reduction of 132,800 barrels for proved plus probable reserves. For natural gas, the NRF accounted for a reduction of
56,500 MCF for proved and 128,800 MCF for proved plus probable reserves. On a BOE basis, this reduction represented
approximately 0.6 percent of the Company gross reserves on a proved plus probable basis.
prODUCTION COSTS
($ 000)
Production costs
$ per BOE
Three months ended
Twelve months ended
December September December
December
December
31, 2008
30, 2008
31, 2007
31, 2008
31, 2007
6,859
16.25
6,148
15.84
5,535
14.01
25,413
15.98
24,073
15.64
Barrels of oil equivalent (BOE) are calculated using a conversion ratio of 6 MCF to 1 barrel of oil. The conversion is based
on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead and as such may be misleading if used in isolation. Operating costs on the Company’s newly
acquired British Columbia (BC) properties as well as on the newly drilled wells are lower on a BOE basis than on its older
low productivity wells and this may result in lower operating costs per BOE in the future.
Operating costs increased slightly in the fourth quarter of 2008 compared to the prior quarter due primarily to the acquisition
of Silverwing and from new wells put on production in the fourth quarter of 2008 and large industry wide increases
for oilfield services especially for oil producing properties. Average production costs per BOE increased marginally in
Q408 compared with the previous quarter due mainly to winterization programs performed on the Company’s wells
As discussed above, Bonterra’s production comes primarily from low productivity wells. These wells generally result in
higher operating costs on a per unit-of-production basis as costs such as municipal taxes, surface leases, power and
personnel costs are not variable with production volumes. The Company is continually examining ways to reduce
With the acquisition of Silverwing and the Company’s recent drilling success and expected declines in oilfield service
costs, the Company anticipates operating costs in the $14 to $15 per BOE range for 2009. The higher operating costs
for the Company are substantially offset by lower royalty rates and results in higher cash net backs on a combined basis
despite higher than average operating costs.
GENErAL AND ADMINISTrATIvE ExpENSE
Three months ended
Twelve months ended
December September December
December
December
31, 2008
30, 2008
31, 2007
31, 2008
31, 2007
824
1.95
845
2.18
739
1.69
3,401
2.14
2,603
1.69
and facilities.
operating costs.
($ 000)
G&A Expense
$ per BOE
General and administrative (G&A) expenses increased 31 percent in 2008 compared to 2007. The Company provides
administrative services to Comaplex Minerals Corp. (Comaplex) and Pine Cliff Energy Ltd. (Pine Cliff), companies that
share common directors and management. Please refer to discussion under Related Party Transactions for details.
34 BONTERRA OIL & GAS LTD.
BONTERRA OIL & GAS LTD. 7
Number Weighted-Average
Oustanding
At 12/31/08
1,390,500
Range of
Exercise
Prices
$20.50
3.9 years
$
20.50
–
$
–
Remaining Weighted-Average
Exercise Price
Contractual Life
Number
Exercisable Weighted-Average
At 12/31/08
Exercise Price
As at December 31, 2008, Bonterra had only one gross (0.25 net) Cardium oil well, no natural gas wells, three gross
The following table summarizes information about stock options outstanding at December 31, 2008:
Options Outstanding
Options Exercisable
(2.5 net) coalbed methane (CBM) wells with assigned reserves and three gross (2.9 net) Shaunavon oil wells drilled but
not on production. Subsequent to December 31, 2008 and up to the date of this report, the Company has put all of its oil
wells on production. The timing for the tie-in of the CBM wells has not yet been determined.
rEvENUE
(Cdn $)
Average Realized Prices:
Crude oil and NGLs (per barrel)
Natural gas (per MCF)
Revenue – oil and gas sales (000’s) - cash
22,613
34,226
26,573
121,730
96,431
Three months ended
Twelve months ended
December September December
December
December
31, 2008
30, 2008
31, 2007
31, 2008
31, 2007
58.91
7.00
103.36
8.20
77.60
6.70
87.54
8.21
70.31
6.75
Revenue from petroleum and natural gas sales increased 26 percent in 2008 compared to 2007 due to increased production
volumes and an increase in the average price received for crude oil, natural gas liquids and natural gas. The fourth quarter
of 2008 saw a substantial decrease in realized revenues over the third quarter of 2008 due to the significant decrease in
commodity prices.
Included in revenue is a risk management loss of $7,353,000 (2007 – gain of $621,000) due to lower prices received as a
result of commodity risk management agreements. The Company may continue to hedge future production to assist in
managing its cash flow. As at December 31, 2008, the Company had no outstanding risk management agreements. The
value of the outstanding commodity hedging contracts as of December 31, 2007 was a net liability of $3,085,000.
rOYALTIES
($ 000)
Crown royalties
Freehold royalties, gross overriding
royalties and net carried interests
Total royalty expense
Three months ended
Twelve months ended
December September December
December
December
31, 2008
30, 2008
31, 2007
31, 2008
31, 2007
2,337
3,523
2,634
13,736
9,209
558
2,895
1,134
4,657
682
3,316
3,479
17,215
3,235
12,444
Royalties paid by the Company consist primarily of Crown royalties paid to the Provinces of Alberta, Saskatchewan and
British Columbia. The majority of the Company’s wells are low productivity wells and therefore have low Crown royalty
rates. The Company’s average Crown royalty rate was approximately 10.6 percent (2007 – 10 percent) and approximately
2.7 percent (2007 – 3 percent) for other royalties before hedging adjustments.
During 2007, the Company was advised by the owner of a gross overriding royalty that a production limit was attained
that resulted in an additional gross overriding royalty in respect of certain of its Cardium oil wells. The production limit
was triggered by a calculation on a multitude of Cardium wells including many that were not owned by the Company.
determined. In discussions with the payee it was determined that the production limit was reached in late 2005. The
royalty was calculated based on this agreed date and the affected wells for the Company and other operators in the
area were identified. The approximate amount of the adjustment, net to the Company was $570,000 for periods prior to
January 1, 2007. This amount has been included in the 2007 royalty numbers.
Also in 2007 the Company was informed by the operator of its former Dodsland property that it had not been charged a
net profit royalty for the years 2004, 2005 and 2006. In reviewing the agreements it was confirmed the claim was accurate
and an amount of approximately $150,000 was paid by the Company in 2007 for the net profit royalty. This was also
expensed in 2007.
A summary of the former unit option plan as of December 31, 2008 and 2007, and changes during the years is
presented below:
Outstanding at beginning of year
Options granted
Options exercised
Options cancelled
Outstanding at end of year
Options exercisable at end of year
2008
weighted-
Average
Exercise price
Options
2007
Weighted-
Average
Options
Exercise Price
1,177,000 $
29,000
(321,700)
(884,300)
– $
– $
27.59
39.09
24.66
29.03
–
–
721,500 $
553,000
(53,500)
(44,000)
1,177,000 $
530,000 $
26.55
28.11
18.56
27.92
27.59
26.63
The Company records compensation expense over the vesting period based on the fair value of options granted to
employees, directors and consultants. The Company granted 1,390,500 stock options with an estimated fair value of
$1,548,000 ($1.11 per option) using the Black-Scholes option pricing model with the following key assumptions:
2008
2007
Weighted-average risk free interest rate (%)
Expected life (years)
Weighted-average volatility (%)
Dividend yield 2008 and 2007
4.7
2.3
27.2
based on the percentage of dividends or distributions paid during the year
2.2
3.5
31.3
In addition the exact wells that the production limit was applicable to was not readily known by the Company nor easily
($000)
Unrealized gains on available for
sale financial assets
Unrealized gains and losses on derivatives
designated as cash flow hedges
($000)
Unrealized gains (losses) on available for
sale financial assets
Other
January 1, Comprehensive December 31,
2008
Income (Loss)
2008
$
3,031 $
(1,611) $
1,420
Other
January 1, Comprehensive December 31,
2007
Income (Loss)
2007
$
1,566 $
1,465 $
814
$
2,380
$
(814)
651 $
3,031
–
3,031
14. ACCUMULATED OThEr COMprEhENSIvE INCOME
6 B ONTE RR A OIL & GAS LTD.
BON TERRA OI L & G AS LTD. 35
2
9
0
2
0
4
9
2
_
B
o
n
t
e
r
r
a
P
e
r
f
e
c
t
o
r
0
9
-
0
3
-
2
6
1
5
:
4
5
:
1
9
2
B
a
c
k
-
-
a
n
d
r
e
w
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
B
l
a
c
k
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
S
B
I
1
2
9
0
2
0
4
9
2
_
B
o
n
t
e
r
r
a
P
e
r
f
e
c
t
o
r
0
9
-
0
3
-
2
6
1
5
:
4
5
:
1
8
2
F
r
o
n
t
-
-
a
n
d
r
e
w
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
B
l
a
c
k
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
S
B
I
1
15. rELATED pArTY TrANSACTIONS
The Company received a management fee from Comaplex of $330,000 (2007 - $300,000) for management services and
office administration. This fee has been included as a recovery in general and administrative expenses and represents the
fair value of the services rendered.
In order to facilitate the acquisition of Silverwing, the Company borrowed on a short-term basis $20,000,000 from Comaplex
to allow time to finalize documentation for its new bank line of credit. The funds were repaid on November 21, 2008. Total
interest paid on the loan was $21,000.
As at December 31, 2008, the Company had an account receivable from Comaplex of $56,000 (December 31, 2007 - $63,000).
The Company received a management fee from Pine Cliff Energy Ltd., a company with common directors and management
with the Company and its subsidiaries, of $238,000 (2007 - $216,000) for management services and office administration.
This fee has been included in general and administrative expenses as a recovery and represents the fair value of the
services rendered.
As at December 31, 2008 the Company had an account receivable from Pine Cliff of $1,000 (December 31, 2007 - $4,000).
($000)
Restricted cash
Future income tax benefit
Property and equipment
Working capital deficiency
Asset retirement obligations
($000)
Accounts receivable
Prepaids
Accounts payable
16. FINANCIAL AND CApITAL rISk MANAGEMENT
INTErNAL CONTrOL ChANGES
Silverwing
1,252
18,325
15,347
(14,979)
(5,929)
14,016
SRX
2,158
1,701
3,859
Nil
$
$
$
$
Financial risk Factors
The Company undertakes transactions in a range of financial instruments including:
• Receivables
• Payables
• Common share investments
• Bank loans
• Derivatives
The Company’s activities result in exposure to a number of financial risks including market risk (commodity price risk,
interest rate risk, foreign exchange risk, credit risk, and liquidity risk).
The Company’s overall risk management program seeks to mitigate these risks and reduce the volatility on the Company’s
financial performance. Financial risk management is carried out by senior management under the direction of the Directors
of the Company.
The Company enters into various risk management contracts in accordance with Board approval to manage the Company’s
exposure to commodity price fluctuations. Currently no risk management agreements are in place in respect of interest
rate risk. The Company does not speculatively trade in risk management contracts. The Company’s risk management
contracts are entered into to manage the risks relating to commodity prices from its business activities.
Capital risk Management
The Company’s objectives when managing capital are to safeguard the Company’s ability to continue as a going concern,
so that it can continue to provide returns to its shareholders and benefits for other stakeholders and to maintain an
optimal capital structure to reduce the cost of capital. In order to maintain or adjust the capital structure, the Company
may adjust the amount of dividends, the percentage of return of capital or issue new shares.
The Company monitors capital on the basis of the ratio of debt to cash flow. During the year the Company acquired
Silverwing, a public oil and gas producer for cash consideration including negative working capital of $28,795,000. In
addition, the Trust underwent a reorganization resulting in a cash outlay of $11,257,000 plus reorganization costs of
$2,121,000. The Company has also experienced a decrease in cash flow due to the rather significant drop in commodity
prices during the final four months of 2008.
The Company is required to comply with Multilateral Instrument 52-109 “Certification of Disclosure in Issuers’ Annual and
Interim Filings”, otherwise referred to as Canadian SOX (C-Sox). The 2008 certificate requires that the Company disclose
in the MD&A any changes in the Company’s internal control over financial reporting that occurred during the period that
has materially affected, or is reasonably likely to materially affect the Company’s internal control over financial reporting.
The Company confirms that no such changes were made to the internal controls over financial reporting during 2008.
prODUCTION
Crude oil and NGLs (barrels per day)
Natural gas (MCF per day)
Average BOE per day
Three months ended
Twelve months ended
December September December
December
December
31, 2008
30, 2008
31, 2007
31, 2008
31, 2007
3,105
8,892
4,587
3,013
7,233
4,219
3,098
7,176
4,295
3,073
7,637
4,346
3,113
6,627
4,218
Bonterra’s 2008 average production increased three percent on a per BOE basis. Crude oil production decreased by
approximately 1.3 percent while gas production increased by approximately 15.2 percent. The decreased crude oil
production was due to the timing of Bonterra’s 2008 development program in which production came on late in the year
and therefore contributed little to 2008 and the 2007 property swap where the Company exchanged its predominantly
Saskatchewan oil property for additional production in the Pembina area which had higher natural gas production. The
natural gas increase was due to a combination of the successful 2008 development program, the acquisition of Silverwing
on November 12, 2008 and the above mentioned property swap.
The Company’s fourth quarter production in 2008 saw increases in crude oil (92 barrels per day) and natural gas
(1,659 MCF per day) production over Q308 production due to the commencement of production from new wells drilled
as well as the completion of the Silverwing acquisition. The Silverwing acquisition, which closed on November 12, 2008
added approximately 650 BOE per day, mainly natural gas. The Company’s average production volume for December
was approximately 4,950 BOE per day.
Bonterra’s overall annual decline rate for 2008 was approximately 8.5 percent. The Company was able to more than offset
this decline with its 2008 drill program. Bonterra, along with its partners, drilled 33 gross (22.9 net) Cardium oil wells. This
includes 26 gross and 21.9 net Cardium wells drilled directly by the Company. Also the Company drilled 7 gross (5 net)
shallow gas wells in 2008 in the Pembina field and 3 gross (2.9 net) Shaunavon oil wells. The Company also participated in
one (0.1 net) Cardium natural gas well drilled by one of its partners. Bonterra recorded a 100 percent success rate with its
2008 drilling program. The majority of the wells were drilled in the fourth quarter; 14 (10.2 net) Cardium oil wells, 7 gross
(5 net) shallow Pembina gas wells and all three (2.9 net) of the Shaunavon oil wells. The closing date for the Silverwing
acquisition was November 12, 2008 and therefore contributed little to production rates for the full year.
36 BONTERRA OIL & GAS LTD.
BONTERRA OIL & GAS LTD. 5
2
9
0
2
0
4
9
2
_
B
o
n
t
e
r
r
a
S
h
e
e
t
w
i
s
e
0
9
-
0
3
-
2
6
1
5
:
4
5
:
1
8
1
B
a
c
k
-
-
a
n
d
r
e
w
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
B
l
a
c
k
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
M
Y
C
M
C
Y
C
M
Y
B
C
M
Y
Y
7
0
C
M
Y
B
C
M
Y
M
Y
C
M
Y
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
s
l
u
r
C
C
M
Y
B
C
M
Y
C
M
Y
B
C
M
Y
B
7
0
C
7
0
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
s
l
u
r
M
C
M
Y
B
C
M
Y
Y
7
0
C
M
Y
B
C
M
Y
s
l
u
r
Y
C
M
Y
B
C
M
Y
C
7
0
C
M
Y
B
C
M
Y
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
C
M
C
Y
C
M
Y
B
C
M
Y
Y
7
0
C
M
Y
B
C
M
Y
M
Y
C
M
Y
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
s
l
u
r
C
C
M
Y
B
C
M
Y
C
M
Y
B
C
M
Y
B
7
0
C
7
0
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
s
l
u
r
M
C
M
Y
B
C
M
Y
Y
7
0
C
M
Y
B
C
M
Y
s
l
u
r
Y
C
M
Y
B
P
r
i
n
e
c
t
4
G
S
i
F
o
r
m
a
t
1
0
2
/
1
0
5
D
i
p
c
o
3
.
0
e
(
p
d
f
)
©
2
0
0
7
H
e
i
d
e
l
b
e
r
g
e
r
D
r
u
c
k
m
a
s
c
h
i
n
e
n
A
G
While Bonterra believes it has adequate DC&P in place, lapses in the disclosure controls and procedures could occur
and/or mistakes could happen. Should such occur, the Company intends to take whatever steps it deems necessary to
The following section (a) of this note provides a summary of the Company’s underlying economic positions as represented
by the carrying values, fair values and contractual face values of the Company’s financial assets and financial liabilities.
1. pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and
The carrying amounts, fair value and face values of the Company’s financial assets and liabilities are shown in Table 1.
The Company’s debt to cash flow from operations is also provided.
The following section (b) addresses in more detail the key financial risk factors that arise from the Company’s activities
including its policies for managing these risks.
The following section (c) provides details of the Company’s risk management contracts that are used for financial
risk management.
a) Financial assets, financial liabilities and debt ratio
Table 1
($000)
Financial assets
Restricted term deposit
Accounts receivable
Investment in related party
Financial liabilities
Accounts payable and
accrued liabilities
Due to related party
Short-term debt
Long-term debt
2. due to the limited number of staff, the Company relies upon third parties as participants in the Company’s internal
The net debt and cash flow from operations figures are presented in Table 2.
Table 2
($000)
Short-term debt
Long-term debt
Due to related party
Accounts payable and accrued liabilities
Current assets (1)
Net Debt
Cash flow from operations (2)
Net debt to cash flow from operations
As at December 31, 2008
Carrying
value
Fair
value
Face
value
20
11,753
2,131
20
11,753
2,131
20
11,838
N/A
23,888
6,000
13,325
79,910
23,888
6,000
13,325
79,910
23,888
6,000
13,325
79,910
December 31,
2008
13,325
79,910
6,000
23,888
(18,971)
104,152
69,570
1.50
minimize the consequences thereof.
Internal Controls Over Financial reporting
includes those policies and procedures that:
dispositions of the assets of the issuer;
Internal controls over financial reporting (ICFR) are defined in NI 52-109 as “… a process designed by, or under the
supervision of, an issuer’s certifying officers and effected by the issuer’s board of directors, management and other
personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with the issuer’s Generally Accepted Accounting Practices (GAAP) and
2. are designed to provide reasonable assurance that transactions are recorded as necessary to permit preparation
of financial statements in accordance with the issuer’s GAAP, and that receipts and expenditures of the issuer are
being made only in accordance with authorizations of management and directors of the issuer; and
3. are designed to provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use or disposition of the issuer’s assets that could have a material effect on the annual financial
statements or interim financial statements.”
The Company has conducted a review and evaluation of its ICFR, with the conclusion that as of December 31, 2008 the
Company’s system of ICFR as defined under NI 52-109 is adequately designed to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with
GAAP. The control framework the Company used to design and evaluate its ICFR was COSO. In its evaluation, the
Company identified certain material weaknesses in internal controls over financial reporting:
1. due to the limited number of staff at the Company, it is not feasible to achieve the complete segregation of
incompatible duties; and
controls over financial reporting.
The Company believes these weaknesses are mitigated by: the active involvement of senior management and the board
of directors in the affairs of the Company; open lines of communication within the Company; the present levels of activities
and transactions within the Company being readily transparent; the thorough review of the Company’s financial statements
by management, the board of directors and by the Company’s auditors (annual statements only); and the establishment of
a whistle-blower policy. However, these mitigating factors will not necessarily prevent a material misstatement occurring
as a result of the aforesaid weaknesses in the Company’s internal controls over financial reporting. A system of internal
controls over financial reporting, no matter how well conceived or operated, can provide only reasonable, not absolute,
assurance that the objectives of the internal controls over financial reporting are met. The Company has no plans for
remediating the above weaknesses.
Limitation on Scope of Design of DC&p and ICFr
The above design of DC&P and ICRF has been limited to exclude controls, policies and procedures of both Silverwing
Energy Inc. (Silverwing) and operations of SRX Post Holdings (SRX) prior to the reorganization of Bonterra Energy Income
Trust into the Company. The following tables summarize the information that has been included in the consolidated
financial statements of the Company.
(1) Current assets include restricted term deposit, accounts receivable, crude oil inventory, prepaid expenses and investment in related party.
(2) Cash flow from operations includes annual net earnings less adjustment for non-cash (gain) loss on risk management contracts, stock-
based compensation, depletion, depreciation and accretion, future income taxes, changes in non-cash working capital items and asset
retirement obligations settled.
4 B ONTE RR A OIL & GAS LTD.
BON TERRA OI L & G AS LTD. 37
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
k
c
a
l
B
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
w
e
r
d
n
a
-
-
t
n
o
r
F
1
8
1
:
5
4
:
5
1
6
2
-
3
0
-
9
0
e
s
i
w
t
e
e
h
S
a
r
r
e
t
n
o
B
_
2
9
4
0
2
0
9
2
G
A
n
e
n
i
h
c
s
a
m
k
c
u
r
D
r
e
g
r
e
b
l
e
d
i
e
H
7
0
0
2
©
)
f
d
p
(
e
0
.
3
o
c
p
i
D
5
0
1
/
2
0
1
t
a
m
r
o
F
i
S
G
4
t
c
e
n
i
r
P
B
Y
M
C
Y
r
u
l
s
Y
M
C
B
Y
M
C
0
7
Y
Y
M
C
B
Y
M
C
M
r
u
l
s
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
0
7
C
0
7
B
Y
M
C
B
Y
M
C
Y
M
C
B
Y
M
C
C
r
u
l
s
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
Y
M
C
Y
M
Y
M
C
B
Y
M
C
0
7
Y
Y
M
C
B
Y
M
C
Y
C
M
C
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
Y
M
C
B
Y
M
C
0
7
C
Y
M
C
B
Y
M
C
Y
r
u
l
s
Y
M
C
B
Y
M
C
0
7
Y
Y
M
C
B
Y
M
C
M
r
u
l
s
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
0
7
C
0
7
B
Y
M
C
B
Y
M
C
Y
M
C
B
Y
M
C
C
r
u
l
s
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
Y
M
C
Y
M
Y
M
C
B
Y
M
C
0
7
Y
Y
M
C
B
Y
M
C
Y
C
M
C
Y
M
b) Risks and mitigations
Market risk is the risk that the fair value or future cash flow of the Company’s financial instruments will fluctuate because of
changes in market prices. Components of market risk to which the Company is exposed are discussed below.
Commodity price risk
The Company’s principal operation is the production and sale of crude oil, natural gas and natural gas liquids. Fluctuations
in prices of these commodities directly impact the Company’s performance and ability to continue with its dividends.
The Company has used various risk management contracts to set price parameters for a portion of its production.
Management, in agreement with the Board of Directors, recently decided that at least in the near term it will discontinue
the use of commodity price agreements. The Company will assume full risk in respect of commodity prices.
Sensitivity Analysis
Commodity prices have fluctuated significantly over the recent past. The following table updates the cash flow sensitivity
for movements in the commodity prices of $1 U.S. per barrel WTI for crude oil, $0.10 per MCF AECO for natural gas and
$0.01 fluctuation in exchange rates.
($000)
U.S. $1.00 per barrel
Canadian $0.10 per MCF
Change of Canadian $0.01/U.S. $ exchange rate
Interest rate risk
Cash Flow
870,000
289,000
593,000
$
$
$
Interest rate risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument
will fluctuate due to changes in market interest rates. Interest rate risk arises from interest bearing financial assets and
liabilities that the Company uses. The principal exposure of the Company is on its bank borrowings which have a variable
interest rate which gives rise to a cash flow interest rate risk.
The Company’s debt consists of an $80,000,000 revolving operating line, $20,000,000 demand operating line and
$6,000,000 due to the Company’s CEO and major shareholder. The borrowings under these facilities are at bank prime
plus or minor various percentages as well as by means of banker acceptances (BA’s). The Company manages its exposure
to interest rate risk through entering into various term lengths on its BA’s but in no circumstances do the terms exceed
six months.
Sensitivity analysis
Based on historic movements and volatilities in the interest rate markets and management’s current assessment of the
financial markets, the Company believes that a one percent variation in the Canadian prime interest rate is reasonably
possible over a 12-month period. No income tax effect has been calculated as the Company has sufficient tax pools such
that it will not be taxable in the near future.
A one percent increase (decrease) in the Canadian prime rate would decrease cash flow by $992,000 (increase by
$992,000).
Foreign exchange risk
The Company has no foreign operations and currently sells all its product sales in Canadian currency. The Company
however is exposed to currency risk in that crude oil is priced in U.S. currency then converted to Canadian currency. The
Company currently has no outstanding risk management agreements. Management, in agreement with the Board of
Directors, recently decided that at least in the near term it will discontinue the use of commodity price agreements. The
Company will assume full risk in respect of foreign exchange fluctuations.
Credit risk
Credit risk is the risk that a contracting party will not complete its obligations under a financial instrument and cause the
Company to incur a financial loss. The Company is exposed to credit risk on all financial assets included on the balance
sheet. To help mitigate this risk:
• The Company only enters into material agreements with credit worthy counterparties. These include major oil and
gas companies or major Canadian chartered banks;
Financial ($000, except $ per unit)
Revenue – realized oil and gas sales
Cash flow from operations
Per Unit Basic
Per Unit Fully Diluted
Cash payments per share/unit (1)
Payout Ratio (1)
Net Earnings
Per Unit Basic
Per Unit Fully Diluted
Capital Expenditures and Acquisitions
Total Assets
Working Capital Deficiency
Long-term debt
Unitholders’ Equity
Operations
Oil and Liquids (barrels per day)
Natural Gas (MCF per day)
Total BOE per day
4th
3rd
2nd
1st
2007
26,573
13,369
0.79
0.79
0.66
84%
7,920
0.47
0.47
7,213
142,329
58,766
–
44,218
3,098
7,176
4,295
23,794
11,886
0.70
0.70
0.66
94%
9,086
0.54
0.53
2,763
138,140
50,041
–
50,820
3,054
6,196
4,086
23,462
13,413
0.79
0.79
0.66
84%
4,440
0.26
0.26
1,699
139,432
49,595
–
51,920
3,074
6,663
4,184
22,602
12,765
0.76
0.76
0.66
87%
8,904
0.53
0.53
7,625
140,926
49,288
–
57,646
3,227
6,470
4,305
(1) Cash payments per share/unit are based on payments made in respect of production months within the quarter.
Disclosure Controls and procedures
Disclosure controls and procedures (DC&P) are defined under National Instrument 52-109 – Certification of Disclosure
Controls in Issuers’ Annual and Interim Filings (NI 52-109) as “…controls and other procedures of an issuer that are
designed to provide reasonable assurance that information required to be disclosed by the issuer in its annual filings,
interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized
and reported within the time periods specified in the securities legislation and include controls and procedures designed
to ensure that information required to be disclosed by an issuer in its annual filings, interim filings or other reports filed
or submitted under securities legislation is accumulated and communicated to the issuer’s management, including its
certifying officers as appropriate to allow timely decisions regarding required disclosure.” The Company has conducted a
review and evaluation of its DC&P, with the conclusion that as at December 31, 2008 the Company has an effective system
of DC&P as defined under NI 52-109. In reaching this conclusion, the Company recognizes that two key factors must be
and are present:
requirements; and
1.
the Company is very dependent upon its advisors and consultants (principally its legal counsels) to assist in
recognizing, interpreting, understanding and complying with the various securities regulations disclosure
2.
the Company has an active Board and management with open lines of communications.
Bonterra has a small staff with varying degrees of knowledge concerning the various regulatory disclosure requirements.
In many circumstances, the various regulatory requirements are relatively new, subject to interpretation, and complex.
The Company is not of sufficient size to justify a separate department or one or more staff member specialists in this area.
Therefore the Company must rely upon its advisors/consultants to assist it and as such they form part of the disclosure
controls and procedures.
Proper disclosure necessitates that a person not only be aware of the pertinent disclosure requirements, but must also
be sufficiently involved in the affairs of the Company and/or receives the communication of information to assess any
necessary disclosure requirements. Accordingly, it is essential that there be proper communication among those people
who manage and govern the affairs of the Company, this being the Board of Directors and senior management. The
Company believes this communication exists.
38 BONTERRA OIL & GAS LTD.
BONTERRA OIL & GAS LTD. 3
ANNUAL COMpArISONS
Financial ($000, except $ per unit)
Revenue – realized oil and gas
Cash flow from operations
Per Share/Unit Basic
Per Share/Unit Fully Diluted
Cash payments per share/unit (1)
Payout Ratio (1)
Net Earnings
Per Share/Unit Basic
Per Share/Unit Fully Diluted
Capital Expenditures and Acquisitions
Total Assets
Working Capital Deficiency
Long-term Debt
Shareholders’/Unitholders’ Equity
Operations
Oil and Liquids (barrels per day)
Natural Gas (MCF per day)
Total BOE per day
QUArTErLY COMpArISONS
Financial ($000, except $ per unit)
Revenue – realized oil and gas sales
Cash flow from operations
Per Share/Unit Basic
Per Share/Unit Fully Diluted
Cash payments per share/unit (1)
Payout Ratio (1)
Net Earnings
Per Share/Unit Basic
Per Share/Unit Fully Diluted
Capital Expenditures and Acquisitions
Total Assets
Working Capital Deficiency
Long-term debt
Unitholders’ Equity
Operations
Oil and Liquids (barrels per day)
Natural Gas (MCF per day)
Total BOE per day
121,730
69,570
4.07
4.06
3.12
77%
55,426
3.25
3.23
45,407
265,301
23,878
79,910
56,777
3,073
7,637
4,346
34,226
22,492
1.31
1.30
0.96
73%
21,125
1.23
1.22
6,038
150,120
47,499
–
57,623
3,013
7,233
4,219
2008
96,431
51,433
3.04
3.04
2.64
87%
30,350
1.79
1.79
19,300
142,326
58,766
–
44,376
3,113
6,627
4,218
34,398
20,530
1.21
1.20
0.84
69%
12,912
0.76
0.75
2,543
153,247
57,148
–
46,612
3,024
7,272
4,236
88,734
51,944
3.10
3.08
2.82
91%
37,250
2.23
2.21
38,348
134,942
50,187
–
53,359
3,040
6,014
4,042
30,493
16,212
0.96
0.96
0.70
73%
10,804
0.64
0.64
6,421
150,169
57,810
–
48,136
3,153
7,139
4,343
22,613
10,336
0.59
0.59
0.62
105%
10,585
0.62
0.62
30,405
265,301
23,878
79,910
56,777
3,105
8,892
4,587
2008
2007
2006
•
Investments are generally only with companies that have common management with the Company.
• Agreements for product sales are primarily on 30 day renewal terms; and
Of the accounts receivable balance of December 31, 2008 ($11,753,000) and December 31, 2007 ($10,575,000) over
82 (2007 – 90) percent relates to product sales with international oil and gas companies, tax receivables from the Canadian
Government or risk contract payments from the Company’s principal banker.
The Company assesses quarterly, if there has been any impairment of the financial assets of the Company. During the year
ended December 31, 2008, there was no impairment provision required on any of the financial assets of the Company
due to historical success of collecting receivables. The Company does have a credit risk exposure as the majority of
the Company’s accounts receivable are with counterparties having similar characteristics. However, payments from the
Company’s largest accounts receivable counter parties have consistently been received within 30 days and the sales
agreements with these parties are cancellable with 30 days notice if payments are not received.
At December 31, 2008 approximately $99,000 or 0.8 percent of the Company’s total accounts receivable are aged over
120 days and considered past due. The majority of these accounts are due from various joint venture partners. The
Company actively monitors past due accounts and takes the necessary actions to expedite collection, which can include
withholding production or net paying when the accounts are with joint venture partners. Should the Company determine
that the ultimate collection of a receivable is in doubt, it will provide the necessary provision in its allowance for doubtful
accounts with a corresponding charge to earnings. If the Company subsequently determines an account is uncollectable,
the account is written off with a corresponding charge to the allowance account. The Company’s allowance for doubtful
accounts balance at December 31, 2008 is $85,000. There were no accounts written off during the year.
The carrying value of accounts receivable approximates their fair value due to the relatively short periods to maturity on
this instrument. The maximum exposure to credit risk is represented by the carrying amount on the balance sheet. There
are no material financial assets that the Company considers past due.
4th
3rd
2nd
1st
Liquidity risk
Liquidity risk includes the risk that, as a result of Company’s operational liquidity requirements:
• The Company will not have sufficient funds to settle a transaction on the due date;
• The Company will not have sufficient funds to continue with its dividends;
• The Company will be forced to sell assets at a value which is less than what they are worth; or
• The Company may be unable to settle or recover a financial asset at all.
To help reduce these risks the Company:
• Maintains a portfolio of high-quality, long reserve life oil and gas assets.
The Company has the following maturity schedule for its financial liabilities:
Payments Due By Period
($000)
Recognized on Financial
Statements
Less Than
One Year
1-3 Years
4-5 Years
Accounts payable and accrued liabilities
Due to related party
Short-term bank debt
Long-term bank debt
Office leases
Yes – Liability
Yes – Liability
Yes – Liability
Yes – Liability
No
Total
23,888
6,000
13,325
–
589
43,802
–
–
–
79,910
1,238
81,148
–
–
–
–
1,080
1,080
2 B ONTE RR A OIL & GAS LTD.
BON TERRA OI L & G AS LTD. 39
M
Y
C
M
C
Y
C
M
Y
B
C
M
Y
Y
7
0
C
M
Y
B
C
M
Y
M
Y
C
M
Y
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
s
l
u
r
C
C
M
Y
B
C
M
Y
C
M
Y
B
C
M
Y
B
7
0
C
7
0
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
s
l
u
r
M
C
M
Y
B
C
M
Y
Y
7
0
C
M
Y
B
C
M
Y
s
l
u
r
Y
C
M
Y
B
C
M
Y
C
7
0
C
M
Y
B
C
M
Y
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
C
M
C
Y
C
M
Y
B
C
M
Y
Y
7
0
C
M
Y
B
C
M
Y
M
Y
C
M
Y
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
s
l
u
r
C
C
M
Y
B
C
M
Y
C
M
Y
B
C
M
Y
B
7
0
C
7
0
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
s
l
u
r
M
C
M
Y
B
C
M
Y
Y
7
0
C
M
Y
B
C
M
Y
s
l
u
r
Y
C
M
Y
B
P
r
i
n
e
c
t
4
G
S
i
F
o
r
m
a
t
1
0
2
/
1
0
5
D
i
p
c
o
3
.
0
e
(
p
d
f
)
©
2
0
0
7
H
e
i
d
e
l
b
e
r
g
e
r
D
r
u
c
k
m
a
s
c
h
i
n
e
n
A
G
2
9
0
2
0
4
9
2
_
B
o
n
t
e
r
r
a
S
h
e
e
t
w
i
s
e
0
9
-
0
3
-
2
6
1
5
:
4
5
:
1
8
1
F
r
o
n
t
-
-
a
n
d
r
e
w
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
B
l
a
c
k
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
G
A
n
e
n
i
h
c
s
a
m
k
c
u
r
D
r
e
g
r
e
b
l
e
d
i
e
H
7
0
0
2
©
)
f
d
p
(
e
0
.
3
o
c
p
i
D
5
0
1
/
2
0
1
t
a
m
r
o
F
i
S
G
4
t
c
e
n
i
r
P
B
Y
M
C
Y
r
u
l
s
Y
M
C
B
Y
M
C
0
7
Y
Y
M
C
B
Y
M
C
M
r
u
l
s
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
0
7
C
0
7
B
Y
M
C
B
Y
M
C
Y
M
C
B
Y
M
C
C
r
u
l
s
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
Y
M
C
Y
M
Y
M
C
B
Y
M
C
0
7
Y
Y
M
C
B
Y
M
C
Y
C
M
C
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
Y
M
C
B
Y
M
C
0
7
C
Y
M
C
B
Y
M
C
Y
r
u
l
s
Y
M
C
B
Y
M
C
0
7
Y
Y
M
C
B
Y
M
C
M
r
u
l
s
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
0
7
C
0
7
B
Y
M
C
B
Y
M
C
Y
M
C
B
Y
M
C
C
r
u
l
s
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
Y
M
C
Y
M
Y
M
C
B
Y
M
C
0
7
Y
Y
M
C
B
Y
M
C
Y
C
M
C
Y
M
c) Risk management contracts
The Company currently has no outstanding risk management contracts:
As of December 31, 2007, the fair value of the outstanding commodity risk management contracts was a net liability
of $3,085,000.
17. COMMITMENTS, CONTINGENCIES AND GUArANTEES
The Company has no contractual obligations that last more than a year other than its office lease agreements which are
as follows:
Contract Obligations
($000)
Office leases (1)
Total
Less than
1 year
1 – 3
years
$
2,907 $
589 $
1,238 $
4 – 5
years
1,080
(1)
Includes Silverwing’s former office space which is being sublet at a rate that approximates the rates charged to the Company. The funds
received on the sublease have not been offset against the contractual liability.
18. SUBSEQUENT EvENTS - DIvIDENDS
Subsequent to December 31, 2008, the Company has declared the following dividends:
Date declared
January 6, 2009
February 9, 2009
March 5, 2009
Record date
January 15, 2009
February 18, 2009
March 16, 2009
$ per share
$0.16
$0.12
$0.12
Date payable
January 30, 2009
February 27, 2009
March 31, 2009
40 BONTERRA OIL & GAS LTD.
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
k
c
a
l
B
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
w
e
r
d
n
a
-
-
k
c
a
B
1
8
1
:
5
4
:
5
1
6
2
-
3
0
-
9
0
e
s
i
w
t
e
e
h
S
a
r
r
e
t
n
o
B
_
2
9
4
0
2
0
9
2
BONTERRA OIL & GAS LTD. 1MANAGEMENT’S DISCUSSION AND ANALYSISThis report dated March 18, 2009 is a review of the operations, current financial position, and outlook for Bonterra Oil & Gas Ltd. (“Bonterra” or the “Company”) and should be read in conjunction with the audited financial statements for the year ended December 31, 2008, together with the notes related thereto.FOrwArD-LOOkING INFOrMATIONCertain statements contained in this Management’s Discussion and Analysis (MD&A) include statements which contain words such as “anticipate”, “could”, “should”, “expect”, “seek”, “may”, “intend”, “likely”, “will”, “believe” and similar expressions, statements relating to matters that are not historical facts, and such statements of our beliefs, intentions and expectations about development, results and events which will or may occur in the future, constitute “forward-looking information” within the meaning of applicable Canadian securities legislation and are based on certain assumptions and analysis made by us derived from our experience and perceptions. Forward-looking information in this MD&A includes, but is not limited to: expected cash provided by continuing operations; dividends; future capital expenditures, including the amount and nature thereof; oil and natural gas prices and demand; expansion and other development trends of the oil and gas industry; business strategy and outlook; expansion and growth of our business and operations; and maintenance of existing customer, supplier and partner relationships; supply channels; accounting policies; credit risks; and other such matters.All such forward-looking information is based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate in the circumstances. The risks, uncertainties, and assumptions are difficult to predict and may affect operations, and may include, without limitation: foreign exchange fluctuations; equipment and labour shortages and inflationary costs; general economic conditions; industry conditions; changes in applicable environmental, taxation and other laws and regulations as well as how such laws and regulations are interpreted and enforced; the ability of oil and natural gas companies to raise capital; the effect of weather conditions on operations and facilities; the existence of operating risks; volatility of oil and natural gas prices; oil and gas product supply and demand; risks inherent in the ability to generate sufficient cash flow from operations to meet current and future obligations; increased competition; stock market volatility; opportunities available to or pursued by us; and other factors, many of which are beyond our control. The foregoing factors are not exhaustive and are further discussed herein under the heading Business Prospects, Risks and Outlooks as well as in the Company’s Annual Information Form filed on SEDAR at www.sedar.com.Actual results, performance or achievements could differ materially from those expressed in, or implied by, this forward-looking information and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking information will transpire or occur, or if any of them do so, what benefits will be derived therefrom. Except as required by law, the Company disclaims any intention or obligation to update or revise any forward-looking information, whether as a result of new information, future events or otherwise.The forward-looking information contained herein is expressly qualified by this cautionary statement.
COrpOrATE INFOrMATION
BOArD OF DIrECTOrS
G.J. Drummond, Nassau, Bahamas
G.F. Fink, Calgary, Alberta
C.R. Jonsson, Vancouver, British Columbia
F. W. Woodward, Calgary, Alberta
OFFICErS
G.F. Fink – Chief Executive Officer
R.M. Jarock – President and Chief Operating Officer
G.E. Schultz – Vice President, Finance,
Chief Financial Officer & Secretary
rEGISTrAr & TrANSFEr AGENT
Olympia Trust Company, Calgary, Alberta
AUDITOrS
Deloitte & Touche LLP, Calgary, Alberta
SOLICITOrS
Borden Ladner Gervais LLP, Calgary, Alberta
BANkErS
The Royal Bank of Canada, Calgary, Alberta
CIBC, Calgary, Alberta
STOCk LISTING
The Toronto Stock Exchange, Toronto, Ontario
Trading symbol: BNE
hEAD OFFICE
901, 1015 – 4th Street SW
Calgary, Alberta T2R 1J4
PH 403.262.5307
FX 403.265.7488
wEB SITE
www.bonterraenergy.com
2
9
0
2
0
4
9
2
_
B
o
n
t
e
r
r
a
S
h
e
e
t
w
i
s
e
0
9
-
0
3
-
2
6
1
5
:
4
5
:
1
8
1
B
a
c
k
-
-
a
n
d
r
e
w
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
B
l
a
c
k
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
BON TERRA OI L & G AS LTD. 41
M
Y
C
M
C
Y
C
M
Y
B
C
M
Y
Y
7
0
C
M
Y
B
C
M
Y
M
Y
C
M
Y
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
s
l
u
r
C
C
M
Y
B
C
M
Y
C
M
Y
B
C
M
Y
B
7
0
C
7
0
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
s
l
u
r
M
C
M
Y
B
C
M
Y
Y
7
0
C
M
Y
B
C
M
Y
s
l
u
r
Y
C
M
Y
B
C
M
Y
C
7
0
C
M
Y
B
C
M
Y
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
C
M
C
Y
C
M
Y
B
C
M
Y
Y
7
0
C
M
Y
B
C
M
Y
M
Y
C
M
Y
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
s
l
u
r
C
C
M
Y
B
C
M
Y
C
M
Y
B
C
M
Y
B
7
0
C
7
0
C
M
Y
B
C
M
Y
M
7
0
C
M
Y
B
C
M
Y
s
l
u
r
M
C
M
Y
B
C
M
Y
Y
7
0
C
M
Y
B
C
M
Y
s
l
u
r
Y
C
M
Y
B
P
r
i
n
e
c
t
4
G
S
i
F
o
r
m
a
t
1
0
2
/
1
0
5
D
i
p
c
o
3
.
0
e
(
p
d
f
)
©
2
0
0
7
H
e
i
d
e
l
b
e
r
g
e
r
D
r
u
c
k
m
a
s
c
h
i
n
e
n
A
G
Suite 901, 1015 – 4th Street SW | Calgary, Alberta T2R 1J4
42 BONTERRA OIL & GAS LTD.
w
o
l
l
e
Y
a
t
n
e
g
a
M
n
a
y
C
k
c
a
l
B
s
e
r
i
h
k
o
o
B
_
F
D
P
_
g
o
d
n
u
S
w
e
r
d
n
a
-
-
t
n
o
r
F
1
8
1
:
5
4
:
5
1
6
2
-
3
0
-
9
0
e
s
i
w
t
e
e
h
S
a
r
r
e
t
n
o
B
_
2
9
4
0
2
0
9
2
G
A
n
e
n
i
h
c
s
a
m
k
c
u
r
D
r
e
g
r
e
b
l
e
d
i
e
H
7
0
0
2
©
)
f
d
p
(
e
0
.
3
o
c
p
i
D
5
0
1
/
2
0
1
t
a
m
r
o
F
i
S
G
4
t
c
e
n
i
r
P
B
Y
M
C
Y
r
u
l
s
Y
M
C
B
Y
M
C
0
7
Y
Y
M
C
B
Y
M
C
M
r
u
l
s
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
0
7
C
0
7
B
Y
M
C
B
Y
M
C
Y
M
C
B
Y
M
C
C
r
u
l
s
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
Y
M
C
Y
M
Y
M
C
B
Y
M
C
0
7
Y
Y
M
C
B
Y
M
C
Y
C
M
C
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
Y
M
C
B
Y
M
C
0
7
C
Y
M
C
B
Y
M
C
Y
r
u
l
s
Y
M
C
B
Y
M
C
0
7
Y
Y
M
C
B
Y
M
C
M
r
u
l
s
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
0
7
C
0
7
B
Y
M
C
B
Y
M
C
Y
M
C
B
Y
M
C
C
r
u
l
s
Y
M
C
B
Y
M
C
0
7
M
Y
M
C
B
Y
M
C
Y
M
C
Y
M
Y
M
C
B
Y
M
C
0
7
Y
Y
M
C
B
Y
M
C
Y
C
M
C
Y
M
2
9
0
2
0
4
8
5
_
B
o
n
t
e
r
r
a
E
n
e
r
g
y
S
h
e
e
t
w
i
s
e
0
9
-
0
3
-
2
6
1
5
:
2
7
:
0
8
1
F
r
o
n
t
-
-
k
e
r
i
S
u
n
d
o
g
_
P
D
F
_
B
o
o
k
h
i
r
e
s
C
y
a
n
M
a
g
e
n
t
a
Y
e
l
l
o
w
B
l
a
c
k
P
A
N
T
O
N
E
6
5
3
C
P
A
N
T
O
N
E
4
1
0
C
Corporate Information
Board of Directors
G.J. Drummond, Nassau, Bahamas
G.F. Fink, Calgary, Alberta
C.R. Jonsson, Vancouver, British Columbia
F. W. Woodward, Calgary, Alberta
Officers
G.F. Fink – Chief Executive Officer
R.M. Jarock – President and Chief Operating Officer
G.E. Schultz – Vice President, Finance,
Chief Financial Officer & Secretary
Registrar & Transfer Agent
Olympia Trust Company, Calgary, Alberta
Auditors
Deloitte & Touche LLP, Calgary, Alberta
Solicitors
Borden Ladner Gervais LLP, Calgary, Alberta
Bankers
The Royal Bank of Canada, Calgary, Alberta
CIBC, Calgary, Alberta
Stock Listing
The Toronto Stock Exchange, Toronto, Ontario
Trading symbol: BNE
Head Office
901, 1015 – 4th Street SW
Calgary, Alberta T2R 1J4
PH 403.262.5307
FX 403.265.7488
Web Site
www.bonterraenergy.com
16 BONTERRA OIL & GAS LTD.
CMY
Z
X
slurY
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CMY
CMYC 70MY
Z
X
Y
M
C
B
CMY
Z
X
slurM
CMYB 70
Z
X
Y
M
C
B
CMY
Z
X
CMYY 70X 70
Z
X
Y
M
C
B
CMY
Z
X
slurC
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CY
CM
CMYC 70
Z
X
Y
M
C
B
CMY
Z
X
slurB
CMYB 70
Z
X
C
B
CMY
Z
X
slurY
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CMY
CMYC 70MY
Z
X
Y
M
C
B
CMY
Z
X
slurM
CMYB 70
Z
X
Y
M
C
B
CMY
Z
X
CMYY 70X 70
Z
X
Y
M
C
B
CMY
Z
X
slurC
CMYM 70
Z
X
Y
M
C
B
CMY
Z
X
CY
CM
CMYC 70
Z
X
Y
M
C
B
CMY
Z
X
slurB
CMYB 70
Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG