The Value of Bonterra
Growth
Performance
Sustainability
AN NUAL REPORT 20 10
Bonterra Energy Corp. is a high-yield, dividend paying oil and gas company headquartered in
Calgary, Alberta with a proven history of creating growth and long-term value for shareholders on a per
share basis. Bonterra’s successful performance is due to its experienced management team, conservative
capital structure and sustainable pace of development. The Company’s operations are currently focused
on creating value through the execution of its Cardium horizontal drill program and efficient operating
practices, resulting in superior returns for investors.
Bonterra’s common shares trade on the Toronto Stock Exchange under the ticker symbol BNE.
Bonterra is focused on providing investors with continued superior growth on both a total and per share
basis. 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.
The success of the Company’s Cardium horizontal drill program will continue to drive future growth
and maximize long-term value for shareholders.
GROWTH
Bonterra provides income in the form of a monthly dividend and has consistently generated strong
returns for investors. The Company has over $436 million in tax pools which currently extends Bonterra’s
tax horizon past 2018, allowing the Company to target a 2011 payout ratio of 55 to 70 percent of
funds flow.
PERFORMANCE
Bonterra is focused on the sustainable development and efficient management of its high-quality,
low-risk asset base. By operating approximately 84 percent of its production, Bonterra maintains a high
degree of control over the pace of its capital development program and costs incurred. The Company
spent $76.9 million in 2010 and drilled 22 gross (20.0 net) wells with a 100 percent success rate.
SUSTAINABILITY
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:: Annual Highlights 02 :: Quarterly Highlights 03 :: Report to Shareholders 04 :: Operational Review 09 :: Cardium Horizontal Drilling 10 ::
:: Statistical Review 12 :: Management’s Discussion & Analysis 19 :: Consolidated Financial Statements 51 ::
:: Notes to the Consolidated Financial Statements 55 :: Corporate Information 78 ::
5,628
BOE PER DAY IN 2010
8%
INCREASE IN PRODUCTION
PER SHARE
See page 4
for more info
39.4
MILLION BOE
OF P+P RESERVES
5%
INCREASE IN P+P RESERVES
ON A PER SHARE BASIS
See page 12
for more info
59%
$2.55
ONE-YEAR TOTAL RETURN
PAID OUT PER SHARE IN 2010
$1.2
$79.6
BILLION MARKET CAP
MILLION FUNDS FLOW
14
YEAR DRILLING INVENTORY
420
GROSS DRILLING LOCATIONS
77%
OF P+P RESERVES WEIGHTED
TO CRUDE OIL/LIQUIDS
17.8
YEAR RLI
(PROVED PLUS PROBABLE)
See page 4
for more info
See page 5
for more info
See page 9
for more info
See page 12
for more info
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ANNUAL
HIGHLIGHTS
Funds Flow increased 20% in 2010.
Find out more on page 5
A 50% increase in dividends
paid year over year.
Find out more on page 6
69% of production in 2010
was oil/liquids.
Find out more on page 26
Financial ($000s, except $ per share)
Revenue – realized oil and gas
Funds Flow (1)
Per share basic
Per share diluted
Payout ratio
Cash flow from operations
Per share basic
Per share diluted
Payout ratio (2)
Cash payments per share (2)
Net earnings (3)
Per share basic
Per share diluted
Capital expenditures and acquisitions (net of disposals)
Total assets
Working capital deficiency
Long-term debt
Shareholders’ equity
Operations
Oil and liquids (barrels per day)
Natural gas (MCF per day)
Total BOE per day
2010
118,980
79,602
4.23
4.12
60%
66,262
3.52
3.42
72%
2.55
49,864
2.65
2.58
70,680
335,144
14,602
85,386
138,413
3,875
10,521
5,628
2009
85,712
66,504
3.69
3.67
46%
38,893
2.16
2.15
79%
1.70
68,563
3.81
3.78
5,640
293,987
10,162
59,823
118,874
3,141
11,120
4,994
2008
121,730
70,448
4.13
4.12
76%
69,570
4.07
4.06
77%
3.12
55,426
3.25
3.23
45,407
265,301
23,878
79,910
56,777
3,073
7,637
4,346
2010
Financial ($000s, except $ per share)
Revenue – realized oil and gas
Funds Flow (1)
Per share basic
Per share diluted
Payout ratio
Cash flow from operations
Per share basic
Per share diluted
Payout ratio (3)
Cash dividends per share (2)
Net earnings
Per share basic
Per share diluted
Capital expenditures and acquisitions
(net of disposals)
Total assets
Working capital deficiency
Long-term debt
Shareholders’ equity
Operations
Oil and liquids (barrels per day)
Natural gas (MCF per day)
Total BOE per day
4th
3rd
2nd
1st
34,209
21,104
1.11
1.08
61%
16,987
0.89
0.86
74%
0.68
14,213
0.75
0.73
25,318
335,144
14,602
85,386
138,413
4,378
10,214
6,080
28,332
19,622
1.04
1.01
63%
17,558
0.93
0.91
71%
0.66
12,724
0.68
0.66
19,227
318,493
17,891
73,901
128,492
3,890
10,674
5,669
29,191
17,550
0.94
0.91
68%
16,644
0.89
0.86
72%
0.64
10,887
0.58
0.56
10,994
307,934
2,281
78,434
126,045
3,874
11,157
5,733
27,248
21,326
1.14
1.11
50%
15,073
0.81
0.79
70%
0.57
12,040
0.64
0.63
15,141
305,440
13,178
63,097
125,392
3,345
10,038
5,018
(1) Funds flow is not a recognized measure under GAAP. For these purposes, the Company defines funds flow as funds
provided by operations before changes in non-cash operating working capital items but including gain on sale of property
and investments, adjustments of investment tax credit receivable and excluding restricted cash and asset retirement
obligations settled.
(2) Cash dividend payments per share are based on payments made in respect of production months as opposed to the
month paid.
(3) Net earnings includes gains from the sale of properties and investments and recognition of investment tax credits before tax
effect as follows: (2010 - $10,820,000, 2009 - $51,868,000, 2008 - $Nil).
QUARTERLY
HIGHLIGHTS
Bonterra met its 2010 target
payout ratio of between
60 and 75% of Funds Flow.
Find out more on page 6
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Q4 2010 production increased
24% compared to Q4 2009.
Find out more on page 26
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REPORT TO
SHAREHOLDERS
Bonterra Energy Corp. (“Bonterra” or the “Company”) is pleased to report to shareholders its
operational and financial results for the year ended December 31, 2010. The Company continues
to maintain that the best assessment of an entity is its long-term return to shareholders. In 2010,
Bonterra provided investors with a total return of 59 percent and continued to perform extremely
well over longer periods of time. Total return to shareholders over a three year period (2008 – 2010)
was 176 percent and over a five year period (2006 – 2010) was 205 percent. These positive results are
mainly attributable to the Company’s success in the development of its Cardium horizontal drilling
program.
It is a long-term outlook that defines Bonterra’s business strategy. The Company provides investors with
stable income in the form of a monthly dividend and the potential of appreciation of its share price by
sustainable annual growth through the internal development and expansion of its high-quality asset base.
GROWTH AND PERFORMANCE
Bonterra has been a leader in applying horizontal, multi-stage frac technology in the Pembina Cardium
field having drilled the first well in the halo area in 2008. The Company has continued to aggressively
develop its Cardium opportunities in 2010 recording its best operational results to date.
2010 highlights include:
Drilled 22 gross (20.0 net) operated Cardium horizontal, multi-stage fractured wells with a
100 percent success rate in the halo area.
Participated in 5 gross (0.75 net) successful non-operated Cardium horizontal,
multi-stage fractured wells in the main Pembina Cardium pool.
Average daily production increased by 13 percent to 5,628 BOE per day.
Production per share increased by 8 percent to 0.109 BOE per share.
Total Proved plus Probable reserves increased by 10 percent to 39.4 million BOE.
Total Proved plus Probable reserves per share increased by 5 percent to 2.09 BOE per share.
0.109
0.101
0.092
0.091
0.087
2.09
1.99
1.83
1.62
1.57
Production per Share/Unit
(BOE)
Reserves per Share/Unit
(Proved plus Probable)
2010
2009
2008
2007
2006
2010
2009
2008
2007
2006
5 year compounded growth rate
Total Proved reserves increased by 13 percent to 28.6 million BOE.
Proved plus Probable reserve adds 2.7 times 2010 production.
Proved plus Probable reserve life index of 17.8 years, one of the highest among
conventional producers.
In 2011, Bonterra plans to invest between $50 to $60 million on its development program focusing
capital and technical staff on the Company’s highest-quality opportunities. The program plan is to:
Drill a minimum of 20 gross horizontal Cardium wells mainly in the halo area of the Pembina and
Willesden Green fields with the remainder in the main pool of the Pembina field.
Maintain a steady pace of development targeting 10 to 15 percent growth in production. Production
for the full year 2011 is estimated to be between 6,200 to 6,500 BOE per day.
Implement further cost reduction initiatives on the horizontal drill program including new drilling
and completion methods to not only decrease costs but also improve well performance and
reserve recovery.
Conduct project reviews throughout the year and apply additional operational efficiencies where
possible to reduce operating costs to the $12.50 to $13.50 per BOE range.
Continue to review and develop new opportunities to ensure long-term sustainable growth.
FINANCIAL RESULTS
Financial results in 2010 were positively impacted by increased production levels and improved crude oil
prices. Overall, Bonterra generated cash flow from operations of $66.3 million and net earnings of
$49.9 million or on a per share basis (basic), $3.52 and $2.65, respectively. The Company’s average realized
price for crude oil and natural gas liquids increased 21.5 percent year over year to $72.69 per barrel.
Natural gas prices remained depressed and the Company’s average realized price was $4.14 per MCF.
The improved crude oil pricing environment is positive for the Company. Bonterra’s production
is composed of predominantly light oil and in 2010, 69 percent of the Company’s production was
crude oil and liquids. The Board of Directors and management have decided to not engage in any
hedging practices at the present time and have not hedged since 2008.
2010
2009
2008
2007
2006
2010
2009
2008
2007
2006
2010
2009
2008
2007
2006
Average Daily Production
(BOE per day)
Cash Flow from Operations
($ thousands)
Funds Flow
($ thousands)
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5,628
4,994
4,346
4,218
4,042
66,262
38,893
69,570
51,433
51,944
79,602
66,504
70,448
53,815
52,797
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2010
2009
2008
2007
2006
Cash Dividends/Distributions
to Investors
($ per unit/share)
Funds Flow
Dividends/Distributions
$4.23
$2.55
$3.69
$1.70
$4.13
$3.12
$3.18
$2.64
$3.15
$2.82
In 2010, Bonterra increased the monthly cash dividend twice and paid out a total of $2.55 per share, an
increase of 50 percent over 2009 levels. Subsequent to year-end, Bonterra was able to again increase
the dividend to its current level of $0.24 per share which began with the dividend paid out in
January 2011.
Management and the Board of Directors will continue to monitor production volumes, commodity prices,
operating costs, payout ratios and capital expenditures on a monthly basis to determine the dividend
amount. There remains good potential to increase the dividend level should the current strong pricing
environment persist coupled with expected production level increases resulting from the capital program.
FINANCIAL STRENGTH
A conservative approach to the Company’s capital structures has been a key factor in building financial
strength and flexibility. Bonterra retains its strong financial position by maintaining a sustainable growth
strategy, minimizing the amount and cost of debt and raising equity when prudent. As a result, Bonterra
is well funded to execute the 2011 capital program and to pursue additional acquisition opportunities that
may become available.
Bonterra has over $436 million in tax pools, $27 million in investment tax credits and $141 million of capital
loss carry forwards (which can only be claimed against taxable capital gains). The Company anticipates
that these pools push Bonterra’s tax horizon beyond 2018.
The Company ended 2010 with a total of debt and working capital to cash flow ratio of 1.18 times (based
on a total of debt and working capital of $100.0 million and annualized 2010 fourth quarter funds flow of
$84.4 million). As a result of its strong financial position, Bonterra is well funded to execute the
2011 capital program and to pursue additional acquisition opportunities that may become available.
ACQUISITIONS AND DISPOSITIONS
Bonterra has strengthened its asset base by selling a portion of its non-core holdings. In February 2010,
the Company disposed of its Southeast Saskatchewan Pinto property. The proceeds of disposition were
$5,534,000 cash. In addition, during the third quarter of 2010 the Company disposed of non-producing land
for proceeds of $700,000. The Company re-deployed the proceeds from these dispositions towards
Bonterra’s 2010 Cardium drilling program.
7
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Bonterra’s core asset base is concentrated in the Cardium pools located in the Pembina and Willesden
Green fields of west central Alberta. The Company’s high level of concentration and experience in the
area provides Bonterra with the knowledge to efficiently exploit the Cardium formation. As such, Bonterra
plans to pursue land and corporate acquisitions to acquire further interests in its key resource plays.
In addition, Bonterra is also considering natural gas acquisitions to take advantage of the low price
environment. Bonterra’s enviable, mainly oil, drilling inventory of over 14 years may allow the
Company to acquire natural gas assets at low prices and to wait until natural gas pricing improves
before developing these properties.
OUTLOOK
This is an exciting time for Bonterra and its shareholders. The Company has a superior inventory of
long-life, light oil targets in the Cardium play and the flexibility to allocate internal resources
to achieve the best returns. The Company will continue to execute a disciplined approach to its
operations and financial management in 2011 to maximize shareholder value on a long-term basis while
remaining committed to continuous improvements and safety across its operations.
The Company is confident that 2011 will be a year of growth for both its operations and its investors.
Bonterra would like to take this opportunity to thank its long-term shareholders for their continued support
of the Company, the Board of Directors for their strategic guidance and its employees for continuing to
create and deliver outstanding value for shareholders.
2010
2009
2008
2007
2006
2010
2009
2008
2007
2006
George F. Fink
Chairman of the
Board and Chief
Executive Officer
Randy M. Jarock
President and
Chief Operating Officer
Proved plus Probable Reserves
(MBOE)
Proved plus Probable
Reserve Life Index
(years)
39,397
35,824
31,241
27,321
26,476
17.8
20.1
18.7
17.4
17.6
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Bonterra’s demonstrated
history of year over year
reserve and production
growth on a per share
basis is unparalleled in the
energy industry. Growth
on a per share basis will
remain a prime objective
for Bonterra.
14 year
DRILLING INVENTORY
10%-15%
PRODUCTION
GROWTH TARGET
FOR 2011
01-25-047-03W5
Well Production
Actual versus Predicted Performance
Current Performance Point
(as of Dec 2010)
Model was calibrated with
production and pressure
data up to this point
70,000
60,000
50,000
40,000
30,000
20,000
10,000
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15
Month
20
25
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0
100 200 300 400 500 600 700 800 900
Total Time on Production, days
History-Matched Period
Additional Well Performance Data Model Prediction
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OPERATIONAL
REVIEW
The enormous resource potential, robust economics
and solid results recorded by Bonterra in its horizontal
Cardium drilling program continue to provide the
Company with strong competitive advantages.
Bonterra drilled the first horizontal well (01-25-047-
03W5) in the Pembina halo area in late 2008 which has
averaged 101 BOE per producing day to date. This well
has performed as expected, exhibiting a typical Cardium
hyperbolic decline that is generally observed in the main
Pembina Pool. The well has also tracked favorably with
Sproule Associates Limited’s predicted performance
trend from the 3-D Reservoir Model that was completed in
September, 2009. This 3-D numerical model indicates that
oil recoveries of up to 225,000 stock tank barrels per well
are achievable in portions of the Cardium halo with similar
well completion and reservoir characteristics.
250
200
150
100
50
)
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Bonterra’s operations are defined by consistency and
sustainability. Bonterra’s demonstrated history of year
over year reserve and production growth on a per share
basis is unparalleled in the energy industry. Growth
on a per share basis will remain a prime objective
for Bonterra.
In 2011, Bonterra plans to drill at least 20 wells,
predominantly in the halo area of the Pembina and
Willesden Green Cardium fields with the remainder in the
main pool of the Pembina Cardium field. The Company
plans to continue advancing its use of horizontal
multi-stage technology in the main part of the Pembina
Cardium pool in 2011 by initiating an operated multi-well
program in the second half of 2011 with the objective of
changing the pool exploitation strategy to horizontal well
development from vertical well development.
10 CARDIUM HORIZONTAL DRILLING
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OVERVIEW
Bonterra is the third largest operator in the Pembina Cardium field, Canada’s largest conventional light
oil field, with approximately 160 gross (117 net) sections including 27.5 gross (23.9 net) sections in the
halo area. Bonterra has a 14 year drilling inventory with 420 gross locations already identified including
at least 52 gross horizontal locations in the Halo area of the Pembina and Willesden Green fields.
In 2011, the Company will spend $50 to $60 million on its capital development program focused
mainly on its horizontal drill program. Full year production rates are expected to average between
6,200 to 6,500 BOE per day, an increase of 10 to 15 percent over 2010 levels.
West
Pembina
Berrymoor
Cardium
Unit
T51
T50
T49
T48
T47
East
Carnwood
Warburg
T46
Willesden Green
BONTERRA LANDS
R14
R13
R12
R11
R10
R9
R8
R7
R6
R5
R4
R3
R2W5
T45
T44
T43
Main Pool
Bonterra participated in successfully drilling
five gross (0.75 net) non-operated horizontal
Berrymoor Cardium Unit wells in the main
Pembina Cardium pool. The Company plans
to further advance the use of horizontal
multi-stage technology in 2011 with the objective
of converting some identified vertical locations
to horizontals locations.
98.4 gross (82.3 net) sections
5 gross (0.75 net) wells drilled in 2010
6 gross (2.9 net) wells planned in 2011
West Pembina
East Carnwood
The West Pembina area was a key focus area for the Company in 2010.
Bonterra’s development plans in 2011 will involve completing development
of the area to four wells per section.
Bonterra will look to follow up on the success of the 15-22-48-05W5 well in
this area with its 2011 capital development program.
2222
23
24
19
20
21
22
23
24
19
20
21
22
19
20
21
22
23
24
19
20
21
MAIN POOL
22
23
24
19
15
14
10
11
13
12
3
2
1
18
17
16
15
14
13
18
17
16
15
7
6
8
5
9
4
10
11
HALOHALO
12
7
3
2
1
6
8
5
9
4
10
T48
3
2
33
34
35
36
31
32
33
34
35
36
31
32
33
28
27
26
25
30
29
28
27
26
25
30
29
28
T47
34
27
21
22
23
24
19
20
21
22
23
24
19
20
21
22
16
15
14
13
18
17
16
15
14
13
MAIN POOL
MAIN POOL
15
16
17
18
9
10
11
12
3
2
1
7
6
8
5
9
4
10
11
12
3
2
1
7
6
8
5
9
10
4
T46
3
34
35
36
31
32
33
34
35
36
31
32
33
34
R4
27
26
25
R3
30
29
28
27
26
R2W5
25
30
29
28
27
22
23
24
19
20
21
22
23
24
19
20
21
22
4 gross (3.75 net) sections
12 wells drilled in 2010
4 gross (3 net) wells planned
in 2011
278,310 Bbls of cumulative oil
production (02/28/2011)
2,845.6 MBOE Proved reserves;
4,062.1 MBOE Proved plus
Probable reserves
18
17
16
15
14
13
18
17
16
15
14
13
18
7
6
8
5
9
4
10
11
12
3
2
1
7
6
8
5
9
4
10
11
12
3
2
1
7
6
31
32
33
34
35
36
31
32
33
34
35
36
31
30
29
28
27
26
25
30
29
28
27
26
25
30
19
20
21
22
23
24
19
20
21
22
23
24
19
18
17
16
HALOHALO
15
14
13
18
17
16
15
14
13
18
7
6
8
5
9
4
10
11
12
3
2
1
7
6
8
5
9
4
10
11
12
3
2
1
7
6
5.5 gross (4.375 net)
sections
5 gross (4.25 net) wells
drilled in 2010
5 gross wells (3.75 net)
planned in 2011
93,157 Bbls of
cumulative oil
production (02/28/2011)
1,846 MBOE Proved;
3,139.6 MBOE Proved
plus Probable reserves
11
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P
.
2
0
1
0
A
N
N
U
A
L
R
E
P
O
R
T
Willesden Green
Warburg
This area provides the Company with a large potential for future reserve
growth and will be an important component of the 2011 capital
development program.
Bonterra has recorded success in this area, the initial area of development.
It has demonstrated potential for low-risk and repeatable infill development.
2323
2424
1919
2020
2121
2222
2323
2424
1414
1313
1818
1717
1616
1515
1414
1313
1111
1212
2
1
77
6
88
5
99
4
1010
HALOHALO
1111
122
3
2
1
3535
3636
3131
3232
3333
3434
3535
3636
2626
2525
3030
2929
2828
2727
2626
2525
2323
2424
1919
2020
2121
2222
2323
2424
1414
1313
1818
1717
1616
1515
1414
1313
19
1818
77
6
311
3030
199
1818
2020
2121
2222
1717
1616
1515
88
5
9
4
1010
3
3232
3333
3434
2929
2828
2727
2020
2121
2222
177
1616
155
1111
1212
22
11
77
66
88
55
99
44
1010
1111
1212
33
22
11
7
66
MAIN POOL
MAIN POOL
1010
8
9
55
44
33
MAIN POOL
5 gross (4.875 net) sections
4 gross wells (3.75 net)
drilled in 2010
5 gross (5 net) wells planned
in 2011
17,211 Bbls of cumulative oil
production (02/28/2011)
251.3 MBOE Proved;
838.1 MBOE Proved plus
Probable reserves
7.75 gross (5.3 net) sections
3 gross (2.0 net) wells drilled
in 2010
2 gross (1.4 net) wells planned
in 2011
354,075 Bbls of cumulative oil
production (02/28/2011)
HALO
1,409 MBOE Proved;
2,197 MBOE Proved plus
Probable reserves
3535
3636
3131
3232
3333
3434
3535
3636
3131
3232
3333
3434
* Drilling plans are subject to change based on actual results.
12
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A
U
N
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A
0
1
0
2
.
P
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R
E
N
E
A
R
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T
N
O
B
STATISTICAL REVIEW
RESERVES
Bonterra engaged the services of Sproule Associates Limited to prepare a reserve evaluation with an
effective date of December 31, 2010. The reserves are located in the provinces of Alberta, British Columbia
and Saskatchewan. Bonterra’s largest producing area is located in the Pembina and Willesden Green fields
of Alberta, which contains 94.3 percent of the Company’s reserves of a Proved plus Probable basis. The gross
reserve figures from 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, 2010
Reserve Category:
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved Plus Probable
Light and
Medium
Oil (Mbbl)
Natural
Gas
(MMcf)
Natural
Gas Liquids
(Mbbl)
15,594.4
206.1
4,693.0
20,493.5
7,708.2
28,201.7
32,552
507
5,441
38,500
15,192
53,692
1,400.7
12.6
251.7
1,665.0
581.7
2,246.7
BOE(1)
(MBOE)
22,420.3
303.3
5,851.4
28,575.1
10,822.0
39,397.0
13
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T
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R
R
A
E
N
E
R
Y
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P
.
2
0
1
0
A
N
N
U
A
L
R
E
P
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T
RECONCILIATION OF COMPANY GROSS RESERVES BY PRINCIPAL
PRODUCT TYPE AS OF DECEMBER 31, 2010
Light and Medium
Oil and Natural
Gas Liquids
Proved
plus
Probable
Proved
(Mbbl)
19,220.1
2,984.1
0
1,474.1
0
0
(178.9)
73.5
(1,414.4)
22,158.5
(Mbbl)
27,567.7
4,915.8
0
(489.9)
0
0
(213.3)
82.5
(1,414.4)
30,448.4
December 31, 2009
Extension
Improved Recovery
Technical Revisions
Discoveries
Acquisitions
Dispositions
Economic factors
Production
December 31, 2010
Natural Gas
BOE(1)
Proved
plus
Probable
Proved
(MMcf)
36,642
2,706
0
3,512
0
0
(318)
(202)
(3,840)
38,500
(MMcf)
49,539
4,374
0
4,193
0
0
(376)
(198)
(3,840)
53,692
Proved
Plus
Probable
(MBOE)
35,824.2
5,644.8
0
208.9
0
0
(276.0)
49.5
(2,054.4)
39,397.1
Proved
(MBOE)
25,327.1
3,435.1
0
2,059.4
0
0
(231.9)
39.8
(2,054.4)
28,575.2
SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE
AS OF DECEMBER 31, 2010
Net Present Values of Future Net Revenue Before Income Taxes Discounted at (%/Year)
($ Millions)
Reserve Category:
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved Plus Probable
0%
5%
10%
15%
20%
Future
Net Value
10%/yr
($/BOE)(1)
1,097.7
14.4
207.1
1,319.2
644.5
1,963.7
656.9
10.7
135.8
803.5
251.8
1,055.2
479.9
8.6
93.1
581.6
132.1
713.6
385.3
7.2
65.4
457.9
82.0
540.0
326.0
6.2
46.5
378.7
56.1
434.8
24.15
31.65
18.85
23.19
14.58
20.91
14
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A
U
N
N
A
0
1
0
2
.
P
R
O
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Y
R
E
N
E
A
R
R
E
T
N
O
B
Net Present Values of Future Net Revenue After Income Taxes Discounted at (%/Year)
($ Millions)
Reserves Category:
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved Plus Probable
0%
929.5
10.8
155.3
1,095.5
483.5
1,579.0
5%
585.3
8.3
100.3
693.9
188.5
882.3
10%
441.9
6.8
67.4
516.1
98.7
614.8
15%
362.7
5.8
46.1
414.7
61.2
475.9
20%
311.5
5.2
31.6
348.2
41.9
390.1
Commodity prices used in the above calculations of reserves are as follows:
Natural Gas
AECO-
C-Spot
(Cdn $
Edmonton
Par Price
(Cdn $
per BBl) per MMbtu)
93.08
93.85
93.43
93.54
94.95
96.38
97.84
99.32
100.81
102.34
4.04
4.66
4.99
6.58
6.69
6.80
6.91
7.02
7.14
7.26
Butanes
Edmonton
(Cdn $
per Bbl)
62.44
62.95
62.67
62.75
63.69
64.65
65.63
66.62
67.63
68.65
Pentanes
Edmonton
(Cdn $
per Bbl)
95.32
96.11
95.68
95.79
97.24
98.71
100.20
101.71
103.25
104.81
Inflation
Rate
Exchange
Rate
(%/Yr) ($ U.S./$ Cdn)
0.932
0.932
0.932
0.932
0.932
0.932
0.932
0.932
0.932
0.932
1.5
1.5
1.5
1.5
1.5
1.5
1.5
1.5
1.5
1.5
Year
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
Crude oil, natural gas and liquid prices escalate at 1.5 percent thereafter.
15
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A
E
N
E
R
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C
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P
.
2
0
1
0
A
N
N
U
A
L
R
E
P
O
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T
2010 FINDING AND DEVELOPMENT COSTS
The Company has historically been active in its capital development program. Over three years, Bonterra has
incurred the following finding and development (F&D) and finding, development and acquisition(FD&A)(3) costs:
Proved Reserve Net Additions
Proved plus Probable Reserve Net Additions
Proved Reserve Net Additions
Proved plus Probable Reserve Net Additions
2010 F&D
Costs per
BOE(1)(2)
21.98
$
19.19
$
2010 FD&A
Costs per
BOE(1)(2)(3)
20.86
$
18.13
$
2009 F&D
Costs per
BOE(1)(2)
16.23
11.01
$
$
2009 FD&A
Costs per
BOE(1)(2)(3)
13.25
$
8.93
$
2008 F&D
Costs per
BOE(1)(2)
7.00
6.82
$
$
2008 FD&A
Costs per
BOE(1)(2)(3)
8.67
$
7.47
$
Three Year
Average
15.07
$
12.34
$
Three Year
Average
14.26
$
11.51
$
(1) Barrels of Oil Equivalent may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based
on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at
the wellhead.
(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.
(3) FD&A costs are net of proceeds of disposal and the FD&A costs per BOE are based on reserves acquired net of reserves
disposed of.
FD&A and F&D cost increases are primarily due to 1) a 12 percent increase to the Company’s average
horizontal well costs, reflecting the deeper Cardium targets in West Pembina and Willesden Green and
the placing of more fracs per well; 2) capital for infrastructure which will reduce operating expense but
not increase reserves was included that was not included in the previous reserve report; and 3) due to the
51-101 Standards of Disclosure only six of a possible 22 wells were assigned reserves in Willesden Green.
All reserves numbers provided in the preceding tables are Bonterra’s interest before royalties. It should not
be assumed that the estimates of future net revenue presented in the above tables represent the fair market
value of reserves. There is no assurance that the forecast prices and costs assumptions will be attained and
variances could be material. 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.
16
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A
U
N
N
A
0
1
0
2
.
P
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R
E
N
E
A
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R
E
T
N
O
B
PRODUCTION
Pembina, Alberta
British Columbia
Saskatchewan
Other Alberta
LAND HOLDINGS
Alberta
British Columbia
Saskatchewan
Oils and NGLs
(Bbls per day)
3,564
22
172
117
3,875
2010
Natural Gas
(MCF per day)
6,607
2,971
269
674
10,521
Total
(BOE per day)
4,665
517
217
229
5,628
2010
2009
Gross Acres
172,749
61,330
6,881
240,960
Net Acres
109,944
21,217
5,640
136,801
Gross Acres
172,907
73,194
14,779
260,880
Net Acres
109,710
28,509
12,846
151,065
PETROLEUM AND NATURAL GAS 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:
($000s)
Land
Acquisitions
Disposals
Exploration and development costs
Net petroleum and natural gas capital expenditures
2010
-
-
(6,234)
76,914
70,680
2009
5,184
7,105
(30,191)
22,912
5,640
17
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A
E
N
E
R
Y
C
O
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P
.
2
0
1
0
A
N
N
U
A
L
R
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P
O
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T
DRILLING HISTORY
The following tables summarize Bonterra’s gross and net drilling activity and success:
Crude oil
Natural gas
Dry
Total
Success rate
Crude oil
Natural gas
Dry
Total
Success rate
Crude oil
Natural gas
Dry
Total
Success rate
Development
Exploratory
Total
2010
Gross
30
1
-
31
100%
Net
22.09
0.11
-
22.20
100%
Gross
-
-
-
-
-
Development
2009
Exploratory
Gross
15.0
2.0
-
17.0
100%
Net
12.4
0.4
-
12.8
100%
Gross
-
-
-
-
-
Development
2008
Exploratory
Net
-
-
-
-
-
Net
-
-
-
-
-
Gross
30
1
-
31
100%
Total
Gross
15.0
2.0
-
17.0
100%
Total
Gross
Net
Gross
Net
Gross
35.0
8.0
-
43.0
100%
25.5
5.1
-
30.6
100%
1
-
-
1
100%
0.3
-
-
0.3
100%
36.0
8.0
-
44.0
100%
Net
22.09
0.11
-
22.20
100%
Net
12.4
0.4
-
12.8
100%
Net
25.8
5.1
-
30.9
100%
18
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A
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N
N
A
0
1
0
2
.
P
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R
E
N
E
A
R
R
E
T
N
O
B
SHARE TRADING STATISTICS
High
Low
Close
Daily Average Trading Volume
BONTERRA VS. THE INDICES
$
$
$
2010
53.56
31.27
51.65
29,041
$
$
$
$
2009
36.44
13.50
35.14
22,704
Cumulative Total Return on $100 Investment
400
350
300
250
200
150
100
50
Dec. 2005
Dec. 2006
Dec. 2007
Dec. 2008
Dec. 2009
Dec. 2010
Bonterra
TSX 300 Composite Index
TSX Energy Index
2010 Production by Commodity
2010 Reserves by Commodity
(based on Proved plus Probable Reserves)
69% Oil and NGLs
31% Natural Gas
77% Oil and NGLs
23% Natural Gas
19
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R
A
E
N
E
R
Y
C
O
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P
.
2
0
1
0
A
N
N
U
A
L
R
E
P
O
R
T
MANAGEMENT’S DISCUSSION
AND ANALYSIS
This report dated March 22, 2011 is a review of the operations, current financial position, and outlook for
Bonterra Energy Corp. (“Bonterra” or the “Company”) and should be read in conjunction with the audited
financial statements for the year ended December 31, 2010, together with the notes related thereto.
NON-GAAP MEASURES
Throughout this Management’s Discussion and Analysis (MD&A) we use the terms “payout ratio” and
“cash netback” to analyze operating performance. We calculate payout ratio by dividing cash dividends to
shareholders by cash flow from operating activities both of which are measures prescribed by GAAP
which appear on our consolidated statements of cash flows. We calculate cash netback by dividing
various operation and deficit statement items as determined by GAAP by total production on a barrel of
oil equivalent basis.
FORWARD-LOOKING INFORMATION
Certain statements contained in this 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.
20
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L
A
U
N
N
A
0
1
0
2
.
P
R
O
C
Y
R
E
N
E
A
R
R
E
T
N
O
B
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
As at and for the years ended December 31,
Financial ($000s, except $ per share)
Revenue – realized oil and gas
Cash flow from operations
Per share basic
Per share diluted
Cash payments per share (1)
Payout ratio (1)
Net earnings (2)
Per share basic
Per share diluted
Capital expenditures and acquisitions (net of disposals)
Total assets
Working capital deficiency
Long-term debt
Shareholders’ equity
Operations
Oil and liquids (barrels per day)
Natural gas (MCF per day)
Total BOE per day
2010
2009
2008
118,980
66,262
3.52
3.42
2.55
72%
49,864
2.65
2.58
70,680
335,144
14,602
85,386
138,413
3,875
10,521
5,628
85,712
38,893
2.16
2.15
1.70
79%
68,563
3.81
3.78
5,640
293,987
10,162
59,823
118,874
3,141
11,120
4,994
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
(1) Cash dividend payments per share are based on payments made in respect of production months as opposed to the
month paid.
(2) Net earnings includes gains from the sale of properties and investments and recognition of investment tax credits before tax
effect as follows: (2010 – $10,820,000, 2009 – $51,868,000, 2008 – $Nil)
21
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O
N
T
E
R
R
A
E
N
E
R
Y
C
O
R
P
.
2
0
1
0
A
N
N
U
A
L
R
E
P
O
R
T
22
T
R
O
P
E
R
L
A
U
N
N
A
0
1
0
2
.
P
R
O
C
Y
R
E
N
E
A
R
R
E
T
N
O
B
QUARTERLY COMPARISONS
Financial ($000s, except $ per share)
Revenue – realized oil and gas
Cash flow from operations
Per share basic
Per share diluted
Cash dividends per share (1)
Payout ratio (1)
Net earnings
Per share basic
Per share diluted
Capital expenditures and acquisitions (net of disposals)
Total assets
Working capital deficiency
Long-term debt
Shareholders’ equity
Operations
Oil and liquids (barrels per day)
Natural gas (MCF per day)
Total BOE per day
4th
34,209
16,987
0.89
0.86
0.68
74%
14,213
0.75
0.73
25,318
335,144
14,602
85,386
138,413
4,378
10,214
6,080
3rd
28,332
17,558
0.93
0.91
0.66
71%
12,724
0.68
0.66
19,227
318,493
17,891
73,901
128,492
3,890
10,674
5,669
2010
2nd
29,191
16,644
0.89
0.86
0.64
72%
10,887
0.58
0.56
10,994
307,934
2,281
78,434
126,045
3,874
11,157
5,733
1st
27,248
15,073
0.81
0.79
0.57
70%
12,040
0.64
0.63
15,141
305,440
13,178
63,097
125,392
3,345
10,038
5,018
(1) Cash dividend payments per share are based on payments made in respect of production months as opposed to the
month paid.
(2) Net earnings includes gains from the sale of properties and investments and recognition of investment tax credits before tax
effect as follows: (2010 – $10,820,000, 2009 – $51,868,000, 2008 – $Nil)
Financial ($000s, except $ per share)
Revenue – realized oil and gas
Cash flow from operations
Per share basic
Per share diluted
Cash dividends per share (1)
Payout ratio (1)
Net earnings
Per share basic
Per share diluted
Capital expenditures and acquisitions (net of disposals)
Total assets
Working capital deficiency
Long-term debt
Shareholders’ equity
Operations
Oil and liquids (barrels per day)
Natural gas (MCF per day)
Total BOE per day
4th
24,946
13,673
0.76
0.75
0.50
66%
52,136
2.88
2.85
(16,976)
293,987
10,162
59,823
118,874
3,182
10,193
4,881
3rd
20,965
9,350
0.50
0.50
0.44
87%
5,790
0.32
0.32
17,660
273,543
14,455
81,386
74,025
3,084
10,881
4,898
2009
2nd
20,501
9,238
0.52
0.52
0.40
77%
4,544
0.26
0.26
2,255
258,393
13,989
71,573
72,332
3,029
11,551
4,954
1st
19,300
6,632
0.38
0.38
0.36
94%
6,093
0.35
0.35
2,701
260,732
14,909
89,383
56,377
3,268
11,877
5,245
(1) Cash dividend payments per share are based on payments made in respect of production months as opposed to the
month paid.
(2) Net earnings includes gains from the sale of properties and investments and recognition of investment tax credits before tax
effect as follows: (2010 – $10,820,000, 2009 – $51,868,000, 2008 – $Nil).
23
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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, 2010 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 communication.
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.
While Bonterra believes it has adequate DC&P in place, lapses in the disclosure controls and procedures
could occur and/or errors could occur. Should such occur, the Company intends to take whatever steps it
deems necessary to minimize the consequences thereof.
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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 acquisitions, 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, 2010, 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. In addition, the Company has concluded that
sufficient mitigating controls exist that the below mentioned weaknesses have resulted in no material
impact on the Company’s financial reporting or ICFR.
The control framework the Company used to design and evaluate its ICFR was the Committee of
Sponsoring Organizations of the Treadway Commission (COSO). In its evaluation, the Company identified
certain 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 controls over financial reporting.
26
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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; and the establishment of a whistle-blower policy. Based on the above identified weaknesses, the
Company has concluded that the Company’s ICFR are ineffective. The mitigating factors will not necessarily
prevent a 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.
INTERNAL CONTROL CHANGES
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 2010 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 2010.
PRODUCTION
Crude oil and NGLs (barrels per day)
Natural gas (MCF per day)
Average BOE per day
Three Months Ended
Twelve Months Ended
December
31, 2010
4,378
10,214
6,080
September
30, 2010
3,890
10,674
5,669
December
31, 2009
3,182
10,193
4,881
December
31, 2010
3,875
10,521
5,628
December
31, 2009
3,141
11,120
4,994
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.
27
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Bonterra’s 2010 average production increased 12.7 percent on a per BOE per day basis over 2009 which
includes the production from the February 2010 sale of the Pinto property of approximately 60 BOE per
day and the November 2009 sale of the Shaunavon property of approximately 200 BOE per day. Crude oil
production increased by 23.4 percent while gas production decreased by 5.4 percent. The natural gas
decrease was due primarily to the shut in of a portion of the Company’s Pembina natural gas production.
In June 2010, a non-operated natural gas plant, to which Bonterra delivers a portion of its natural gas,
reached capacity and resulted in the shut in of a number of the Company’s natural gas wells. The average
amount of shut in natural gas during Q3 was approximately 660 MCF per day (110 BOE per day).
Effective October 1, 2010, the Company was notified of additional shut in requirements due to other owners
in the plant increasing their throughput. Although Bonterra is an owner in the facility, the Company had been
delivering natural gas volumes well in excess of its ownership percentage. The amount of natural gas shut
in effective October 1, 2010 was approximately 1,100 MCF per day (183 BOE per day) net to the Company.
The Company is currently reviewing alternatives, while considering the current low natural gas prices, to
either redirect this natural gas production or participate with the other owners in the plant in the expansion
of the facility. A short-term solution has been presented by one of the other owners where they would
redirect a portion of their natural gas to an alternative natural gas processing facility. Once this is complete,
anticipated by the end of Q1 2011, Bonterra would be able to reactivate all of its currently shut in production,
but due to low natural gas prices may elect to keep these wells shut in for the present time.
The Company drilled 22 gross (20.0 net) operated Pembina Cardium horizontal oil wells (five gross
and net in Q4 2010) and one gross and net Pembina Cardium vertical oil well during 2010. The Company
also participated in the drilling of five gross (0.75 net) (two gross and 0.3 net in Q4 2010) non-operated
Pembina Cardium horizontal oil wells and two gross (0.3 net) non-operated Pembina Cardium vertical
oil wells during 2010. Bonterra’s working interest in the non-operated wells is approximately 15 percent.
Bonterra had a 100 percent success rate in 2010.
As of December 31, 2010 the Company had four gross (3.75 net) operated horizontal wells drilled but not
on production. One of the remaining operated horizontal oil wells (one net) was placed on production
January 2, 2011. The remaining three (2.75 net) horizontal wells were on production in February, 2011.
The Company’s fourth quarter 2010 production saw increases in crude oil of 488 barrels per day and a decline
in natural gas of 460 MCF per day production compared to Q3 2010. During the fourth quarter, the Company
was able to place on production two 100 percent gross and net horizontal wells in October, four gross
(3.43 net) horizontal wells in November and one gross and net horizontal well in late December, 2010.
Offsetting the increase in solution gas from these wells was the additional shut in of approximately
600 MCF per day of natural gas production due to the above mentioned gas plant capacity restrictions.
Bonterra expects 2011 production to average between 6,200 and 6,500 BOE per day.
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REVENUE
Revenue – oil and gas sales ($ 000s)
Average Realized Prices:
Crude oil and NGLs ($ per barrel)
Natural gas ($ per MCF)
Three Months Ended
Twelve Months Ended
December
31, 2010
34,209
September
30, 2010
28,332
December
31, 2009
24,946
December
31, 2010
118,980
December
31, 2009
85,712
75.91
3.78
68.79
3.74
68.40
4.76
72.69
4.14
59.82
4.15
Revenue from petroleum and natural gas sales increased 38.8 percent in 2010 compared to 2009. The
increase was primarily due to a 23.4 percent increase in crude oil production as well as a 21.5 percent
increase in crude oil prices. During 2010 the Company did not enter into any risk management contracts.
Quarter over quarter the Company saw an increase in revenues of $5,877,000, a 20.7 percent increase,
due primarily to increased crude oil production as well as increased crude oil pricing.
ROYALTIES
($ 000s except $ per BOE)
Crown royalties
Freehold royalties, gross overriding
royalties and net carried interests
Total royalty expense
Percentage of revenue
$ per BOE
Three Months Ended
Twelve Months Ended
December
31, 2010
2,092
September
30, 2010
1,907
December
31, 2009
1,451
December
31, 2010
7,562
December
31, 2009
4,737
757
2,849
8.3
5.09
1,041
2,948
10.4
5.65
892
2,343
9.4
5.22
3,875
11,437
9.6
5.57
2,677
7,414
8.6
4.07
Royalties paid by the Company consist primarily of Crown royalties paid to the Provinces of Alberta,
Saskatchewan and British Columbia. The Company’s average Crown royalty rate was approximately
6.4 percent (2009 – 5.5 percent) and approximately 3.3 percent (2009 – 3.1 percent) for other royalties.
The fourth quarter royalties decreased $99,000 over the third quarter. During the fourth quarter the
Company reviewed several of its other royalty agreements and discovered some overpayments. The
adjustment recorded in Q4 2010 amounted to approximately $160,000 of overpayments in previous periods.
In addition, production subject to the freehold royalty rate of 17 percent has been declining while production
from the Company’s new crown horizontal wells, which have a five percent royalty rate, has increased
resulting in an overall lower royalty expense.
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ALBERTA GOVERNMENT COMPETITIVENESS REVIEW
On March 11, 2010, the Government of Alberta announced it will modify conventional oil and natural gas
royalties effective January 2011 to increase Alberta’s competitiveness in the upstream energy sector. The
current five percent front-end royalty rate on conventional oil and natural gas will become a permanent
feature of the royalty system. The maximum royalty rate for conventional oil will be reduced to 40 percent
from 50 percent. The maximum royalty rate for conventional and unconventional natural gas will be reduced
at higher prices from 50 to 36 percent. Other royalty incentive programs will remain in effect. Management
believes these changes to the royalty system should have a positive effect on the Company’s future
cash flow.
OTHER REVENUE
($ 000s)
Investment tax credit recovery
Gain on sale of property
Gain on sale of investments
Interest and other
Total other revenue
Three Months Ended
Twelve Months Ended
December
31, 2010
–
–
782
10
792
September
30, 2010
–
700
3,536
2
4,238
December
31, 2009
27,670
24,198
–
95
51,963
December
31, 2010
–
6,485
4,335
36
10,856
December
31, 2009
27,670
24,198
–
158
52,026
As part of the Company’s conversion from a trust to a corporation in 2008, Bonterra assumed approximately
$27,670,000 of investment tax credits (ITC’s) from SRX Post holdings Inc. Due to the depressed commodity
prices as of December 31, 2008, the Company was not able to justify the ability to claim these ITC’s prior
to their expiration. The recovery in the price of crude oil as well as the Company’s success in its horizontal
crude oil development has resulted in significantly higher future anticipated cash flow from Bonterra’s oil
and gas operations and therefore justified that the ITC’s are likely to be claimed in the future. The Company
was able to do so in 2009.
On November 6, 2009, the Company closed the sale of a portion of its Shaunavon oil production to
Eagle Rock Exploration Ltd. (Eagle Rock) (TSXV: ERX). The proceeds of disposition consisted of
$23,729,000 cash and 30,769,200 common shares in Eagle Rock (representing approximately 4.2 percent of
the outstanding common shares of that company at the time). The closing price of the Eagle Rock common
shares on November 6, 2009 was $0.21 resulting in total consideration for the property of $30,191,000. The
book value (net of asset retirement provision) of the property to the Company was approximately $5,993,000
resulting in a gain on sale of $24,198,000. Eagle Rock has since changed its name to Wild Stream
Exploration Inc. (Wild Stream) (TSXV: WSX) and consolidated its common shares on a 30:1 basis.
30
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In February 2010, the Company disposed of its Southeast Saskatchewan Pinto property. The proceeds of
disposition were $5,534,000 cash. At the time of disposition, the Company had a net book value of $120,000
for the property and had an asset retirement obligation related to the property of $371,000 that was
transferred resulting in a gain on sale of property of $5,785,000. In addition, during the third quarter of 2010
the Company disposed of non-producing land for proceeds of $700,000. The Company had no capital costs
associated with this land.
Effective July 6, 2010, Comaplex Minerals Corp. (Comaplex) (a company with common directors and
management with the Company) was acquired by Agnico-Eagle Mines Limited (Agnico-Eagle) (TSX: AEM).
In exchange for Bonterra’s 689,682 common shares in Comaplex, the Company received 689,682 shares in
Geomark Exploration Ltd. (Geomark) (TSXV: GME) (a company with common directors and management
with the Company) and 108,693 common shares in Agnico-Eagle. The value of the Agnico-Eagle shares is
included with investments while the value of the Geomark shares is listed as investment in related party on
the December 31, 2010 balance sheet.
During 2010, Bonterra disposed of a portion of its investments. Gross proceeds from the sales were
$5,603,000 resulting in an accounting gain of $4,335,000. The Company holds in excess of $11,000,000 worth
of investments as of December 31, 2010.
PRODUCTION COSTS
($ 000s except $ per BOE)
Production costs
$ per BOE
Three Months Ended
Twelve Months Ended
December
31, 2010
8,699
15.55
September
30, 2010
8,069
15.47
December
31, 2009
6,870
15.30
December
31, 2010
30,451
14.82
December
31, 2009
27,848
15.28
Total production costs in 2010 have increased by $2,603,000 over 2009. The increase is substantially due to
approximately $2.5 million in 2007, 2008 and 2009 natural gas processing fee adjustments billed to Bonterra
during 2010 by the operator of several of the natural gas plants that the Company uses to process its natural
gas. On a per BOE basis, production costs have declined in 2010 compared to 2009 by $0.46, and excluding
the natural gas processing fee adjustments, by $1.66 mainly due to higher rate horizontal wells, field
optimization and cost control procedures implemented by Bonterra.
31
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Total operating costs increased in the fourth quarter of 2010 compared to the prior quarter due
primarily to the billing of 2009 natural gas processing charge adjustments of approximately $800,000
(see above discussion).
GENERAL AND ADMINISTRATIVE EXPENSE
($ 000s except $ per BOE)
G&A Expense
$ per BOE
Three Months Ended
Twelve Months Ended
December
31, 2010
1,468
2.62
September
30, 2010
1,204
2.31
December
31, 2009
1,623
3.61
December
31, 2010
5,406
2.63
December
31, 2009
4,458
2.45
General and administrative (G&A) expenses increased 21.3 percent in 2010 compared to 2009. The Company
provides administrative services to Geomark and Pine Cliff Energy Ltd. (Pine Cliff) (TSXV: PNE), companies
that share common directors and management. Please refer to discussion under Related Party Transactions
for details.
The Company’s significant general and administrative costs include employee compensation; professional
services such as legal, engineering and accounting; computer services, bank charges and occupancy costs.
Employee compensation expense increased by approximately 21 percent ($742,000) in 2010 from 2009 due to
a larger bonus accrual and an increase in staff. The Company’s bonus plan consists of cash payments equal
to three percent of before tax net earnings (excluding the 2009 investment tax credit recovery of $27,670,000)
to be paid to employees and key consultants. Bonus payments to individuals are based on performance.
Costs associated with professional services were relatively unchanged year over year. Costs associated
with computer services (decrease of $72,000) and bank charges (decrease of $43,000) were offset by
increased occupancy cost of $138,000.
The quarter over quarter increase of $264,000 was primarily due to increased employee and
consultant compensation.
During the year the Company capitalized $Nil (2009 – $460,000) of general and administrative costs.
32
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INTEREST EXPENSE
($ 000s except $ per BOE)
Interest on long-term debt
Other interest
Interest Expense
$ per BOE
Three Months Ended
Twelve Months Ended
December
31, 2010
654
192
846
1.51
September
30, 2010
562
140
702
1.35
December
31, 2009
620
118
738
1.64
December
31, 2010
2,244
555
2,799
1.35
December
31, 2009
2,833
461
3,294
1.81
Bank debt at December 31, 2010 was $70,386,000 (December 31, 2009 – $59,823,000). 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 Company has also borrowed $32,000,000 (December 31, 2009 – $23,500,000) from two related parties as
well as $15,000,000 (December 31, 2009 – Nil) from a private investor. Please see Related Party Transactions
and Liquidity and Capital Resources sections for further details.
Interest charges decreased in 2010 as decreased interest rates more than overset the increase in average
outstanding debt balance. The interest rate decrease is due to a reduced bank rate resulting from a better
debt to cash flow ratio and to increases in loans from related parties and private investments which have a
lower interest rate than bank loans.
Quarter over quarter saw an increase in interest charges due to increased debt balances resulting from the
Company’s fourth quarter capital program.
Effective April 9, 2010, the Company renewed its bank facility under similar terms and conditions with
the exception of extending the revolving period to April 27, 2012, reducing its interest and bank fees and
amending one of the material covenants (see below).
The interest rate on the credit facility is calculated as follows:
Consolidated Total Funded Debt (1)
to Consolidated Cash flow Ratio
Canadian Prime Rate Plus (2)
Bankers’ Acceptances Rate Plus (2)
Level I
Under
1.0:1
100
225
Level II
Over
1.0:1 to 1.5:1
150
275
Level III
Over
1.5:1 to 2.0:1
175
300
Level IV
Over
2.0:1 to 2.5:1
200
325
Level V
Over
2.5:1
250
375
(1) Consolidated total funded debt excludes related party amounts and subordinated debenture but includes working capital.
Consolidated cash flow is calculated as cash flow according to GAAP excluding adjustments for non-cash working
capital items.
(2) Numbers in table represent basis points.
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Consolidated total funded debt to consolidated cash flow ratio shall be calculated each fiscal quarter and
the interest rates adjusted effective as of the first day of the fiscal quarter commencing immediately after
the fiscal quarter in which Bonterra files a compliance certificate containing the ratio, with each such
adjustment to be effective until the next such adjustment.
As of December 31, 2010 the Company will continue to qualify for the Level I interest rates.
The following is a list of the material covenants of the Company’s bank facility:
• The Company is required to not exceed $120,000,000 in consolidated debt (includes negative
working capital but excludes debt to related parties and the subordinated promissory note). As of
December 31, 2010 the Company had consolidated total funded debt of $52,995,000.
• Total dividends paid in the current quarter and the three previous quarters shall not exceed 80 percent
of the previous four quarters’ cash flow as defined under GAAP. Dividend payments totalled $46,867,000
during the quarter and the three previous quarters while cash flow totalled $68,782,000 during the same
period for an overall payout ratio of 68 percent.
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. The Company issued
only 36,000 stock options during 2010 resulting in a reduction of stock-based compensation by $428,000.
As of December 31, 2010, the Company has a total of $290,000 of stock-based compensation to amortize over
the next two years.
The 36,000 common share options were issued with a weighted average exercise price of $36.98 per share
and a fair value of $5.67 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 1.9 percent
(2009 – 1.4 percent), expected weighted average volatility of 33 percent (2009 – 33 percent), expected
weighted average life of 2.8 years (2009 – 3.0 years) and an annual dividend rate based on the dividends
paid to the shareholders during the year.
34
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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, the Company now uses a 10 percent declining basis for
depreciation calculation. The Company changed from the straight line basis due to the increasing reserve
life index which continues to indicate a longer service life for its production assets.
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, 2010, the estimated total undiscounted amount required to settle the asset retirement
obligations was $62,579,000 (2009 – $64,482,000). The $1,903,000 decrease is due primarily to a reduction in
anticipated inflation from two percent to one and a half percent.
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 $2,827,000, while a one percent decrease in the risk adjusted rate would increase the asset
retirement obligation by $3,875,000.
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.
35
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O
N
T
E
R
R
A
E
N
E
R
Y
C
O
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P
.
2
0
1
0
A
N
N
U
A
L
R
E
P
O
R
T
For the fiscal year ending December 31, 2010, the Company expensed $22,278,000 (2009 – $19,277,000) for the
above-described items. The increase is predominately due to increased production volumes resulting from
the Company’s Pembina Cardium horizontal oil well drill program. The higher BOE depletion charges on
the horizontal wells are primarily due to lack of production history on these wells resulting in lower proved
reserves being assigned but with substantial probable reserves being assigned. The Company’s policy is
to deplete the cost of the wells based on proved reserves. When there is longer production history on the
horizontal wells there may be a conversion of the probable reserves to proven reserves which would result in
a reduction of depletion charges per BOE in future years.
The Company continues to have relatively low finding and development costs. Based on year end reserves,
the Company’s average cost of proved reserves is $7.80 (2009 – $6.62) per BOE.
The Company currently has an estimated reserve life for its proved developed producing reserves of
10.1 (2009 – 11.7) years calculated using the Company’s gross reserves (prior to allowance for royalties)
based on the third party engineering report dated December 31, 2010 and using fourth quarter 2010
average production rates of 6,080 BOE per day (2009 – 4,879 BOE per day). Based on total proved reserves
the Company has a 12.9 (2009 – 14.2) year reserve life and on a proved and probable basis the reserve life
increases to 17.8 (2009 – 20.1) years. These figures are some of the longest reserve life indexes (excluding
oil sands) in the Canadian oil and gas industry.
TAXES
The current tax provision relates to a resource surcharge of $141,000 (2009 – $282,000) payable to the
Province of Saskatchewan. The resource surcharge is calculated as a flat percent of revenues generated
from the sale of petroleum products produced in Saskatchewan. The resource surcharge rate is three
percent in 2010. In 2009, a capital tax amount of $269,000 payable to the Province of Quebec was incurred
due to the 2008 reorganization for the conversion from a Trust to a Corporation. The capital tax payable to
the Province of Quebec was a one-time charge.
36
T
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O
P
E
R
L
A
U
N
N
A
0
1
0
2
.
P
R
O
C
Y
R
E
N
E
A
R
R
E
T
N
O
B
The Company has the following tax pools, which may be used to reduce taxable income in future years,
limited to the applicable rates of utilization:
($ 000s)
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
25,441
$
6,849
1,424
19,074
109,642
11,140
39,985
222,596
436,151
$
(1) Income tax losses carried forward expire in the following years; 2024 – $3,347,000, 2025 – $7,532,000, 2026 – $46,671,000,
2027 – $117,189,000, 2028 – $34,726,000, 2029 – $13,131,000.
In addition to the above pools, the Company also has $27,670,000 (December 31, 2009 – $27,670,000)
remaining of investment tax credits that expire in the following years; 2019 – $3,469,000, 2020 – $3,059,000,
2021 – $4,667,000, 2022 – $3,909,000, 2023 – $3,155,000, 2024 – $1,995,000, 2025 – $2,257,000, 2026 – $2,405,000,
2027 – $2,009,000, 2028 – $745,000.
The Company also has $141,417,000 (December 31, 2009 – $143,061,000) of capital loss carry forwards which
can only be claimed against taxable capital gains.
The amount and timing of reversals of temporary differences will also depend on the Company’s
future operating results and its future acquisitions and dispositions of assets and liabilities. A significant
change in any of the preceding assumptions could materially affect the Company’s estimate of the future
income tax asset.
37
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T
E
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R
A
E
N
E
R
Y
C
O
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P
.
2
0
1
0
A
N
N
U
A
L
R
E
P
O
R
T
NET EARNINGS
($ 000s except $ per share)
Net Earnings
$ per share – Basic
$ per share – Fully Diluted
Three Months Ended
Twelve Months Ended
December
31, 2010
14,213
0.75
0.73
September
30, 2010
12,724
0.68
0.66
December
31, 2009
52,136
2.88
2.85
December
31, 2010
49,864
2.65
2.58
December
31, 2009
68,563
3.81
3.78
Bonterra’s net earnings for the year ended December 31, 2010 represents a 27.3 percent decrease over
the Company’s 2009 net earnings. Two significant factors contributing to the 2009 net earnings were the
Company’s recordings of the investment tax credit recovery of $27,670,000 and the sale of a portion of the
Company’s Shaunavon production for a gain of $24,198,000; all of which occurred in the fourth quarter of
2009. Excluding these items (net of 29.15 percent tax effect), 2009 net earnings would decrease by $36,748,000
from $68,563,000 to an adjusted net earnings of $31,815,000. In 2010, a gain on sale of property of $4,665,000
(net of 28.06 percent tax effect) was incurred. Excluding these items, Bonterra’s 2010 net earnings increased
by $13,384,000, or 42 percent, over 2009.
Higher revenues resulting from increased production and increased commodity prices were the main
reason for the significant net earnings increase. The Company continues to return in excess of 40 percent
of its gross crude oil and natural gas revenues in net earnings. The Company’s low capital costs per BOE
of reserves combined with the Company’s low production decline rates should allow for continued
positive earnings.
OTHER COMPREHENSIVE INCOME
Other comprehensive income for 2010 consists of an unrealized gain before tax on investments
(including investments in a related party) of $8,602,000 (2009 – $697,000) including a fourth quarter
unrealized gain before tax of $2,642,000 relating to an increase in the investment’s fair value. The Company
also sold some of these investments, which comprise of marketable securities, for a realized gain before
tax of $4,335,000 (2009 – $Nil) including a fourth quarter realized gain before tax of $782,000. Realized gains
decrease other comprehensive income, as the gains are transferred to net earnings. Other comprehensive
income varies from net earnings by unrealized changes in the fair value of Bonterra’s holdings of
investments including the investment in Geomark, net of tax.
38
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A
U
N
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A
0
1
0
2
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P
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O
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Y
R
E
N
E
A
R
R
E
T
N
O
B
CASH FLOW FROM OPERATIONS
($ 000s except $ per share)
Cash flow from operations
$ per share – basic
$ per share – fully diluted
Three Months Ended
Twelve Months Ended
December
31, 2010
16,987
0.89
0.86
September
30, 2010
17,558
0.93
0.91
December
31, 2009
13,673
0.76
0.75
December
31, 2010
66,262
3.52
3.42
December
31, 2009
38,893
2.16
2.15
Cash flow from operations increased 70 percent year over year, mainly due to increased production and
crude oil prices. Fourth quarter cash flow decreased by $571,000 over Q3 due to adjustments of $3,335,000
relating to changes in non-cash working capital items. The Company has not entered into any risk
management agreements and as such is fully exposed to changes in commodity prices and exchange rates.
CASH NETBACKS
The following table illustrates the Company’s annual cash netback:
($ per BOE)
Production volumes (BOE)
Gross production revenue
Royalties
Production costs
Field netback
General and administrative
Interest and taxes
Cash netback
2010
2,054,375
57.92
$
(5.57)
(14.82)
37.53
(2.63)
(1.43)
$ 33.47
2009
1,822,628
47.04
$
(4.07)
(15.28)
27.69
(2.45)
(2.11)
23.13
$
39
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E
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E
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Y
C
O
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2
0
1
0
A
N
N
U
A
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T
The following table illustrates the Company’s cash netback for the three months ended:
($ per BOE)
Production volumes (BOE)
Gross production revenue
Royalties
Production costs
Field netback
General and administrative
Interest and taxes
Cash netback
$
December 31, September 30,
2010
521,601
54.32
(5.65)
(15.47)
33.20
(2.31)
(1.39)
29.50
2010
559,400
$ 61.15
(5.09)
(15.55)
40.51
(2.62)
(1.58)
$ 36.31
$
RELATED PARTY TRANSACTIONS
As a result of the acquisition of Comaplex by Agnico-Eagle, the loan agreement and Bonterra common
shares previously held by Comaplex were transferred to Geomark. A new management agreement was
entered into between Bonterra and Geomark with the only amendment to the former agreement with
Comaplex being a reduction in the monthly management fee from $30,000 to $22,500.
Geomark and Comaplex combined paid a management fee to the Company of $316,500 (2009 – $330,000).
Geomark also shares office rental costs and reimburses the Company for costs related to employee benefits
and office materials. In addition, Geomark owns 204,633 (Comaplex December 31, 2009 – 204,633) common
shares in the Company. Services provided by the Company included executive services (chief executive
officer, president and vice president, finance duties), accounting services, oil and gas administration and
office administration. All services performed were charged at estimated fair value. At December 31, 2010,
Geomark owed the Company $35,000 (Comaplex December 31, 2009 – $105,000).
As of December 31, 2010, Geomark has loaned the Company $20,000,000 (Comaplex December 31, 2009 –
$12,000,000). The loan is unsecured, bears interest at Canadian chartered bank prime less 5/8th of a percent
and has no set repayment terms. The loan cannot be repaid, or demanded to be paid by Geomark, unless
the Company has sufficient available borrowing limits under the Company’s credit facility. Interest paid on
both the Comaplex and Geomark loans during 2010 was $313,000 (2009 – $194,000). This loan results in being
a substantial benefit to Bonterra and to Geomark. The interest paid to Geomark by Bonterra is substantially
lower than bank interest and for Geomark, the interest earned is substantially higher than Geomark would
receive by investing in bank instruments such as BA’s or GIC’s.
40
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A
U
N
N
A
0
1
0
2
.
P
R
O
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Y
R
E
N
E
A
R
R
E
T
N
O
B
The Company also has a management agreement with Pine Cliff. Pine Cliff has common directors
and management with the Company. Pine Cliff paid a management fee to the Company of $90,000
(2009 – $120,000). Services provided by the Company include executive services (CEO, 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. At December 31, 2010, the Company had an account receivable from Pine Cliff of $1,000
(December 31, 2009 – $1,000).
As of December 31, 2010, the Company’s CEO and major shareholder has loaned the Company $12,000,000
(December 31, 2009 – $11,500,000). The loan is unsecured, bears interest at Canadian chartered bank prime
less 5/8th of a percent and has no set repayment terms. The loan cannot be repaid, or demanded to be paid
by the Company’s CEO, unless the Company has sufficient available borrowing limits under the Company’s
credit facility. Interest paid on this loan during 2010 was $242,000 (2009 – $209,000). This loan results in being
a substantial benefit to Bonterra and to the CEO. The interest paid to the CEO by Bonterra is substantially
lower than bank interest and for the CEO, the interest earned is substantially higher than the CEO would
receive by investing in bank instruments such as BA’s or GIC’s.
LIQUIDITY AND CAPITAL RESOURCES
During 2010, the Company incurred capital costs of $76,914,000 (2009 – $28,726,000) net of drilling
tax credits. The costs relate primarily to the drilling, completing, tie-in and equipping of 22 gross (20.0 net)
operated Pembina Cardium horizontal wells as well as its proportion of the non-operated drilling costs.
During the fourth quarter of 2010, Bonterra elected to drill two additional operated horizontal oil wells and
the operator of non-operated property also added two additional (0.3 net to Bonterra) horizontal oil wells to
its drilling program.
The Company currently has plans to spend approximately $50,000,000 to $60,000,000 on its 2011 Pembina
Cardium horizontal well program and non-operated capital programs. Bonterra anticipates funding the 2011
capital program out of cash flow, proceeds from the exercise of employee stock options, sale of investments
and the Company’s line of credit.
As of December 31, 2010 and December 31, 2009, the Company has a bank facility consisting of a
$100,000,000 syndicated revolving credit facility and a $20,000,000 non-syndicated revolving credit facility.
Amounts drawn under these facilities at December 31, 2010 were $70,386,000 (December 31, 2009 –
$59,823,000). The interest rates on the outstanding debt as of December 31, 2010 were 4.0 percent and
3.4 percent on the Company’s Canadian prime rate loan and Bankers’ Acceptances, respectively. For
information related to interest rate levels and material covenants please refer to the discussion under
Interest Expense.
41
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O
N
T
E
R
R
A
E
N
E
R
Y
C
O
R
P
.
2
0
1
0
A
N
N
U
A
L
R
E
P
O
R
T
On October 4, 2010, the Company borrowed $15,000,000 from a private investor. In exchange Bonterra has
issued a Subordinated Promissory Note for $15,000,000. The terms of the Subordinated Promissory Note are
that it bears interest at three percent, is not callable by the investor prior to January 4, 2012 at which time it
will be a demand note until its maturity of April 4, 2012, and can be repaid at the option of the Company at
any time. Security consists of a floating demand debenture totaling $15,000,000 over all of the Company’s
assets and is subordinated to any and all claims in favor of the syndicate of senior lenders providing credit
facilities to the Company.
The Company is authorized to issue an unlimited number of common shares without nominal or par value.
Transactions during the years 2010 and 2009 in the shares of the common stock of the Company are
as follows:
Common Shares
Balance, beginning of year
Issued pursuant to private placement
Issued on acquisition of Cobalt (Note 4)
Issued pursuant to Company share option plan
Transfer of contributed surplus to share capital
Issue costs for private placement
Future tax effect of share issue costs
Balance, end of year
2010
Amount
($ 000s)
121,955
–
–
12,377
698
–
–
135,030
Number
18,619,641
–
–
599,900
–
–
–
19,219,541
2009
Amount
($ 000s)
99,530
17,996
3,207
1,898
103
(1,046)
267
121,955
Number
17,257,603
1,068,000
201,438
92,600
–
–
–
18,619,641
The Company provides a stock option plan for its directors, officers, employees and consultants. Under the
plan, the Company may grant options for up to 1,921,954 common shares (2009 – 1,861,964). 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.
42
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R
O
P
E
R
L
A
U
N
N
A
0
1
0
2
.
P
R
O
C
Y
R
E
N
E
A
R
R
E
T
N
O
B
A summary of the status of the Company’s stock option plan as of December 31, 2010 and 2009, and changes
during the twelve month periods ended on those dates is presented below:
December 31, 2010
December 31, 2009
Outstanding at beginning of period
Options granted
Options cancelled
Options exercised
Outstanding at end of period
Options exercisable at end of period
$
Weighted-
Average
Exercise
Price
20.36
36.98
34.66
20.63
20.56
20.50
$
$
Options
1,330,900
36,000
(20,000)
(599,900)
747,000
255,500
Options
1,390,500
33,000
–
(92,600)
1,330,900
370,900
$
Weighted-
Average
Exercise
Price
20.50
14.90
–
20.50
20.36
20.50
$
$
The following table summarizes information about options outstanding at December 31, 2010:
Options Outstanding
Options Exercisable
Number
Outstanding
at 12/31/10
22,000
719,000
6,000
747,000
Weighted-
Average
Remaining
Contractual
Life
2.1 years
1.9 years
2.5 years
1.9 years
Range of Exercise Prices
$ 14.90
20.50
48.60
$ 14.90 - $ 48.60
COMMITMENTS
$
Weighted-
Average
Price
14.90
20.50
48.60
20.56
$
Number
Exercisable
at 12/31/10
–
255,500
–
255,500
Weighted-
Average
Exercise
Price
–
20.50
–
20.50
$
$
The Company has no contractual obligations that last more than a year other than its office lease
agreements which are as follows:
Lease Obligations ($000s)
Year 1
Year 2
Year 3
Year 4
Year 5
Total
$
$
967
874
537
–
–
2,378
FINANCIAL REPORTING UPDATE
International Financial Reporting Standards (IFRS)
In October 2009, the Accounting Standards Board issued a third and final IFRS Omnibus Exposure
Draft confirming that publicly accountable enterprises will be required to apply IFRS, in full and without
modification, for all financial periods beginning January 1, 2011. The adoption date of January 1, 2011 will
require the restatement, for comparative purposes, of amounts reported by Bonterra for the year ended
December 31, 2010, including the opening balance sheet as at January 1, 2010.
The Company commenced the process to transition its financial statements from current Canadian GAAP
to IFRS in 2008. The Company’s project consists of three key phases: the scoping and diagnostic phase, the
impact analysis and evaluation phase and the implementation phase.
• Scoping and diagnostic phase – this phase involves performing a high level impact analysis to identify
areas that may be affected by the transition to IFRS. The results of this analysis were given a priority
ranking according to their complexity and the amount of time required to assess the impact of changes
in transitioning to IFRS. The Company identified the following high impact and medium impact areas:
43
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A
E
N
E
R
Y
C
O
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P
.
2
0
1
0
A
N
N
U
A
L
R
E
P
O
R
T
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
44
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P
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R
L
A
U
N
N
A
0
1
0
2
.
P
R
O
C
Y
R
E
N
E
A
R
R
E
T
N
O
B
•
Impact analysis and evaluation phase – during this phase, items identified in the diagnostic were
addressed according to the priority ranking assigned to them. The Company conducted analysis of
policy choices allowed under IFRS and their impact to the financial statements. Additionally, certain
potential differences were further investigated to assess if there was any broader impact to the
Company’s net earnings, debt agreements, compensation arrangements or management reporting
systems. The impact analysis and evaluation phase was concluded by management pending the
Audit Committee of the Board of Directors approval on all accounting policies chosen by management.
Since Bonterra uses successful efforts method of accounting on its petroleum and natural gas
properties under Canadian GAAP, the audit committee of the Board of Directors gave management
the directive to chose policies that will retain as much comparability to the accounting policies chosen
under Canadian GAAP.
•
Implementation phase – involved implementation of all changes approved in the impact analysis and
evaluation phase, which included minor changes to existing information systems, the creation of new
business processes and the modification of training staff impacted by the conversion.
Since its inception, the project has been led by the financial reporting group with sponsorship from the
executive team. The Company has effectively completed all phases of its IFRS transition project and
continues to review its draft IFRS financial statements and disclosures for completeness and quality
assurance. The Audit Committee will review and approve the Company’s IFRS accounting policy selections
and adjustments prior to the release of the first quarter of 2011 financial statements and MD&A.
First Time Adoption of IFRS
Most adjustments required on transition to IFRS will be made retrospectively against opening retained
earnings as of the date of the first comparative balance sheet presented, based on standards applicable
at that time. IFRS 1 provides entities adopting IFRS for the first time with certain optional exemptions and
mandatory exceptions to the general requirement for full retrospective application of IFRS. Management
has analyzed the various accounting policy choices available under IFRS 1 and has implemented those
determined to be the most appropriate for Bonterra. Accordingly, it has applied the following IFRS 1
exemptions in its IFRS opening balance sheet:
• Business combinations (IFRS 1) – provides the option to apply IFRS 3, Business Combinations,
retrospectively or prospectively from the Transition Date. The retrospective basis would require
restatement of all business combinations that occurred prior to the Transition Date. The Company
elected not to retrospectively apply IFRS 3 to business combinations that occurred prior to its Transition
Date and such business combinations have not been restated. Any goodwill arising on such business
combinations before the Transition Date has not been adjusted from the carrying value previously
determined under Canadian GAAP as a result of applying these exemptions.
45
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A
E
N
E
R
Y
C
O
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P
.
2
0
1
0
A
N
N
U
A
L
R
E
P
O
R
T
• Share-based payments (IFRS 2) – encourages the application of its provisions to equity instruments
granted on or before November 7, 2002, but permits the application only to equity instruments granted
after November 7, 2002 that had not vested by the Transition Date. The Company elected to avail itself
of the exemption provided under IFRS 1 and applied IFRS 2 for all equity instruments granted after
November 7, 2002 that had not vested by its Transition Date. Further, the Company applied IFRS 2 for
all liabilities arising from share-based payment transactions that existed at its Transition Date. This
election has no material effect on the Company.
• Borrowing Costs (IAS 23) – requires an entity to capitalize the borrowing costs related to all qualifying
assets for which the commencement date for capitalization is on or after January 1, 2010. Due
to the short time frame to drill a well and place it on production this election has no material effect
on the Company.
•
Leases (IAS 17) – requires an entity to assess arrangements outstanding at the Transition Date. It also
requires a determination of the appropriate lease classification in accordance with IAS 17, should
an arrangement containing a lease be identified as part of the International Financial Reporting
Interpretations Committee (IFRIC) 4, Determining Whether an Arrangement Contains a Lease,
application. This election has no effect on the Company.
• Decommissioning Liabilities Included in the Cost of Property, Plant and Equipment (IAS 37) –
Provisions, Contingent Assets and Contingent Liabilities requires an entity to estimate the statutory and
constructive liabilities that existed at the Transition Date, discounted at the risk free rate. The Company
has revalued its asset retirement obligation under GAAP to IFRS. The Company also determined it had
no unrecorded statutory or constructive obligations.
The following is a listing of key areas where accounting policies differ and where accounting policy
decisions are necessary that will significantly impact our reported financial position and results
of operations:
• Deferred credit – On November 12, 2008, Bonterra Energy Income Trust (the “Trust”) was acquired by
Bonterra Oil & Gas Ltd. through a reverse takeover by the Trust of SRX Post Holdings Inc. (SRX). This
transaction gave the Company additional tax pools in excess of the purchase price. Under Canadian
GAAP this purchase was considered an acquisition of an asset and not a business combination and
therefore the resulting gain on acquisition had to be deferred and charged to net earnings on the same
basis as the acquired assets. Under IFRS the deferred gain does not meet the definition of a liability and
the deferred credit of $55,131,000 ($7,363,000 of the deferred credit being a current liability) is recorded
as a decrease to deficit.
46
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L
A
U
N
N
A
0
1
0
2
.
P
R
O
C
Y
R
E
N
E
A
R
R
E
T
N
O
B
• Asset exchange revaluation – In 2007, the Company exchanged certain oil and gas assets in Alberta
for oil and gas assets in Saskatchewan that were recorded at book value under Canadian GAAP.
Under IFRS the values of the assets received are to be recorded at fair value, this resulted in
$14,310,000 increase in the cost of the property and equipment and a $2,553,000 increase in the
accumulated depletion and amortization of the property and equipment on the January 1, 2010
opening balance sheet. As a result of this change, the Company’s deferred tax asset decreased by
$3,446,000 million and the net offset is recorded as a decrease to deficit.
• Asset retirement obligation (ARO) – Under IFRS, the Company is required to revalue its entire liability
for asset retirement costs at each balance sheet date using a current liability-specific discount rate,
which can generally be interpreted to mean the current risk-free rate of interest. Under Canadian
GAAP, obligations are discounted using a credit-adjusted risk-free rate and, once recorded, the asset
retirement obligation is not adjusted for future changes in discount rates. At January 1, 2010 Bonterra’s
total of its asset retirement obligations will increase by $3,492,000 to $21,282,000 from $17,790,000,
as the liability is revalued to reflect the estimated risk free rate of interest at that time of 4.1 percent.
The offsetting ARO asset cost will be adjusted by $3,540,000 due to the changes in the ARO liability.
The ARO asset would also incur $1,804,000 more accumulated depletion. As a result of these changes,
Bonterra’s deferred tax asset is increased by $442,000 and the net offset is recorded as an increase
to deficit.
•
•
Future income tax asset (liability) – Under Canadian GAAP, Bonterra separates future income tax
assets (liabilities) between current, which as of January 1, 2010 was a $11,889,000 asset and long-term,
which as of January 1, 2010 was a $58,265,000 asset. Under IFRS, all future income tax assets (liabilities)
(which will be renamed “deferred tax”) will all be classified as long-term.
Impairment of property and equipment (P&E) assets – Canadian GAAP generally uses a two-step
approach to impairment testing; first comparing asset carrying values with undiscounted future
cash flows to determine whether an impairment exists, and then measuring impairment by comparing
asset carrying values to their fair value (which is calculated using discounted cash flows). IFRS uses
a one-step approach for testing and measuring impairment, with asset carrying values compared
directly with the higher of fair value less costs to sell and value in use down to a cash generating unit
(CGU) level. A cash generating unit is the smallest group of assets that generates cash flows largely
independent of other assets or group of assets. The impairment test categories of CGUs under IFRS
is materially similar to the impairment groupings already chosen under Canadian GAAP, since the
Company is using the successful efforts method of accounting for its P&E assets. The discount rate
however, to determine fair value could materially differ under IFRS versus Canadian GAAP. As of
January 1, 2010 and December 31, 2010, the Company does not anticipate an impairment of P&E
assets under IFRS.
47
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2
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A
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The table below summarizes the Company’s January 1, 2010 balance sheet under Canadian GAAP and the
transitional entries required to present the opening balance sheet under IFRS. Bonterra has not yet prepared
a full set of annual financial statements under IFRS, therefore, amounts disclosed are unaudited.
($ 000s)
Current assets
Long-term assets
Total assets
Current liabilities
Long-term liabilities
Equity
Total liabilities and equity
Canadian
IFRS
GAAP Adjustments
(11,889)
21,919
10,030
39,569
254,418
293,987
49,731
125,382
118,874
293,987
(7,363)
(44,277)
61,670
10,030
IFRS
27,680
276,337
304,017
42,368
81,105
180,544
304,017
In addition to accounting policy differences, the Company’s transition to IFRS is expected to impact its
internal control over financial reporting, disclosure controls and procedures, certain of Bonterra’s business
activities and IT systems as follows:
•
Internal control over financial reporting (ICFR) – Bonterra is currently in the process of reviewing its
ICFR documentation and is identifying instances where controls must be amended or added in order to
address the accounting policy changes required under IFRS. No material changes in control procedures
are expected as a result of transition to IFRS.
• Disclosure controls and procedures – Bonterra has assessed the impact of transition to IFRS on its
disclosure controls and procedures and has not identified any material changes required in its control
environment. It is expected that there will be increased note disclosure around certain financial
statement items than what is currently required under Canadian GAAP. Management is currently
drafting its IFRS note disclosure in accordance with current IFRS standards and continues to monitor
requirements put forth by the International Accounting Standards Board (IASB) in discussion papers
and exposure drafts for future disclosure requirements. Throughout the transition process, Bonterra
has carefully considered its stakeholders’ information requirements and will continue to ensure that
adequate and timely information is provided to meet these needs.
• Business activities – Management has been cognizant of the upcoming transition to IFRS, and as such,
has worked with its counterparties and lenders to ensure that any agreements that contain references
to Canadian GAAP financial statements are modified to allow for IFRS statements. Based on the
changes to the Company’s accounting policies, no issues are expected to arise with the existing wording
of debt covenants and related agreements as a result of the conversion to IFRS.
48
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N
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B
•
IT systems – Bonterra has completed the accounting system updates required in order to prepare
for IFRS reporting. Since the Company has been using successful efforts method to account for its
petroleum and natural gas assets, no significant modifications were deemed critical in order to allow
for reporting of both Canadian GAAP and IFRS statements in 2010.
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 2011:
U.S. $1.00 per barrel
Canadian $0.10 per MCF
Change of Canadian $0.01/U.S. $ exchange rate
(1) Based on year end outstanding common shares of 19,219,541.
ADDITIONAL INFORMATION
Cash
Flow
$ 1,376,000
$
349,000
$ 1,161,000
Cash Flow
Per Share (1)
0.072
0.018
0.060
$
$
$
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.
MANAGEMENT’S
RESPONSIBILITY
FOR FINANCIAL
STATEMENTS
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 auditor’s 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.
49
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George F. Fink
Chief Executive Officer
March 22, 2011
Garth E. Schultz
Chief Financial Officer
March 22, 2011
INDEPENDENT
AUDITOR’S
REPORT
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N
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B
To the Shareholders of Bonterra Energy Corp.
We have audited the accompanying consolidated financial statements of Bonterra Energy Corp., which comprise
the consolidated balance sheets as at December 31, 2010 and 2009, and the consolidated statements of shareholders’
equity, operations and deficit, comprehensive income and cash flow for the years then ended, and the notes to the
consolidated financial statements.
Management’s Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in
accordance with Canadian generally accepted accounting principles, and for such internal control as management
determines is necessary to enable the preparation of consolidated financial statements that are free from material
misstatement, whether due to fraud or error.
Auditor’s Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We
conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require
that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about
whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the
consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the
assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud
or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation
and fair presentation of the consolidated financial statements in order to design audit procedures that are
appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the
entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the
reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of
the consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for
our audit opinion.
Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of
Bonterra Energy Corp. as at December 31, 2010 and 2009 and the results of its operations and its cash flows for the
years then ended in accordance with Canadian generally accepted accounting principles.
Calgary, Alberta
March 22, 2011
Chartered Accountants
CONSOLIDATED
BALANCE
SHEETS
As at December 31 ($ 000s)
ASSETS
Current
Accounts receivable (Note 14)
Crude oil inventory
Prepaid expenses
Future income tax asset (Note 10)
Investments (Note 5 and 6)
Investment in related party (Note 5)
Investment in related party (Note 5)
Restricted cash
Investment tax credit receivable (Note 10)
Future income tax asset (Note 10)
Property and Equipment (Note 6)
Petroleum and natural gas properties and related equipment
Accumulated depletion and depreciation
Net Property and Equipment
LIABILITIES
Current
Accounts payable and accrued liabilities
Due to related parties (Note 7)
Deferred credit (Note 10)
Subordinated promissory note (Note 8)
Bank debt (Note 9)
Deferred credit (Note 10)
Asset retirement obligations (Note 11)
Commitments, Contingencies and Guarantees (Note 16)
Shareholders’ Equity (Note 12)
Share capital
Contributed surplus
Deficit
Accumulated other comprehensive income (Note 13)
Total Shareholders’ Equity
See the accompanying notes to the consolidated financial statements
On behalf of the Board:
George F. Fink
Director
Bill Woodward
Director
51
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A
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N
U
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O
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T
2010
2009
17,345
487
1,631
22,889
11,471
–
53,823
814
–
27,670
30,011
332,141
(109,315)
222,826
335,144
16,839
32,000
19,586
68,425
15,000
70,386
25,850
17,070
196,731
135,030
3,135
138,165
(5,454)
5,702
248
138,413
335,144
14,713
431
3,247
11,889
4,462
4,827
39,569
–
812
27,670
58,265
255,840
(88,169)
167,671
293,987
18,868
23,500
7,363
49,731
–
59,823
47,769
17,790
175,113
121,955
3,350
125,305
(8,451)
2,020
(6,431)
118,874
293,987
52
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A
U
N
N
A
0
1
0
2
.
P
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O
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Y
R
E
N
E
A
R
R
E
T
N
O
B
CONSOLIDATED
STATEMENTS OF
SHAREHOLDERS’
EQUITY
For the Years Ended December 31 ($ 000s)
Shareholders’ equity, beginning of year
Comprehensive income for the year
Common Shares issued pursuant to private placement
Common Shares issued on acquisition
Common Shares issued pursuant to Company share option plan
Stock-based compensation expense
Dividends declared
Shareholders’ Equity, End of Year
CONSOLIDATED
STATEMENTS
OF OPERATIONS
AND DEFICIT
For the Years Ended December 31 ($ 000s except $ per share)
Revenue and Other Income
Oil and gas sales
Royalties
Investment tax credit recovery
Gain on sale of property (Note 6)
Gain on sale of investments
Interest and other
Expenses
Production costs
General and administrative
Interest on long-term debt (Notes 8 and 9)
Other interest (Note 7)
Stock-based compensation
Depletion, depreciation and accretion
Earnings Before Taxes
Taxes (Note 10)
Current
Future
Net Earnings for the Year
Deficit, beginning of year
Dividends declared and paid
Deficit, end of year
Net Earnings Per Share – Basic (Note 12)
Net Earnings Per Share – Diluted (Note 12)
See the accompanying notes to the consolidated financial statements
2010
118,874
53,546
–
–
12,377
483
(46,867)
138,413
2009
56,777
69,163
17,217
3,207
1,898
911
(30,299)
118,874
2010
2009
118,980
(11,437)
–
6,485
4,335
36
118,399
30,451
5,406
2,244
555
483
22,278
61,417
56,982
141
6,977
7,118
49,864
(8,451)
(46,867)
(5,454)
2.65
2.58
85,712
(7,414)
27,670
24,198
–
158
130,324
27,848
4,458
2,833
461
911
19,277
55,788
74,536
551
5,422
5,973
68,563
(46,715)
(30,299)
(8,451)
3.81
3.78
CONSOLIDATED
STATEMENTS OF
COMPREHENSIVE
INCOME
For the Years Ended December 31 ($ 000s except $ per share)
Net Earnings for the Year
Other comprehensive income net of income tax
Unrealized gains on investments
(net of income taxes of 1,192, (2009 – 97))
Realized gains on investments transferred to
net earnings (net of income taxes of 607 (2009 – Nil))
Other Comprehensive Income
Comprehensive Income
Comprehensive Income Per Share – Basic (Note 12)
Comprehensive Income Per Share – Diluted (Note 12)
See the accompanying notes to the consolidated financial statements
2010
49,864
7,410
(3,728)
3,682
53,546
2.85
2.77
2009
68,563
600
–
600
69,163
3.84
3.81
53
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A
N
N
U
A
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R
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CONSOLIDATED
STATEMENTS
OF CASH FLOW
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A
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1
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2
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E
N
E
A
R
R
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T
N
O
B
For the Years Ended December 31 ($ 000s)
Operating Activities
Net earnings for the year
Items not affecting cash
Stock-based compensation
Depletion, depreciation and accretion
Gain on sale of property
Gain on sale of investments
Future income taxes
Change in non-cash working capital
Accounts receivable
Crude oil inventory
Prepaid expenses
Accounts payable and accrued liabilities
Restricted cash
Investment tax credit receivable
Asset retirement obligations settled (Note 11)
Cash Provided by Operating Activities
Financing Activities
Increase (decrease) in debt
Due to related parties
Subordinated promissory note
Issue of shares pursuant to private placement
Share issue costs
Stock option proceeds
Dividends
Cash Used in Financing Activities
Investing Activities
Property and equipment expenditures
Proceeds on sale of properties
Proceeds on sale of investments
Restricted term deposit
Change in non-cash working capital
Accounts receivable
Accounts payable and accrued liabilities
Cash Used in Investing Activities
Net cash inflow
Cash, beginning of year
Cash, End of Year
Cash Interest Paid
Cash Taxes Paid
See the accompanying notes to the consolidated financial statements
2010
2009
49,864
68,563
483
22,278
(6,485)
(4,335)
6,977
68,782
(2,590)
(39)
1,616
(1,313)
812
–
(1,006)
(2,520)
66,262
10,563
8,500
15,000
–
–
12,377
(46,867)
(427)
(76,914)
6,234
5,603
–
(42)
(716)
(65,835)
–
–
–
2,799
152
911
19,277
(24,198)
–
5,422
69,975
(47)
365
1,057
(4,654
440
(27,670)
(573)
(31,082)
38,893
(35,613)
17,500
–
17,996
(1,046)
1,898
(30,299)
(29,564)
(28,726)
23,729
–
20
(3,613)
(739)
(9,329)
–
–
–
3,294
616
NOTES TO THE
CONSOLIDATED
FINANCIAL
STATEMENTS
55
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For the Years Ended December 31, 2010 and 2009
1. CHANGE OF ORGANIZATION
Effective January 1, 2010, Bonterra Energy Income Trust, a wholly owned Trust of Bonterra Oil & Gas Ltd.,
was wound up into its parent and was amalgamated with Bonterra Energy Corp., a former subsidiary of
the Trust. The continuing entity officially changed its name to Bonterra Energy Corp. (“Bonterra” or the
“Company”) subsequent to finalizing the reorganization.
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 as of December 31, 2009 and wound up on January 1, 2010) and its wholly owned subsidiary
Bonterra Energy Corp. (amalgamated with the Company on January 1, 2010). Inter-company transactions
and balances are eliminated upon consolidation.
Measurement Uncertainty
The preparation of financial statements in accordance 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, accretion and amounts used for impairment 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.
56
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1
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2
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Y
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N
E
A
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T
N
O
B
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.
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 estimated sales price less transportation costs.
Investments
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 at period end.
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.
57
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Depreciation and depletion of capitalized costs of oil and gas producing properties are calculated using
the unit-of-production method. Development and exploration drilling costs are depleted over the remaining
proved reserves.
On January 1, 2010, the Company prospectively began depreciating petroleum and natural gas plant and
equipment using the declining balance method at 10 percent per year, a change from the straight-line
method. The change of estimate was due to declining balance depreciation providing a better reflection
of the estimated service life of the related assets. During 2010, the Company incurred $2,000,000 less
depreciation under the declining balance method, than under the straight-line method.
Furniture, Equipment and Other
On January 1, 2010, the Company prospectively began depreciating these assets using the declining balance
method at rates of 10 percent to 30 percent per year, a change from the straight-line method. The change of
estimate was due to declining balance depreciation providing a better reflection of the estimated service
life of the related assets. During 2010, the Company incurred $141,000 less depreciation under the declining
balance method, than under the straight-line method.
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.
58
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A
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Stock-Based Compensation
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 and are classified
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 instruments 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.
Accounts receivable are classified as loans and receivables which are measured at amortized cost.
Investments and 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, bank debt, subordinated promissory note and amounts due to
related parties are classified as other financial liabilities, which are measured at amortized cost.
59
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2
0
1
0
A
N
N
U
A
L
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P
O
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T
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 based on 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 the
Company 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 years ended
December 31, 2010 and December 31, 2009, the Company did not designate any of its financial instruments
as hedges. There are no risk management contracts outstanding at December 31, 2010 and
December 31, 2009.
Basic and Diluted per Share 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.
3. RECENT ACCOUNTING PRONOUNCEMENTS
The Canadian Accounting Standards Board has confirmed that IFRS will replace Canadian GAAP effective
January 1, 2011, including comparatives for 2010, for Canadian publicly accountable enterprises.
60
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2
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E
N
E
A
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N
O
B
4. BUSINESS COMBINATIONS
On July 2, 2009, the Company acquired all of the issued common shares of Cobalt Energy Ltd. (Cobalt) for
consideration of 201,438 common shares at a value of $15.92 per common share plus the assumption of
$2,856,000 of negative working capital for total consideration of $6,063,000. Results of Cobalt’s operations
have been included in the consolidated financial statements commencing from that date.
The acquisition was accounted for using the purchase method and the purchase price was allocated to the
fair value of the assets acquired and the liabilities assumed as follows:
($ 000s)
Cost of acquisition
Value of common stock
Acquisition costs
Allocation of purchase price:
Property and equipment
Future income tax liability
Working capital deficiency
Asset retirement obligations
3,207
170
3,377
7,105
(748)
(2,856)
(124)
3,377
5. INVESTMENT IN RELATED PARTY
The investment consists of 689,682 common shares in Geomark Exploration Ltd. (Geomark), a
company having common directors and management with the Company. The investment is recorded at
fair market value.
Effective July 6, 2010, Comaplex Minerals Corp. (Comaplex) (a company having common management
and directors) was acquired by Agnico-Eagle Mines Limited (Agnico-Eagle). In exchange for Bonterra’s
689,682 common shares in Comaplex, the Company received 689,682 shares in Geomark and 108,693 common
shares in Agnico-Eagle (value included in Investments on the balance sheet). The investment in Geomark
represents 1.3 percent ownership in the outstanding common shares of Geomark.
61
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2
0
1
0
A
N
N
U
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T
6. PROPERTY AND EQUIPMENT
($ 000s)
Undeveloped land
Petroleum and natural gas properties and
related equipment
Furniture, equipment and other
2010
Accumulated
Depletion and
Cost Depreciation
–
4,595
2009
Accumulated
Depletion and
Depreciation
–
Cost
7,992
326,072
1,474
332,141
108,217
1,098
109,315
246,387
1,461
255,840
87,153
1,016
88,169
On November 6, 2009, the Company divested of a portion of its Shaunavon oil production to
Eagle Rock Exploration Ltd. (Eagle Rock). The proceeds of disposition consisted of $23,729,000 cash
and 30,769,200 common shares in Eagle Rock (representing approximately 4.2 percent of the outstanding
common shares of that company at that time). The Eagle Rock common shares were trading for
$0.21 cents per share on November 6, 2009. The Company had a net book value (after effects of asset
retirement obligations) of $5,993,000 attributable to the assets disposed of resulting in a gain on sale of the
property of $24,198,000.
Eagle Rock has since changed its name to Wild Stream Exploration Inc. (Wild Stream) and consolidated its
common shares on a 30:1 basis resulting in Bonterra holding 1,025,640 common shares (value included in
Investments on the balance sheet).
In February 2010, the Company disposed of its Southeast Saskatchewan Pinto property. The proceeds of
disposition were $5,534,000 cash. At the time of disposition, the Company had a net book value of $120,000
for the property. It also had an asset retirement obligation related to the property of $371,000 that was
transferred resulting in a gain on sale of property of $5,785,000.
In July 2010, the Company disposed of non-producing land rights for proceeds of $700,000. The Company has
never had any capital costs associated with these land rights.
During the year the Company capitalized $Nil (2009 – $460,000) of general and administrative costs.
62
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0
1
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2
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P
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Y
R
E
N
E
A
R
R
E
T
N
O
B
7. DUE TO RELATED PARTIES
As of December 31, 2010, the Company’s CEO and major shareholder has loaned the Company $12,000,000
(December 31, 2009 – $11,500,000). The loan is unsecured, bears interest at a Canadian chartered bank prime
less 5/8th of a percent and has no set repayment terms but is payable on demand. Interest paid on this loan
during 2010 was $242,000 (2009 – $209,000).
As a result of the acquisition by Agnico-Eagle of Comaplex on July 6, 2010, the $12,000,000 loan previously
held by Comaplex was transferred to Geomark and is repayable by the Company under the same terms.
As of December 31, 2010, Geomark has loaned the Company $20,000,000. The loan is unsecured, bears
interest at a Canadian chartered bank prime less 5/8th of a percent and has no set repayment terms but is
payable on demand. Interest paid on this loan during 2010 was $313,000 (including interest paid to Comaplex)
(2009 – $194,000 paid to Comaplex).
The Company’s bank agreement requires that the above loans can only be repaid should the Company
have sufficient available borrowing limits under the Company’s credit facility. As of December 31, 2010, the
Company has sufficient room to repay all balances.
Please refer to Note 14 for additional related party transactions.
8. SUBORDINATED PROMISSORY NOTE
On October 4, 2010 the Company borrowed $15,000,000 from a private investor. In exchange Bonterra has
issued a Subordinated Promissory Note for $15,000,000. The terms of the Subordinated Promissory Note are
that it bears interest at three percent, is not callable by the investor prior to January 4, 2012 at which time it
will be a demand note until its maturity of April 4, 2012, and can be repaid at the option of the Company at
any time. Security consists of a floating demand debenture totaling $15,000,000 over all of the Company’s
assets and is subordinated to any and all claims in favor of the syndicate of senior lenders providing credit
facilities to the Company. Interest paid on the subordinated promissory note during 2010 was $110,000.
The Company’s bank agreement requires that the above loan can only be repaid should the Company
have sufficient available borrowing limits under the Company’s credit facility. As of December 31, 2010 the
Company has sufficient room to repay the subordinated promissory note.
63
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2
0
1
0
A
N
N
U
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O
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T
9. BANK DEBT
As of December 31, 2010, the Company has a bank facility consisting of a $100,000,000 syndicated and
$20,000,000 non-syndicated revolving credit facility (December 31, 2009 – $100,000,000 syndicated and
$20,000,000 non-syndicated revolving credit facility). The interest rates on the outstanding debt as of
December 31, 2010 were 4.0 percent and 3.4 percent on the Company’s Canadian prime rate loan and
Bankers’ Acceptances, respectively. The terms of the syndicated revolving credit facility provided that the
loan is revolving to April 27, 2012 and is subject to annual review. The revolving credit facility has no fixed
payment requirements. The Company at December 31, 2010 was in level I (see below) in respect of its various
borrowing charges.
The amount available for borrowing under the credit facility is reduced by outstanding letters of credit.
Letters of credit totaling $285,000 were issued at December 31, 2010 (December 31, 2009 – $285,000).
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 facility is calculated as follows:
Consolidated Total Funded Debt (1)
to Consolidated Cash flow Ratio
Canadian Prime Rate Plus (2)
Bankers’ Acceptances Rate Plus (2)
Level I
Under
1.0:1
100
225
Level II
Over
1.0:1 to 1.5:1
150
275
Level III
Over
1.5:1 to 2.0:1
175
300
Level IV
Over
2.0:1 to 2.5:1
200
325
Level V
Over
2.5:1
250
375
(1) Consolidated total funded debt excludes related party amounts and subordinated debenture but includes working
capital. Consolidated cash flow is calculated as cash flow according to GAAP excluding adjustments for non-cash working
capital items.
(2) Numbers in table represent basis points.
Consolidated total funded debt to consolidated cash flow ratio shall be calculated each fiscal quarter and
the interest rates adjusted effective as of the first day of the fiscal quarter commencing immediately after
the fiscal quarter in which Bonterra files a compliance certificate containing the ratio, with each such
adjustment to be effective until the next such adjustment.
The following is a list of the material covenants:
• The Company is required to not exceed $120,000,000 in consolidated total funded debt
(includes working capital but excludes due to related parties and subordinated debt).
• The total of the dividends paid in the current quarter and the three previous quarters shall not exceed
80 percent of the previous four quarters’ cash flow as defined under GAAP excluding adjustments for
non-cash working capital items.
64
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U
N
N
A
0
1
0
2
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P
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O
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Y
R
E
N
E
A
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E
T
N
O
B
At December 31, 2010, the Company is in compliance with all covenants.
10. INCOME TAXES
The Company has recorded a future income tax asset related to assets and liabilities and related
tax amounts:
($ 000s)
Future tax liability related to investments
Future tax liability related to property and equipment
Future tax asset related to asset retirement obligations
Future tax asset related to finance costs
Future tax asset related to corporate tax losses and SR&ED claims
Future tax asset related to corporate capital tax losses
Valuation adjustment
Future Tax Asset – Long-Term
Current portion of future income tax asset related to corporate tax
losses and SR&ED claims:
Future Tax Asset – Current
A reconciliation of the deferred credit is as follows:
($ 000s)
Amount recorded on reorganization
Amortized in 2008
Amortized in 2009
Rate adjustment 2009
Balance as of December 31, 2009
Amortized in 2010
Rate adjustment 2010
Balance as of December 31, 2010
Current portion
Long-term portion
2010
(832)
(12,347)
4,274
367
37,717
17,705
(16,873)
30,011
2009
(824)
(5,855)
4,474
802
59,668
17,883
(17,883)
58,265
22,889
22,889
11,889
11,889
71,303
(4,240)
(12,356)
425
55,132
(9,408)
(288)
45,436
19,586
25,850
45,436
65
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A
E
N
E
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Y
C
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P
.
2
0
1
0
A
N
N
U
A
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P
O
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T
Income tax expense varies from the amounts that would be computed by applying Canadian federal and
provincial income tax rates as follows:
($ 000s)
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
Quebec tax
Stock-based compensation
Deferred credit amortization
Non-taxable portion of gains
Change in valuation allowance
Change in effective tax rate
Other
Income tax expense
2010
56,982
28.06%
15,989
141
–
136
(9,696)
(461)
(1,010)
2,071
(52)
7,118
2009
74,536
29.15%
21,727
282
269
266
(11,931)
–
–
(4,708)
68
5,973
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:
($ 000s)
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
25,441
6,849
1,424
19,074
109,642
11,140
39,985
222,596
$ 436,151
(1) Federal income tax losses carried forward expire in the following years; 2024 – $3,347,000, 2025 – $7,532,000, 2026 – $46,671,000,
2027 – $117,189,000, 2028 – $34,726,000, 2029 – $13,131,000.
66
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A
U
N
N
A
0
1
0
2
.
P
R
O
C
Y
R
E
N
E
A
R
R
E
T
N
O
B
The Company has $27,670,000 (2009 – $27,670,000) remaining of investment tax credits that expire in the
following years; 2019 – $3,469,000, 2020 – $3,059,000, 2021 – $4,667,000, 2022 – $3,909,000, 2023 – $3,155,000,
2024 – $1,995,000, 2025 – $2,257,000, 2026 – $2,405,000, 2027 – $2,009,000, 2028 – $745,000.
The Company also has $141,417,000 (December 31, 2009 – $143,061,000) of capital loss carry forwards which
can only be claimed against taxable capital gains.
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. A significant change in any of these
assumptions could materially affect the Company’s estimate of the future income tax asset.
11. ASSET RETIREMENT OBLIGATIONS
At December 31, 2010, the estimated total undiscounted amount required to settle the asset retirement
obligations was $62,579,000 (2009 – $64,482,000). Costs for asset retirement have been calculated assuming a
1.5 percent inflation rate. These obligations will be settled based on the useful lives of the underlying assets,
which extend up to 50 years into the future. This amount has been discounted using a credit-adjusted risk-
free interest rate of five percent (2009 – five percent).
Changes to asset retirement obligations were as follows:
($ 000s)
Asset retirement obligations, January 1
Adjustment to asset retirement obligations
Adjustment related to asset disposals
Liabilities settled during the year
Accretion
Asset retirement obligations, December 31
2010
17,790
(220)
(368)
(1,006)
874
17,070
2009
18,338
(138)
(750)
(573)
913
17,790
67
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A
E
N
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Y
C
O
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P
.
2
0
1
0
A
N
N
U
A
L
R
E
P
O
R
T
12. SHAREHOLDERS’ EQUITY
Authorized
The Company is authorized to issue an unlimited number of common shares without nominal or par value.
The Company is also 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.
Issued
Common Shares
Balance, beginning of year
Issued pursuant to private placement
Issued on acquisition of Cobalt (Note 4)
Issued pursuant to Company share option plan
Transfer of contributed surplus to share capital
Issue costs for private placement
Future tax effect of share issue costs
Balance, end of year
2010
Amount
($ 000s)
121,955
–
–
12,377
698
–
–
135,030
Number
18,619,641
–
–
599,900
19,219,541
2009
Amount
($ 000s)
99,530
17,996
3,207
1,898
103
(1,046)
267
121,955
Number
17,257,603
1,068,000
201,438
92,600
18,619,641
On May 27, 2009, the Company completed a private placement for 1,068,000 common shares at a price of
$16.85 per common share for aggregate proceeds of $17,996,000. The Company incurred issue costs of
$1,046,000 in respect of the offering.
The number of common shares used to calculate diluted net earnings per share for the year ended
December 31, 2010 of 19,348,991 shares (2009 – 18,131,085) included the basic weighted average number
of common shares outstanding of 18,810,355 shares (2009 – 18,006,320) plus 538,636 shares (2009 – 124,765)
related to the dilutive effect of common share options.
68
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A
U
N
N
A
0
1
0
2
.
P
R
O
C
Y
R
E
N
E
A
R
R
E
T
N
O
B
A summary of the changes to the Company’s contributed surplus is presented below:
Contributed Surplus
($ 000s)
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:
($ 000s)
Accumulated earnings
Accumulated cash dividends
Deficit
2010
3,350
483
(698)
3,135
2009
2,542
911
(103)
3,350
2010
326,609
(332,063)
(5,454)
2009
276,745
(285,196)
(8,451)
The Company provides a stock option plan for its directors, officers, employees and consultants. Under the
plan, the Company may grant options for up to 1,921,954 common shares (2009 – 1,861,964). 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, 2010 and 2009, and changes
during the years ended on those dates is presented below:
December 31, 2010
December 31, 2009
Outstanding at beginning of period
Options granted
Options cancelled
Options exercised
Outstanding at end of period
Options exercisable at end of period
$
Weighted-
Average
Exercise
Price
20.36
36.98
34.66
20.63
20.56
20.50
$
$
Options
1,330,900
36,000
(20,000)
(599,900)
747,000
255,500
Options
1,390,500
33,000
–
(92,600)
1,330,900
370,900
$
Weighted-
Average
Exercise
Price
20.50
14.90
–
20.50
20.36
20.50
$
$
69
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A
E
N
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Y
C
O
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P
.
2
0
1
0
A
N
N
U
A
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T
The following table summarizes information about options outstanding at December 31, 2010:
Options Outstanding
Options Exercisable
Weighted-
Average
Number
Outstanding
at 12/31/10
22,000
719,000
6,000
747,000
Weighted-
Remaining
Contractual
Life
2.1 years
1.9 years
2.5 years
1.9 years
Average
Exercise
Price
$14.90
20.50
48.60
$20.56
Weighted-
Number
Exercisable
at 12/31/10
–
255,500
–
255,500
Average
Exercise
Price
$ –
20.50
–
$ 20.50
Range of Exercise Prices
$ 14.90
20.50
48.60
$ 14.90 - $ 48.60
The Company records compensation expense over the vesting period based on the fair value of options
granted to employees, directors and consultants. In 2010, the Company granted 36,000 stock options with
an estimated fair value of $204,000 ($5.67 per option) using the Black-Scholes option pricing model with the
following key assumptions:
Weighted-average risk free interest rate (%)
Expected life (years)
Weighted-average volatility (%)
Dividend yield 2010 and 2009
2010
1.87
2.8
33.1
2009
1.4
3.0
33.0
based on the percentage of dividends
paid during the period granted
13. ACCUMULATED OTHER COMPREHENSIVE INCOME
($ 000s)
Unrealized gains on available
for sale financial assets
($ 000s)
Unrealized gains on available
for sale financial assets
Other
January 1, Comprehensive
Income
2010
December 31,
2010
2,020
3,682
5,702
January 1,
2009
Other
Comprehensive
Income
December 31,
2009
1,420
600
2,020
70
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0
1
0
2
.
P
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R
E
N
E
A
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E
T
N
O
B
14. RELATED PARTY TRANSACTIONS
The Company received a management fee from Geomark and Comaplex of $316,500
(Comaplex 2009 – $330,000) for management services and office administration. This fee has been included
as a recovery in general and administrative expenses. At December 31, 2010, the Company had an account
receivable from Geomark of $35,000 (Comaplex December 31, 2009 – $105,000). Effective July 6, 2010, the
Company cancelled its management agreement with Comaplex due to its takeover by Agnico-Eagle.
A new management agreement was entered into with Geomark effective July 6, 2010, under the same terms
and conditions as those of the Comaplex agreement except that the monthly fee is $22,500 compared to
Comaplex’s monthly fee of $30,000.
The Company received a management fee from Pine Cliff Energy Ltd. (Pine Cliff), a company having
common directors and management with Bonterra, of $90,000 (2009 – $120,000) for management services
and office administration. This fee has been included as a recovery in general and administrative
expenses. At December 31, 2010 the Company had an account receivable from Pine Cliff of $1,000
(December 31, 2009 – $1,000).
These transactions are in the normal course of operations and are measured at the exchange amount, which
is the amount of consideration established and agreed to by the related parties.
15. FINANCIAL AND CAPITAL RISK MANAGEMENT
Financial Risk Factors
The Company undertakes transactions in a range of financial instruments including:
• Receivables
• Payables and accrued liabilities
• Common share investments
• Due to related parties
• Bank debt
• Subordinated Promissory Note
The Company’s activities result in exposure to a number of financial risks including market risk
(commodity price risk, interest rate risk, and foreign exchange risk), credit risk, and liquidity risk.
71
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.
2
0
1
0
A
N
N
U
A
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P
O
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T
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 may enter 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. 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, which the Company defines to include shareholders’
equity, debt, due to related parties, subordinated promissory note and working capital balances, 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, debt facilities or issue new shares.
The Company monitors capital on the basis of the ratio of debt to cash flow. This ratio is calculated using
each quarter end net debt (total debt adjusted for working capital) and divided by the preceding twelve
months cash flow. The Company believes that a debt level of approximately one and a half year’s cash flow
is an appropriate level to allow it to take advantage in the future of either acquisition opportunities or to
provide flexibility to develop its undeveloped resources by horizontal or vertical drill programs.
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.
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B
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
($ 000s)
Financial assets
Accounts receivable
Investments
Investments in related party
Financial liabilities
Accounts payable and accrued liabilities
Due to related parties
Subordinated promissory note
Bank debt
($ 000s)
Financial assets
Accounts receivable
Investments
Investments in related party
Restricted cash
Financial liabilities
Accounts payable and accrued liabilities
Due to related parties
Bank debt
As at December 31, 2010
Carrying Value
Fair Value
Face Value
17,345
11,471
814
16,839
32,000
15,000
70,386
17,345
11,471
814
16,839
32,000
15,000
70,386
17,445
N/A
N/A
16,839
32,000
15,000
70,386
As at December 31, 2009
Carrying Value
Fair Value
Face Value
14,713
4,462
4,827
812
18,868
23,500
59,823
14,713
4,462
4,827
812
18,868
23,500
59,823
14,873
N/A
N/A
812
18,868
23,500
59,823
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Financial instruments consisting of accounts receivable, accounts payable and accrued liabilities, due to
related parties, subordinated promissory note and bank debt on the consolidated balance sheet are carried
at amortized cost. Investments and investments in related party are carried at fair value. All of the fair value
items are transacted in active markets. Bonterra classifies the fair value of these transactions according to
the following hierarchy based on the amount of observable inputs used to value the instrument.
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting
date. Active markets are those in which transactions occur in sufficient frequency and volume to provide
pricing information on an ongoing basis.
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level
2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on
inputs, including quoted forward prices for commodities, time value and volatility factors, which can be
substantially observed or corroborated in the marketplace.
Level 3 – Valuations in this level are those with inputs for the asset or liability that are not based on
observable market data.
Bonterra’s investments and investments in related party have been assessed on the fair value hierarchy
described above and are all considered Level 1.
The net debt and cash flow from operations figures are presented in Table 2.
Table 2
($ 000s)
Bank debt
Due to related parties
Subordinated promissory note
Accounts payable and accrued liabilities
Current assets (1)
Net Debt
Cash flow from operations (2)
Net debt to cash flow from operations
December 31, 2010
70,386
32,000
15,000
16,839
(30,934)
103,291
66,262
1.56
(1) Current assets include accounts receivable, crude oil inventory, prepaid expenses, and investments.
(2) Cash flow from operations includes annual net earnings less adjustment for, stock-based compensation, depletion,
depreciation and accretion, gain on sale of property, gain on sale of investments, future income taxes, changes in non-cash
working capital items, and asset retirement obligations settled.
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A
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N
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B
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, 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.
Interest rate risk
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 borrowings which have a variable interest rate which gives rise to a cash flow
interest rate risk.
The Company’s debt facilities consist of a $100,000,000 revolving operating line, $20,000,000 demand
operating line, a $15,000,000 subordinated promissory note and $32,000,000 due to related parties. The
borrowings under these facilities are at bank prime plus or minus various percentages as well as by
means of bankers’ acceptances (BA’s) within the Company’s credit facility. 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.
A one percent increase (decrease) in the Canadian prime rate would decrease (increase) net earnings
and comprehensive income by $758,000, respectively.
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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, 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; and
• Agreements for product sales are primarily on 30 day renewal terms.
Of the accounts receivable balance of December 31, 2010 ($17,345,000) and December 31, 2009 ($14,713,000)
over 88 (2009 – 87) percent relates to product sales with international oil and gas companies and drilling
credits receivable from the province of Alberta.
The Company assesses quarterly, if there has been any impairment of the financial assets of the Company.
During the year ended December 31, 2010, there was no impairment provision required on any of the
financial assets of the Company due to historical success of realizing financial assets. The Company does
have a credit risk exposure as the majority of the Company’s accounts receivables are with counterparties
having similar characteristics. However, payments from the Company’s largest accounts receivable
counterparties 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, 2010, approximately $231,000 or 1.3 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 netting payables 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, 2010 is $100,000 (December 31, 2009 – $160,000) with the difference being
included in general and administrative expenses. There were no accounts written off during the year.
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B
The maximum exposure to credit risk is represented by the carrying amount on the balance sheet. There are
no material financial assets that the Company considers past due.
Liquidity risk
Liquidity risk includes the risk that, as a result of the Company’s operational liquidity requirements:
• The Company will not have sufficient funds to settle a transaction on the due date;
• The Company will not have sufficient funds to continue with its dividends;
• The Company will be forced to sell assets at a value which is less than what they are worth; or
• The Company may be unable to settle or recover a financial asset at all.
To help reduce these risks the Company:
• Maintains a portfolio of high-quality, long reserve life oil and gas assets.
The Company has the following maturity schedule for its financial liabilities:
($ 000s)
Accounts payable and
accrued liabilities
Due to related parties
Subordinated promissory note
Bank debt
Office leases
Total
Recognized on
Financial Statements
Payments Due By Period
Less than 1 year
1-3 years
4-5 years
Yes – Liability
Yes – Liability
Yes – Liability
Yes – Liability
No
16,839
32,000
–
–
967
49,806
–
–
5,000
70,386
1,411
86,797
–
–
–
–
–
–
c) Risk management contracts
The Company has no outstanding risk management contracts.
16. 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:
Lease Obligations ($ 000s)
Year 1
Year 2
Year 3
Year 4
Year 5
Total
967
874
537
–
–
2,378
17. SUBSEQUENT EVENTS – DIVIDENDS
Subsequent to December 31, 2010, the Company has declared the following dividends:
Date declared
January 5, 2011
February 2, 2011
March 2, 2011
Record date
January 14, 2011
February 15, 2011
March 15, 2011
$ per share
$0.24
$0.24
$0.24
Date payable
January 31, 2011
February 28, 2011
March 31, 2011
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CORPORATE
INFORMATION
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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 and Chairman of the Board
R.M. Jarock – President and Chief Operating Officer
G.E. Schultz – Chief Financial Officer
R.D. Thompson – Vice President, Finance
REGISTRAR & TRANSFER AGENT
Olympia Trust Company, Calgary, Alberta
AUDITORS
Deloitte & Touche LLP, Calgary, Alberta
SOLICITORS
Borden Ladner Gervais LLP, Calgary, Alberta
BANKERS
CIBC, Calgary, Alberta
The Royal Bank of Canada, Calgary, Alberta
Alberta Treasury Branch, 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
901, 1015 - 4th Street SW
Calgary, Alberta T2R 1J4