Bonterra Energy Corp. Annual Report 2009

FY2009 Annual Report · Bonterra Energy Corp.

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The Value of Bonterra

Income, Growth and Sustainability

BONTERRA ANNUAL REPORT 2009

BONTERRA ENERGY CORP. 3

Annual Highlights _______________________________________________ 02
Quarterly Highlights _____________________________________________ 03
Report to Shareholders __________________________________________ 04
Review of Operations ____________________________________________ 09
Pembina Cardium Horizontal Drilling ______________________________ 12

Statistical Review _______________________________________________ 17
Management’s Discussion & Analysis _____________________________ 27
Consolidated Financial Statements _______________________________ 57
Notes to the Consolidated Financial Statements ____________________ 61
Corporate Information ___________________________________________ 85

BONTERRA ENERGY CORP. 1

Bonterra Energy Corp. is a high-yield, dividend paying oil and gas company headquartered in Calgary,
Alberta. Bonterra has paid a monthly dividend (formerly a distribution) since inception and intends to
pay approximately 60 to 75 percent of funds flow to investors.

The Company’s asset base consists of concentrated, stable and underdeveloped properties across
western Canada with large amounts of remaining oil still in place, a long reserve life and low-risk,
predictable returns. Bonterra’s proven track record of success is due to its experienced management
team, conservative capital structure and sustainable pace of development.

Unlocking AdditionAl VAlUe

Bonterra has one of the highest-quality asset bases in the Canadian energy industry with approximately
90 percent of corporate reserves on a Proved plus Probable basis in the Pembina Cardium field,
Canada’s largest original-oil-in-place pool (17 percent recovered to date). The Company has a 14 year
drilling inventory with 435 gross locations already identified including 80 gross horizontal locations
in the Halo area of the Pembina field. The 2010 capital development program of $40 to $50 million
will consist of a targeted drilling program of horizontal multi-stage fracs, vertical wells and land and
corporate acquisitions allowing the Company the potential to continue to provide its investors with
above average results and returns.

BONTERRA ENERGY CORP. 2

Annual Highlights

2009

2008

2007

FinAnciAl ($ 000s, except $ per shAre / Unit)
Revenue – realized oil and gas
Cash flow from operations
Per Share / Unit Basic
Per Share / Unit Diluted
Payout Ratio (1)
Funds Flow (2)
Per Share / Unit Basic
Per Share / Unit Diluted
Payout Ratio (1)
Cash payments per Share / Unit (1)
Net Earnings
Per Share / Unit Basic
Per Share / Unit Diluted
Capital Expenditures and Acquisitions (net of disposals)
Total assets
Working Capital Deficiency
Long-term Debt
Shareholders’ / Unitholders’ Equity
Shares / Units Outstanding
operAtions
Oil and Liquids (barrels per day)
Average Price ($ per barrel)
Natural Gas (MCF per day)
Average Price ($ per MCF)
Total BOE per day (3)
reserVes
Oil and Liquids (barrels in 000s)
Proved Developed Prducing (Gross) (4)
Proved (Gross)
Proved plus Probable (Gross)
Natural Gas (MCF in 000s)
Proved Developed Prducing (Gross)
Proved (Gross)
Proved plus Probable (Gross)
Reserve Life Index (5) (oil, liquids and natural gas at 6:1) (years)
Proved Developed Prducing (Gross)
Proved (Gross)
Proved plus Probable (Gross)
Reserves per Weighted Average Outstanding Share / Unit (BOE)
Proved Developed Prducing (Gross)
Proved (Gross)
Proved plus Probable (Gross)

85,712
38,893
2.16
2.15
79%
66,504
3.69
3.67
46%
1.70
68,563
3.81
3.78
5,640
293,987
10,162
59,823
118,874
18,620

3,141
59.82
11,120
4.15
4,994

15,519
19,220
27,568

32,103
36,642
49,539

11.7
14.2
20.1

1.16
1.41
1.99

121,730
69,570
4.07
4.06
77%
70,448
4.13
4.12
76%
3.12
55,426
3.25
3.23
45,407
265,301
23,878
79,910
56,777
17,258

3,073
87.54
7,637
8.21
4,346

15,534
17,991
22,867

32,108
36,571
50,245

12.5
14.4
18.7

1.22
1.41
1.83

96,431
51,433
3.04
3.04
87%
53,815
3.18
3.18
83%
2.64
30,350
1.79
1.79
19,300
142,326
58,766
-
44,376
16,928

3,113
70.31
6,627
6.75
4,218

14,468
17,472
21,910

19,863
24,125
32,465

11.3
13.7
17.4

1.05
1.27
1.62

BONTERRA ENERGY CORP. 3

Quarterly Highlights

2009
Financial

($ 000s, except $ per share)

Revenue – realized oil and gas sales
Cash flow from operations
Per Share Basic
Per Share Diluted
Payout Ratio (1)
Funds Flow (2)
Per Share Basic
Per Share Diluted
Payout Ratio (1)
Cash payments per share (1)
Net Earnings
Per Share Basic
Per Share Diluted
Capital Expenditures and Acquisitions
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

24,946
13,673
0.76
0.75
66%
37,595
2.07
2.06
24%
0.50
52,136
2.88
2.85
(16,976)
293,987
10,162
59,823
118,874

3,182
10,193
4,881

20,965
9,350
0.50
0.50
87%
10,753
0.58
0.57
76%
0.44
5,790
0.32
0.32
17,660
273,543
14,455
81,136
74,025

3,084
10,881
4,898

20,501
9,238
0.52
0.52
77%
9,780
0.55
0.55
73%
0.40
4,544
0.26
0.26
2,255
258,393
13,989
71,573
72,332

3,029
11,551
4,954

19,300
6,632
0.38
0.38
94%
8,376
0.49
0.49
74%
0.36
6,093
0.35
0.35
2,701
260,732
14,909
89383
56,377

3,268
11,877
5,245

(1) Cash dividend / disbursement payments per share/unit are based on payments made in respect of production

months as opposed to the month paid.

(2) 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, adjustments of investment tax credit receivable, and excluding restricted cash and asset retirement
obligations settled.

(3) 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.

(4) Gross reserves relate to the Company’s ownership of reserves deducting any royalties.
(5) The reserve life index is calculated by dividing the reserves (BOE) by the annualized fourth quarter average

production rate (2009 – 4,881; 2008 – 4,587 BOE per day; 2007 – 4,295 BOE per day).

BONTERRA ENERGY CORP. 4

Report to Shareholders

Bonterra Energy Corp. (Bonterra or the Company) is pleased to report its operational and financial results for
the year ending December 31, 2009.

Bonterra continues to focus on providing its investors with stable income in the form of a monthly dividend,
a conservative growth profile, and sustainability through the internal development and expansion of its
high-quality asset base.

sUstAinAbility And growth

In 2009, Bonterra focused its capital program on its Pembina Cardium property, most notably on the horizontal,
multi-stage frac drilling program and achieved increased production and reserves on both a total and per
share basis. Bonterra is the third largest land owner in the Pembina Cardium field with approximately 160 gross
(117 net) sections of Cardium mineral rights including 27.5 gross (23.0 net) sections along the perimeter of the
main pool (frequently referred to as the “Halo” area) and the adjacent Willesden Green field.

Bonterra is proud to be one of the first companies to realize and unlock further value from the Pembina
Cardium field through the application of this advanced technology beginning with the drilling of its first
successful horizontal well in late 2008 which has averaged 124 BOE per day during its first 12 months of
production. Horizontal, multi-stage frac drilling is now being used by many companies in the area and the
Pembina Cardium zone is recognized as one of the most exciting plays in the Canadian energy sector because
of its significant potential upside.

In 2009, Bonterra spent approximately $35.2 million on its capital development program of which
approximately $22.9 million was spent on drilling and completions with the remainder spent on land and
corporate acquisitions in the Pembina area. During the year, the Company drilled seven Pembina Cardium
horizontal wells (5.5 net), eight vertical Pembina Cardium wells (6.9 net), and two natural gas wells (0.4
net), recording a 100 percent success rate. In November, the Company engaged the services of a second
drilling rig and in March added a third drilling rig. The Pembina Cardium horizontal well drilling program will
continue until spring break-up and resume once again when road bans are lifted. Average daily production
increased 15 percent in 2009 year over year to 4,994 BOE per day, a new record level for Bonterra.

The development of this play is important for future growth and for generating long-term value for
shareholders. The success achieved in 2009 well-exceeded the Company’s initial expectations. As such,
Bonterra has continued to advance the program at an accelerated pace.

bonterra continues
focus
on providing its investors with
stable income in the form of a
monthly dividend, a conservative
growth profile, and sustainability
through the internal development
and expansion of its high-quality
asset base.

Bonterra is currently planning to drill 20 to 30 gross horizontal Cardium wells in 2010 with a capital
development budget of $40 to $50 million. The majority of wells planned are in the Halo area but the Company
will also conduct some drilling in the main portion of the pool with the objective of converting some potential
vertical locations to horizontals. The Company currently forecasts 2010 production to average between
5,700 and 6,000 BOE per day. The future drill program may also be affected by the results of the Alberta
government’s competition review.

strengthening the Asset bAse

The Company was able to enhance its reserve base in 2009, increasing its reserve life index (RLI) to 20.1 years
on a Proved plus Probable basis from 18.7 years in 2008. Bonterra’s RLI continues to be one of the highest in
the industry among conventional producers.

In 2009, Bonterra expanded its land holdings in the Pembina field with the acquisition of mineral rights at
a cost of approximately $5.8 million. In addition, Bonterra acquired a small Canadian junior, Cobalt Energy
Ltd., effective July 1, 2009. This acquisition resulted in only a modest increase in production but provided
the Company with additional ownership in 11 gross Bonterra operated sections of land with potential
Pembina Cardium horizontal drilling locations.

Results from Bonterra’s operations, capital development program and acquisitions have resulted in increases
in the independent engineering estimated recoverable reserves. This has contributed to Bonterra’s low
finding, development and acquisition (FD&A) costs. At $13.25 per BOE on a Total Proved basis and $8.93 on
a Proved Plus probable basis, Bonterra continues to record FD&A costs that are significantly below industry
average. With an average cash netback of $23.42 per BOE, Bonterra’s 2009 proved plus probable recycle ratio
was 2.6 times.

Bonterra completed asset sales in 2009 and in the first quarter of 2010, obtaining $35.8 million in dispositions
from non-core assets in Saskatchewan. This included the divestment of approximately 270 BOE per day of
producing oil and gas properties and an associated 1.4 million BOE of Proved plus Probable reserves. The
proceeds from these sales will assist in accelerating the development of the Cardium assets.

BONTERRA ENERGY CORP. 5

RESERVES PER SHARE/UNIT (BOE)

2005

2006

2007

2008

2009

0.5

1.0

1.5

2.0

PRODUCTION PER SHARE/UNIT (BOE)

2005

2006

2007

2008

2009

0.02

0.04

0.06

0.08

0.10

PROVED PLUS PROBABLE
RESERVE LIFE INDEX (YEARS)

2005

2006

2007

2008

2009

BONTERRA ENERGY CORP. 6

NET EARNINGS ($ 000s)

2005

2006

2007

2008

2009

20000

40000

60000

80000

FUNDS FLOW ($ 000s)

2005

2006

2007

2008

2009

20000

40000

60000

80000

CASH DIVIDENDS/DISTRIBUTIONS
TO INVESTORS ($ PER UNIT/SHARE)

100

2005

2006

2007

2008

2009

Funds flow from operations Dividends/distributions

FinAnciAl strength

During the year, Bonterra took several steps towards improving its financial position. The Company entered
into a new syndicated banking facility effective April 29, 2009 consisting of a $100 million syndicated revolving
credit facility and a $20 million non-syndicated revolving credit facility. In addition, Bonterra completed an
equity offering in May, 2009. The Company issued 1,068,000 common shares at a price of $16.85 per share
for net proceeds of approximately $17 million. Funds were used for the Company’s capital program and for
general working capital purposes.

Bonterra is committed to seeking new ways to strengthen its financial position including cost-reduction
initiatives, project reviews throughout the year and exploring and implementing operational efficiencies
across the Company.

As a result of its strong financial position, Bonterra is sufficiently funded to execute the 2010 capital program
and to pursue additional acquisition opportunities that may become available. It is the Company’s goal to
further decrease the debt to cash flow ratio by the end of 2010.

improVing retUrns to inVestors

Financial results during 2009 were significantly impacted by the low commodity price environment. Revenue
and funds flow from operations in 2009 decreased 30 percent and 6 percent, respectively when compared to
the prior year primarily due to a 32 percent decrease in the Company’s crude oil average realized price and
a 50 percent decrease in the Company’s natural gas average realized price partially offset by production
increases and a gain on asset sale of $24.2 million in the fourth quarter of 2009. Commodity prices showed
improvement during the latter half of the year, mainly in crude oil, and the fourth quarter numbers reflected
a positive impact with a 250 percent increase in funds flow from operations in the fourth quarter of 2009
compared with the third quarter of 2009.

In 2009, Bonterra paid cash dividends to shareholders of $1.70 per share, a substantial decrease from the
2008 level of $3.12 per share. Bonterra had reduced its dividend in early 2009 to maintain its balance sheet
strength and the financial flexibility necessary to continue developing the Pembina Cardium horizontal play.
As pricing improved, Bonterra was able to increase the dividend twice during the year. Subsequent to year-
end, Bonterra was able to once again increase the dividend to its current level of $0.18 per share which began
with the dividend paid out in January, 2010.

Management and the Board of Directors monitor production volumes, commodity prices, operating costs,
payout ratios and capital expenditures on a monthly basis to determine the dividend amount. Bonterra
currently intends to pay out between 60 and 75 percent of its cash flow and retain the remainder for capital
expenditures.

BONTERRA ENERGY CORP. 7

Bonterra continues to maintain that the best assessment of an entity is its return to investors. On a
one-year basis, Bonterra’s total return to shareholders was 117 percent. The improving global economic
outlook, increasing commodity prices and additional value attributed to the Pembina Cardium horizontal
play have increased the share price substantially over the course of the year providing investors with one of
its best returns since inception. Bonterra has also performed well over longer periods of time. Total return
to shareholders over a three year period (2007 – 2009) was 87 percent and over a five year (2005 – 2009) period
was 132 percent.

oUtlook

Bonterra continues to execute its business plan strategically and with discipline. Bonterra has spent
considerable effort developing in-house technical skills and building strategic land positions in and around
its core areas. The 2010 capital development program will continue to target these advantages and focus
on maximizing shareholder returns through the allocation of capital to its high return Pembina Cardium
horizontal drilling program, the active pursuit of improved reserve recovery and continued improvements in
ongoing operations.

Taking this approach will allow Bonterra to maintain its strong dividend policy, providing investors with a
solid income investment paid on a monthly basis while ensuring the long-term sustainability of its business.

Management would like to take this opportunity to thank the Board of Directors for its counsel and advice and
its shareholders for their continued support. In addition, Bonterra’s team of employees must be acknowledged
for their hard work and dedication in executing Company strategy and maximizing shareholder returns. The
Company looks forward to capitalizing on its many opportunities in 2010 and will continue to strive to add
further value on behalf of investors.

Submitted on behalf of the Board of Directors,

george F. Fink
Chairman and Chief Executive Officer

randy m. Jarock
President and Chief Operating Officer

BONTERRA ENERGY CORP. 8

PROVED PLUS
PROBABLE RESERVES (MBOE)

2009 RESERVES BY COMMODITY

AVERAGE DAILY PRODUCTION (BOE per day)

2005

2006

2007

2008

2009

Oil & NGLs
Natural Gas

2005

2006

2007

2008

2009

10000

20000

30000

40000

* based on proved plus probable reserves

1000

2000

3000

4000

5000

NORTHEAST
BC

FORT
ST. JOHN

EDMONTON

PEMBINA

CALGARY

SHAUNAVON

REGINA

BONTERRA ENERGY CORP. 9

operAtions oVerView:

Bonterra’s asset base consists of stable, producing properties located mainly in the Pembina field
in central Alberta as well as northeast British Columbia and Saskatchewan. Its property portfolio is
characterized by a long reserve life and low-risk, predictable returns.

In 2009, the Company developed and expanded its Pembina Cardium multi-stage frac program.
Bonterra has been at the forefront of developing this new, exciting play and has been successful in
capitalizing on a significant upside.

Bonterra’s approach to its operations has been to strategically allocate capital, continue to add to
its significant land base and use advanced industry technology to develop its best opportunities.

production and reserves

Bonterra’s production volumes average 4,994 BOE per day in 2009, an increase of 15 percent over
2008 levels. Production was comprised of approximately 63 percent crude oil and natural gas liquids
(NGLs) and 37 percent natural gas. Production increases can be attributed to the 2009 Pembina
Cardium horizontal and vertical drill programs, improved operations and acquisitions offset by the
disposition of a portion of its Shaunavon property (approximately 210 BOE per day). As well, the
Company’s capital development program was executed during the second half of the year. As such,
new production came on later in the year and thus its impact on the annual average production rates
was moderated.

Operations

2009 PRODUCTION BY COMMODITY

Oil & NGLs
Natural Gas

Bonterra’s low decline production results from its high-quality reserve base. In 2009, Bonterra
increased Total Proved (TP) reserves by 5.0 percent and Proved plus Probable (P+P) reserves by
14.7 percent to total 25.3 million BOE and 35.8 million BOE, respectively. The Company’s reserve life
index on a P+P basis is 20.1 years, well above industry-average.

A total of 2.2 million BOE on a TP basis and 6.6 million BOE on a P+P basis of net reserves have been
assigned to 28.1 net (34 gross) horizontal wells in the company’s Pembina Cardium horizontal project
(almost all in the Halo area). Development has been intentionally located beyond existing Cardium

BONTERRA ENERGY CORP. 10

pool production, in what is termed the Halo area, to reduce the possibility of drainage of existing wells and
in production without any water. There is minimal production history so reserves could only be assigned to a
limited number of locations at this time.

Once further drilling is completed and additional production history becomes available, new reserves may
be assigned as geological information appears to indicate that the undeveloped lands that have not been
assigned reserves have similar characteristics to currently producing lands to which reserves have been
assigned. Based on drilling four horizontal wells per section on the Halo area lands, up to 99 gross (88 net)
total wells could be drilled and have reserves assigned.

Using the same horizontal technology, Bonterra will also be evaluating the main portion of the Pembina
Cardium pool where the Company has a much larger land base. The Company has more than 1,000 gross
vertical locations in the Pembina Cardium field based on 40 acre spacing. The Company will be converting
some of these locations to horizontal locations after its evaluation is completed.

capital development program

During 2009, Bonterra spent approximately $22.9 million on its drilling program focusing mainly on the
Pembina Cardium play. The Company drilled seven Pembina Cardium horizontal wells (5.5 net), eight vertical
Pembina Cardium wells (6.9 net) and two natural gas wells (0.4 net) with a 100 percent success rate.

Bonterra’s first horizontal well was drilled in 2008 and was placed on production in early 2009. Bonterra
completed and tied in three (2.1 net) horizontal Cardium oil wells and six (4.9 net) vertical oil wells in 2009.
The additional four (3.4 net) horizontal Cardium oil wells and two (2.0 net) vertical wells were placed on
production in the first week of January 2010.

Subject to commodity prices and regulatory policies such as the Alberta government’s competition
review, Bonterra is projecting 2010 capital expenditures of $40 to $50 million. Most of the capital will once
again be focused on the Pembina Cardium horizontal drilling program with 20 to 30 gross additional wells
planned in 2010. Production is expected to average between 5,700 to 6,000 BOE per day.

Acquisitions and divestitures

A key part of the Company’s business has been to acquire additional lands in its core areas through both
corporate acquisitions or land sales. In July 2009, Bonterra completed its acquisition of Cobalt Energy Ltd.
(Cobalt) for a total calculated accounting cost of $7,105,000. The acquisition of Cobalt resulted in only a
modest increase in production but provided the Company with additional ownership in the Pembina Cardium
Halo area play, providing additional horizontal drilling opportunities. In addition Bonterra acquired and paid
$5,814,000 for mineral rights in the greater Pembina area of Alberta. These lands are located throughout

the Halo area of the Pembina field and an adjacent small amount in the Willesden Green field, providing
additional opportunities for the Company in developing its horizontal drilling program.

NETBACKS (AFTER REALIZED GAIN (LOSS) ON
RISK MANAGEMENT CONTRACTS) ($ PER BOE)

BONTERRA ENERGY CORP. 11

Bonterra divested a portion of its Shaunavon oil production to Eagle Rock in November 2009. 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 placing total consideration for the
property at $30,191,000. The book value (net of abandonment provision) of the property to the Company was
approximately $5,993,000 resulting in a gain on sale of $24,198,000.

2005

2006

2007

2008

2009

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 resulting in Bonterra holding 1,025,640 common shares of
Wild Stream.

Cash Netback Royalties Field Operating
G&A

Interest & Taxes

The funds were used to retire debt and provided additional room for Bonterra to accelerate its horizontal
drilling program at Pembina.

Subsequent to year-end, the Company divested its non-core Southeast Saskatchewan Pinto property.
Production from this property was approximately 60 BOE per day consisting primarily of higher-cost, light,
sweet crude oil production. The proceeds of disposition consisted of approximately $5.6 million and proceeds
were applied to the Company’s debt. The disposition closed in February, 2010.

operational excellence

Bonterra’s operating strategy continues to focus on reducing development risks, optimizing production
volumes and lowering operating costs to maximize netbacks. On a per BOE basis, production costs have
declined approximately 4.4 percent in 2009 compared to 2008 mainly due to field optimization and a general
decline in service and material costs resulting from decreased industry demand.

Bonterra operates approximately 85 percent of its total production which allows the Company to better
manage costs and efficiently invest capital through strategic scheduling of development programs, well
workovers and facility upgrades.

Finding, development and Acquisition costs

Finding, development and acquisition (FD&A) costs including future development costs in 2009 continue to
be among the lowest in the industry. Results from Bonterra’s ongoing operations, active capital development
program and the successful drilling program continue to meet or exceed expectations. FD&A costs including
acquisitions (and net of dispositions) in 2009 were $8.93 per BOE on a P+P basis compared with the previous
three year average of $9.45 per BOE on a P+P basis (2006 – 2008).

FINDING, DEVELOPMENT & ACQUISITION
COSTS (PROVED AND PROVED PLUS PROBABLE)

2008
3-year Average

2009
3-year Average

2007

2008

2009

Proved Proved plus Probable

Pembina Cardium Horizontal Drilling

WEST PEMBINA

T51

T50

T49

T48

T47

T46

T45

T44

T43

CARNWOOD

WARBURG

WILLESDEN GREEN

Bonterra Lands

R14

R13

R12

R11

R10

R2W5

overview

The Pembina Cardium field was discovered in 1953 and is now the largest conventional light oil field
in Canada, currently covering 755,000 acres. This mature field has been historically exploited through
infill drilling and waterflooding and has recently been further revitalized through the application of
horizontal drilling and multi-stage frac technology.

As one of the largest, long-term players in the Pembina field, Bonterra has been on the forefront of successfully
developing this play. The Company drilled the first successful Cardium Horizontal multi-stage fractured
well in the Halo area of the Pembina field. The enormous resource potential, encouraging results and robust
economics provide significant upside to the Company going forward.

geology

The reservoir is a stratigraphic trap producing from the Cardium formation at a depth of 1,200 to
1,850 meters that contains neither bottom water nor a free gas cap. The Cardium formation consists of
interbedded sandstone and shale which is capped in some areas with an effective higher permeability
conglomerate. The Cardium sandstone is generally thicker, has higher porosity, lower permeability and
therefore contains more of the original-oil-in-place than the conglomerate. The Cardium formation also
exhibits a preferential southwest to northwest stress orientation that controls flow direction of fluids and
hydraulic fracture orientation and therefore must be taken into account when selecting well locations in
the Cardium.

Economic vertical well production has historically been obtained in the main part of the Pembina Cardium
pool and consists of clean, well-sorted sandstones which may or may not have had an effective conglomerate
cap. Bonterra focused its initial horizontal development in the area surrounding the main part of the reservoir
in what is referred to as the “Halo” area – an area in which vertical wells have been uneconomic to drill.

The Halo area consists mainly of extensively bioturbated, interbedded sand units that may have a thinner
upper component of well sorted sandstone and generally does not have more than a thin inactive veneer of
conglomerate overlying the formation. The application of the multi-stage fracture technology in the Halo
area has allowed a portion of the reservoir that was once considered uneconomic to be actively developed
into producing reserves.

land base

Bonterra is the third largest land owner in the Pembina Cardium field with approximately 160 gross (117
net) sections of Cardium mineral rights. This includes 27.5 gross (23.0 net) sections in the Halo area and
the adjacent Willesden Green field. The Halo area land holdings are particularly significant at this time
as all Bonterra’s wells have been drilled in this area and have experienced virgin pressures with no water
production from waterflood.

BONTERRA ENERGY CORP. 13

wArbUrg

MAIN POOL
MAIN POOL

9-25: Drilling

T48

16-30: Drilled

16-25: 265 bbls/day average;
7940 bbls total

1-25: 120 bbls/day average;
43453 bbls total

8-30: 276 bbls/day average;
21260 bbls total

16-19: 147 bbls/day average;
26700 bbls total

12-24: 81 bbls/day average;
2436 bbls total

T47

16-13: 28 bbls/day average;
2260 bbls total

HALOHALO

T46

R2W5

cArnwood

MAIN POOL
MAIN POOL

16-11: Location

8-11: On Production Feb 2010

T48

16-27: 150bbls/day average;
4361 bbls total

8-27: On Production April 2010

HALOHALO

T47

R4W5

T46

BONTERRA ENERGY CORP. 14

west pembinA

2222

HALOHALO

T48

4-32: Drilled

8-27: Drilling

16-27: On Production
April 2010

1-27: On Production
Feb 2010
T47

14-23: Location

MAIN POOL
MAIN POOL

T46

T51

T50

R2W5

T49

R13

R12

R11W5

Bonterra’s lands in the main part of the Pembina Cardium reservoir are generally underdeveloped when
compared to other operators in the field who have typically drilled the Cardium down to 40 acre spacing (16
wells per section). Bonterra has over 1,000 gross additional vertical locations on existing lands if drilled to
this spacing and the Company is currently evaluating converting at least some of these potential vertical
locations to horizontals.

drilling and completion

Bonterra has applied conventional horizontal drilling technology to maximize the amount of Cardium
reservoir accessed in each lateral leg. Depending on the well location, surface locations are chosen which
both minimize the environmental footprint as well as optimize the section of the well for the area spacing
requirements and future pumping equipment. Intermediate casing is set one meter into the Cardium sand
which allows the lateral to begin traversing the sand from the top to find the most optimal placement within
the sand according to area geology and reservoir simulation. The utilization of best drilling practices including
bit selection and hydraulics, mud system design and maintenance and directional drilling combined with
experienced wellsite supervision are key factors in achieving operational success. In 2009, Bonterra drilled
eight (gross) horizontal wells averaging 1,220 meters in horizontal length without operational failure. The
ongoing drilling target is to achieve between 1,200 to 1,300 meters of lateral length in each well.

willesden green lAnds

reserves

2323

2424

1919

2020

2121

2222

2323

2424

1414

1313

1818

1717

1616

1515

1414

1313

1111

1212

1010

HALOHALO

1111

122

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

1818

311

3030

2020

2121

2222

1717

1616

1515

1010

3232

3333

3434

2929

2828

2727

4-25: Drilling

199

1818

2020

2121

2222

177

1616

155

T43

1111

1212

1010

1111

1212

MAIN POOL
MAIN POOL

1010

3535

3636

3131

3232

3333

3434

3535

3636

3131

3232

3333

3434

T42

R10

R8W5

The Pembina Cardium field represents Canada’s single largest conventional petroleum reservoir with an
immense volume of original-oil-in-place estimated at over 7.8 billion barrels with an average recovery to date of
approximately 17 percent. These original-oil-in-place and recovery numbers do not include the large Halo area.

T44

Approximately 89.2 percent of the Company’s Proved plus Probable (P+P) reserves and 84.6 percent of
Total Proved (TP) reserves are assigned to the Cardium. Bonterra’s reserves are very stable and its reserve
life index at 14.2 years on a TP basis and 20.1 years on a P+P basis is one of the longest in the Canadian
energy sector.

A total of 2.2 million BOE on TP basis and 6.6 million BOE on a P+P basis of reserves net to the company have
been assigned to 28.1 net (34 gross) horizontal Cardium wells in this year’s reserves report. The following
table shows that reserves as high as 145 MBOE on a TP basis and 250 MBOE on a P+P basis have been
assigned in our independent engineering evaluation.

BONTERRA ENERGY CORP. 15

(typical 100% gross)

‘Halo’ Area with Successful Hz Producers

‘Halo’ Edge with Hz Production

‘Halo’ Area with Limited Hz Production History

Mbbl / Well

MBOE / Well

Proved

P+P

Proved

P+P

145

250

125

250

158

272

136

272

‘Halo’ Area with Offsetting Vertical Well Production History

50-75

125-250

54-82

136-272

Wells in Waterflooded Portion of Main Pembina Cardium Pool

125

136

Reserves assigned varied for each well and was dependent upon the geology, development in the area
and production history. Since there is minimal production history and the development in the Halo area is
intentionally located beyond existing Cardium pool production to reduce the possibility of depletion and
water production, reserves could only be assigned to a limited number of horizontal well locations at this
time as per NI 51-101 standards. Once additional drilling is completed and additional production history is
available, additional reserves could be assigned. Management believes that geological information indicates
that the undeveloped lands that have not been assigned reserves have similar characteristics to currently
producing lands to which reserves has been assigned.

A reserves simulation was conducted by Bonterra’s independent engineering firm as part of the 2009 reserve
evaluation. The simulation was based on limited production history conducted on the east portion of the
Company’s Halo area lands and indicated that lands could be developed at four wells per section without a
reduction in reserves assigned for each well. Additional drilling density of up to seven wells per section was
shown to result in a reduced recovery per well of 17.5 percent but still resulted in significant increased total
reserves and an increased recovery factor.

capital development program

Subject to commodity prices and regulatory and royalty policy, Bonterra is planning to drill approximately 20
to 30 gross horizontal Cardium wells in 2010. The majority of the horizontal wells will be in the Halo area. The
Company has identified up to 65 gross (60 net) potential additional Cardium horizontal locations presently
not included in the independent engineering evaluation based on drilling at four wells per section on Halo
lands with no reserves currently assigned for a total of 99 gross wells (88 net wells).

Bonterra will also conduct some drilling in the main portion of the pool with the objective of converting some
of the 1,000 gross potential vertical wells to horizontal locations.

BONTERRA ENERGY CORP. 16

Statistical Review

BONTERRA ENERGY CORP. 17

stAtisticAl reView

reserves

Bonterra engaged the services of Sproule Associates Limited to prepare a reserve evaluation with an
effective date of December 31, 2009. The reserves are located in the provinces of Alberta, British Columbia
(BC) and Saskatchewan. Bonterra’s largest producing area is located in the Pembina Field of Alberta, which
contains 89.3 percent of the Company’s reserves on a Proved plus Probable basis. The gross reserve figures
for the following tables represent Bonterra’s ownership interest before royalties and before consideration of
the Company’s royalty interests. Tables may not add due to rounding.

summary of oil and gas reserves as of december 31, 2009

Reserve Category:

PROVED

Developed Producing

Developed Non-Producing

Undeveloped

TOTAL PROVED

PROBABLE

TOTAL PROVED PLUS PROBABLE

Light and
Medium Oil
Gross
(Mbbl)

Natural
Gas
Gross
(MMcf)

Natural Gas
Liquids
Gross
(Mbbl)

BOE
Gross
(MBOE)

14,248

220

3,284

17,752

7,923

25,675

32,103

760

3,779

36,642

12,896

49,539

1,271

190

1,468

425

1,893

20,869

354

4,104

25,327

10,497

35,824

BONTERRA ENERGY CORP. 18

reconciliation of company gross reserves by principal product type as of december 31, 2009

Light and Medium Oil and
Natural Gas Liquids

Natural Gas

BOE

Gross
Proved
(Mbbl)

Gross
Proved Plus
Probable
(Mbbl)

Gross
Proved
(Mmcf)

Gross
Proved Plus
Probable
(Mmcf)

Gross
Proved
(MBOE)

Gross
Proved Plus
Probable
(MBOE)

17,991

1,983

2,138

142

(1,010)

(877)

(1,146)

19,220

22,867

6,062

1,579

253

(1,151)

(895)

(1,146)

27,568

36,571

1,024

3,350

(7)

(290)

(4,059)

36,642

50,246

2,540

1,034

(9)

(309)

(4,059)

49,539

24,086

2,154

2,696

151

(1,011)

(925)

(1,823)

25,327

31,241

6,485

1,751

269

(1,152)

(947)

(1,823)

35,824

December 31, 2008

Extension

Improved recovery

Technical revisions

Discoveries

Acquisitions

Dispositions

Economic factors

Production

December 31, 2009

BONTERRA ENERGY CORP. 19

summary of net present Values of Future net revenue as of december 31, 2009

net present Values of Future net revenue
before income taxes
discounted at (% per year)

($ Millions)

Reserve Category:

PROVED

Developed Producing

Developed Non-Producing

Undeveloped

TOTAL PROVED

PROBABLE

TOTAL PROVED PLUS PROBABLE

10%

15%

20%

1,045.3

15.8

135.5

1,196.6

702.9

1,899.5

580.8

13.0

102.4

696.2

260.6

956.9

407.6

11.2

79.2

498.1

135.6

633.7

319.1

9.9

62.3

391.4

84.7

476.1

264.8

9.0

49.7

323.4

58.4

381.8

net present Values of Future net revenue
After income taxes
discounted at (% per year)

($ Millions)

Reserve Category:

PROVED

Developed Producing

Developed Non-Producing

Undeveloped

TOTAL PROVED

PROBABLE

TOTAL PROVED PLUS PROBABLE

10%

15%

20%

903.8

11.8

101.4

1,017.0

527.4

1,544.5

533.5

10.6

79.4

623.4

195.8

819.2

387.5

9.6

63.3

460.4

102.5

562.9

309.1

8.9

51.1

369.1

64.5

433.7

259.4

8.3

41.6

309.3

44.9

354.2

BONTERRA ENERGY CORP. 20

commodity prices used in the above calculations of reserves are as follows:

Year

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

Edmonton
Par Price

Alberta Gas
AECO-C Spot

Edmonton
Propane

Edmonton
Butane

Edmonton
Pentane

(Cdn $ per bbl)

(Cdn $ per MMBtu)

(Cdn $ per bbl)

84.25

89.99

92.61

96.19

98.13

100.11

102.13

104.19

106.30

108.44

110.63

5.36

6.21

6.44

7.23

7.98

8.16

8.34

8.52

8.71

8.90

9.10

52.74

56.33

57.97

60.21

61.43

62.67

63.94

65.23

66.54

67.89

69.26

59.65

63.72

65.57

68.11

69.48

70.89

72.32

73.78

75.27

76.79

78.34

86.28

92.16

94.84

98.51

100.50

102.53

104.60

106.71

108.86

111.06

113.30

Crude oil, natural gas and liquid prices escalate at two percent per year thereafter.

BONTERRA ENERGY CORP. 21

2009 Finding and development costs (F&d) and Finding, development and Acquisitions
costs (Fd&A)

The Company has been active in its capital development program over the past three years. Over this time
period Bonterra has incurred the following F&D and FD&A(3) Costs:

2009 F&d
costs per
boe (1)(2)

2008 F&D
Costs per
BOE (1)(2)

2007 F&D
Costs per
BOE (1)(2)

2009
three year
Average

2008
Three Year
Average

Proved Reserve Additions

Proved plus Probable Reserve Additions

$ 16.23

$ 11.01

7.00

6.82

2.15

2.02

8.46

$ 11.55

6.62

9.02

2009 Fd&A
costs per
boe (1)(2)(3)

2008 FD&A
Costs per
BOE (1)(2)(3)

2007 FD&A
Costs per
BOE (1)(2)(3)

2009
three year
Average

2008
Three Year
Average

Proved Reserve Net Additions

$ 13.25

Proved plus Probable Reserve Net Additions

8.93

8.67

7.47

2.74

2.68

8.22

$ 12.30

6.36

9.45

The above figures have been calculated in accordance with National Instrument 51-101 (NI 51-101) where the
2009 F&D Costs equate to the total exploration and development costs incurred by the Company of $28,726,000
(includes $5,814,000 for undeveloped land) as calculated according to GAAP plus or minus the yearly change
in estimated future development costs as calculated by Sproule Associates Limited ($34,960,000 for Proved
and $51,538,000 for Proved plus Probable). FD&A costs include acquisition costs of $7,105,000 as well as
proceeds of disposition of $30,191,000.

The following precautionary notes have been provided as required by NI 51-101.

(1) Barrels of Oil Equivalent may be misleading, particularly if used in isolation. A BOE conversion ratio of 6MCF:1bbl
is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent
a value equivalency at the wellhead.

(2) The aggregate of the exploration and development costs incurred in the most recent financial year and the change
during that year in estimated future development costs generally will not reflect total finding and development
costs related to reserve additions for that year.

(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.

BONTERRA ENERGY CORP. 22

All reserve 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 the 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.

production
The following table provides a summary of production volumes from the Company’s main producing areas:

Pembina area, AB

Shaunavon area, SK

Prespatou area, BC (1)

Other

2009

2008

oils and ngls
(bbls per day)

natural gas
(mcF per day)

Oils and NGLs
(Bbls per day)

Natural Gas
(MCF per day)

2,595

318

201

3,141

6,419

3,706

995

11,120

2,520

313

237

3,073

6,376

526

735

7,637

(1) The Northeast BC properties were acquired in the Silverwing acquisition which closed on November 12, 2008 and

thus had little impact on 2008 production volumes.

land holdings
Bonterra’s holding of petroleum and natural gas leases and rights are as follows:

Alberta

Saskatchewan

British Columbia

2009

2008

gross Acres

net Acres

Gross Acres

Net Acres

168,749

14,483

73,910

257,142

106,785

12,793

30,373

149,951

152,917

31,182

73,910

258,009

92,438

28,000

30,373

150,811

BONTERRA ENERGY CORP. 23

petroleum and natural gas capital expenditures
The following table summarizes petroleum and natural gas capital expenditures incurred by Bonterra on
acquisitions, land, seismic, exploration and development drilling and production facilities for the years ended
December 31:

Land

Acquisitions

Disposals

Exploration and development costs

Net petroleum and natural gas capital expenditures

drilling history

2009

2008

$ 5,814,000

376,000

7,105,000

(30,191,000)

15,347,000

22,912,000

29,684,000

$ 5,640,000

$ 45,407,000

The following table summarizes the Company’s gross and net drilling activity and success:

development

2009

exploratory

total

gross

net

gross

net

gross

net

15.0

2.0

17.0

100%

12.4

0.4

12.8

100%

Development

2008

Exploratory

15.0

2.0

17.0

100%

Total

Gross

Net

Gross

Net

Gross

Net

35.0

8.0

43.0

100%

25.5

5.1

30.6

100%

0.2

100%

36.0

8.0

44.0

100%

12.4

0.4

12.8

100%

25.7

5.1

30.8

100%

Crude oil

Natural gas

Dry

Total

Success rate

Crude oil

Natural gas

Dry

Total

Success rate

BONTERRA ENERGY CORP. 24

Development

2007

Exploratory

Total

Gross

Net

Gross

Net

Gross

Net

22.0

2.0

24.0

100%

15.3

0.7

16.0

100%

22.0

2.0

24.0

100%

15.3

0.7

16.0

100%

Crude oil

Natural gas

Dry

Total

Success rate

tax pools

The Company has the following tax pools, which may be used to reduce taxable income in future years,
limited to the applicable rates of utilization:

($000)

Undepreciated capital costs

Eligible capital expenditures

Share issue costs

Canadian oil and gas property expenditures

Canadian development expenditures

Canadian exploration expenditures

SR&ED expenditures

Federal income tax losses carried forward(1)

Rate of
Utilization (%)

20-100

100

Amount

21,671

7,363

2,973

26,282

59,141

11,174

80,357

223,629

432,590

(1) Federal income tax losses carried forward expire in the following years; 2013 – $1,069,000, 2024 – $3,347,000,

2025 – $7,532,000, 2026 – $46,670,000, 2027 – $117,189,000, 2028 – $34,726,000, 2029 – $13,096,000.

The Company has $27,670,000 (2008 – $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 $143,061,000 of capital loss carry forwards which can only be claimed against taxable
capital gains.

BONTERRA ENERGY CORP. 25

shAre/trUst Unit trAding stAtistics

(Based on daily closing price)

High

Low

Daily Average Trading Volume

bonterrA Vs. the indices

2009

36.44

13.50

35.14

22,704

2008

30.80

15.50

17.27

23,031

250

200

150

100

2004

2005

2006

2007

2008

2009

BNE

TSX Composite Index

TSX Energy Index

BONTERRA ENERGY CORP. 26

Management’s Discussion
and Analysis

BONTERRA ENERGY CORP. 27

This report dated March 9, 2010 is a review of the operations, current financial position, and outlook for
Bonterra Energy Corp. (“Bonterra” or the “Company”) (formerly Bonterra Oil & Gas Ltd.) and should be read
in conjunction with the audited financial statements for the year ended December 31, 2009, 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/
distributions to shareholders/unitholders 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.

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

BONTERRA ENERGY CORP. 28

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.

BONTERRA ENERGY CORP. 29

AnnUAl compArisons

Financial ($ 000s, except $ per share/unit)

Revenue – realized oil and gas

Cash flow from operations

Per share / unit basic

Per share / unit diluted

Cash payments per share/unit (1)

Payout ratio (1)

Net earnings

Per share / unit basic

Per share / unit diluted

Capital expenditures and acquisitions (net of disposals)

Total assets

Working capital deficiency

Long-term debt

Shareholders’/unitholders’ equity

Operations

Oil and liquids (barrels per day)

Natural gas (MCF per day)

Total BOE per day

2009

2008

2007

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

96,431

51,433

3.04

2.64

87%

30,350

1.79

19,300

142,326

58,766

44,376

3,113

6,627

4,218

(1) Cash dividend/disbursement payments per share/unit are based on payments made in respect of production

months as opposed to the month paid.

BONTERRA ENERGY CORP. 30

QUArterly compArisons

Financial ($ 000s, except $ per share)

Revenue – realized oil and gas sales

Cash flow from operations

Per share basic

Per share fully diluted

Cash payments per share (1)

Payout ratio (1)

Net earnings

Per share basic

Per share fully 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

2009

3rd

2nd

1st

20,965

9,350

0.50

0.44

87%

5,790

0.32

17,660

273,543

14,455

81,386

74,025

3,084

10,881

4,898

20,501

9,238

0.52

0.40

77%

4,544

0.26

2,255

258,393

13,989

71,573

72,332

3,029

11,551

4,954

19,300

6,632

0.38

0.36

94%

6,093

0.35

2,701

260,732

14,909

89,383

56,377

3,268

11,877

5,245

(1) Cash dividend/disbursement payments per share/unit are based on payments made in respect of production

months as opposed to the month paid.

Financial ($ 000s, except $ per share/unit)

Revenue – realized oil and gas sales

Cash flow from operations

Per share / unit basic

Per share / unit fully diluted

Cash payments per share/unit (1)

Payout ratio (1)

Net earnings

Per share / unit Basic

Per share / unit fully diluted

Capital expenditures and acquisitions

(net of disposals)

Total assets

Working capital deficiency

Long-term debt

Shareholders/unitholders’ equity

Operations

Oil and liquids (barrels per day)

Natural gas (MCF per day)

Total BOE per day

4th

22,613

10,336

0.59

0.62

105%

10,585

0.62

30,405

265,301

23,878

79,910

56,777

3,055

8,817

4,525

BONTERRA ENERGY CORP. 31

2008

3rd

2nd

1st

34,226

22,492

1.31

1.30

0.96

73%

21,125

1.23

1.22

6,038

150,120

47,499

57,623

2,998

7,233

4,204

34,398

20,530

1.21

1.20

0.84

69%

12,912

0.76

0.75

2,543

153,247

57,148

46,612

3,009

7,272

4,221

30,493

16,212

0.96

0.70

73%

10,804

0.64

6,421

150,169

57,810

48,136

3,153

7,139

4,343

(1) Cash dividend/disbursement payments per share/unit are based on payments made in respect of production

months as opposed to the month paid.

BONTERRA ENERGY CORP. 32

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, 2009 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:

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

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.

BONTERRA ENERGY CORP. 33

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:

pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the
transactions and dispositions of the assets of the issuer;

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

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, 2009 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 COSO. In its evaluation, the
Company identified certain weaknesses in internal controls over financial reporting:

due to the limited number of staff at the Company, it is not feasible to achieve the complete
segregation of incompatible duties; and

due to the limited number of staff, the Company relies upon third parties as participants in the
Company’s internal controls over financial reporting.

The Company believes these weaknesses are mitigated by: the active involvement of senior management
and the board of directors in the affairs of the Company; open lines of communication within the Company;
the present levels of activities and transactions within the Company being readily transparent; the thorough
review of the Company’s financial statements by management, the board of directors and by the Company’s
auditors (annual statements only); and the establishment of a whistle-blower policy. Based on the above

BONTERRA ENERGY CORP. 34

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 2009 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 2009.

prOductiOn

Three months ended

Twelve months ended

december
31, 2009

September
30, 2009

December
31, 2008

december
31, 2009

December
31, 2008

Crude oil and NGLs (barrels per day)

Natural gas (MCF per day)

Average BOE per day

3,182

10,193

4,881

3,084

10,881

4,898

3,055

8,817

4,525

3,141

11,120

4,994

3,073

7,637

4,346

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.

Bonterra’s 2009 average production increased 14.9 percent on a per BOE basis over 2008 despite the sale
of the Shaunavon property of 210 BOE per day. Crude oil production increased by 2.2 percent while gas
production increased by 45.6 percent. The natural gas increase was due primarily to the acquisition of
Silverwing Energy Inc. (Silverwing) on November 12, 2008 which resulted in approximately 3,600 MCF per day
being added to production.

BONTERRA ENERGY CORP. 35

On November 6, 2009, the Company disposed of a portion of its Shaunavon property for gross proceeds of
$30,191,000. The production from this property was averaging approximately 210 BOE per day consisting
entirely of medium grade crude oil.

In 2009, Bonterra drilled seven Pembina Cardium horizontal wells (5.5 net), eight vertical Pembina Cardium
wells (6.9 net) and participated in drilling two natural gas wells (0.4 net). Bonterra recorded a 100 percent
success rate with its 2009 drilling program. The Company’s first horizontal well was drilled in 2008 and was
placed on production in Q1 2009. Bonterra has completed and tied in three (2.1 net) horizontal Cardium oil
wells and six (4.9 net) vertical oil wells in 2009. The additional four (3.4 net) horizontal Cardium oil wells and
two (2.0 net) vertical wells were placed on production in the first week in Q1 2010.

In November, the Company engaged the services of a second drilling rig and in March a third drilling rig was
added and will continue its Pembina Cardium horizontal well drilling program with all rigs until road bans are
imposed in March 2010. The acquisition of Cobalt Energy Ltd. (Cobalt) effective July 1, 2009 resulted in only
a modest increase in production but provided the Company with additional ownership in potential Pembina
Cardium horizontal drilling opportunities.

Even with the above mentioned disposition, the company was able to increase its Q4 crude oil production
through its 2009 Pembina Cardium horizontal and vertical drill programs. The Company’s fourth quarter
production in 2009 saw increases in crude oil of 98 barrels per day and a decline in natural gas of 688 MCF
per day production over Q309. Exit production for the four (2.73 net) producing Pembina Cardium horizontal
wells was approximately 456 (311 net) BOE per day. The Q4 natural gas decline is mainly due to shut in and
restricting production of some of the Company’s gas wells as well as natural production declines.

Bonterra expects 2010 production to average between 5,700 and 6,000 BOE per day.

reVenUe

(Cdn $)

Three months ended

Twelve months ended

december
31, 2009

September
30, 2009

December
31, 2008

december
31, 2009

December
31, 2008

Revenue – oil and gas sales (000s)

24,946

20,965

22,613

85,712

121,730

Average Realized Prices:

Crude oil and NGLs (per barrel)

Natural gas (per MCF)

68.40

4.76

65.38

3.13

58.91

7.00

59.82

4.15

87.54

8.21

BONTERRA ENERGY CORP. 36

Revenue from petroleum and natural gas sales decreased 29.6 percent in 2009 compared to 2008 primarily due
to a 31.7 percent drop in crude oil prices and a 49.5 percent drop in natural gas prices. The drop in commodity
prices was partially offset with the above mentioned production increases. During 2009 the Company did not
enter into any risk management contracts.

Quarter over quarter the Company saw an increase in revenues of $3,981,000 due to improved crude oil and
natural gas prices in the fourth quarter of 2009.

royAlties

($ 000s) except $ per BOE

december
31, 2009

September
30, 2009

December
31, 2008

december
31, 2009

December
31, 2008

Three months ended

Twelve months ended

Crown royalties

Freehold royalties, gross overriding
royalties and net carried interests

Total royalty expense

Percentage of Revenue

$ per BOE

1,451

892

2,343

9.4

5.22

1,248

697

1,945

9.3

4.32

2,337

558

2,895

12.8

6.86

4,737

13,736

2,677

7,414

8.6

4.07

3,479

17,215

14.1

10.82

Royalties paid by the Company consist primarily of Crown royalties paid to the Provinces of Alberta,
Saskatchewan and British Columbia. The majority of the Company’s wells are low productivity wells and
therefore have lower Crown royalty rates. The Company’s average Crown royalty rate was approximately
5.5 percent (2008 – 10.6 percent) and approximately 3.1 percent (2008 – 2.7 percent) for other royalties. The
increase in other royalty rates is due to the new horizontal oil wells being drilled on freehold mineral rights
land.

The recently announced new Alberta Crown royalty rates vary by prices as well as productivity levels. With
lower commodity prices in 2009 compared to 2008 and the Silvering acquisition (mostly BC production with
lower Crown royalty rates) the Company has experienced a significant reduction in Crown royalties in 2009.

The fourth quarter royalties have increased $398,000 over third quarter due primarily to higher crude oil and
natural gas pricing and an increased proportion of the Company’s production coming from the new horizontal
oil wells which are subject to freehold royalties at approximately 17 percent compared to a 5 percent royalty
rate on Crown wells.

BONTERRA ENERGY CORP. 37

inVestment tAx credit recoVery

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 continued 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 in the justification that the ITC’s are likely to be claimed.

gAin on sAle oF property

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 was $0.21 placing total consideration for the property at $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.

prodUction costs

($ 000s) except $ per BOE

december
31, 2009

September
30, 2009

December
31, 2008

december
31, 2009

December
31, 2008

Three months ended

Twelve months ended

Production costs

$ per BOE

6,870

15.30

6,585

15.79

6,859

16.25

27,848

15.28

25,413

15.98

Total production costs in 2009 have increased by $2,435,000 over 2008. The increase is due to increased
production volumes (see Production). On a per BOE basis, production costs have declined in 2009 compared
to 2008 mainly due to field optimization and a general decline in service and material costs resulting from
decreased industry demand.

BONTERRA ENERGY CORP. 38

Total operating costs increased slightly in the fourth quarter of 2009 compared to the prior quarter due
primarily to the billing of prior year gas processing charge adjustments in 2009 of approximately $200,000 by
the operator of several of the Company’s non-operated gas plants. On a per-unit-of-production basis, the 2009
rates were $0.49 lower than in 2008.

As discussed above, Bonterra’s production comes primarily from low productivity wells. These wells generally
result in higher operating costs on a per-unit-of-production basis as costs such as municipal taxes, surface
leases, power and personnel costs are not variable with production volumes. The Company is continually
examining ways to reduce operating costs.

generAl And AdministrAtiVe expense

($ 000s) except $ per BOE

december
31, 2009

September
30, 2009

December
31, 2008

december
31, 2009

December
31, 2008

Three months ended

Twelve months ended

G&A Expense

$ per BOE

1,623

3.61

788

1.75

824

1.95

4,458

2.45

3,401

2.14

General and administrative (G&A) expenses increased 31 percent in 2009 compared to 2008. The Company
provides administrative services to Comaplex Minerals Corp. (Comaplex) (TSX: CMF) 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 are employee compensation; professional
services such as legal, engineering and accounting; computer services and bank charges. Employee
compensation expense decreased by approximately 7 percent ($279,000) in 2009 from 2008 due to a smaller
bonus accrual. The Company’s bonus plan consists of cash payments equal to three percent of before tax
net earnings (excluding the investment tax credit recovery) to be paid to employees and key consultants
based on performance throughout the year. Costs associated with professional services increased by
approximately $115,000 due to additional accounting (new production accounting software) and engineering
services (horizontal well evaluations).

Computer services increased by $367,000 due to significant increases in the cost of new licensing agreements
for the Company’s engineering and accounting software and the contracting of an external manager of IT.
The largest increase to G&A was bank charges of $678,000 relating to the cost of establishing a new bank
facility as well as increased standby fees on the unused portion of the Company’s credit facility.

BONTERRA ENERGY CORP. 39

The quarter over quarter increase of $835,000 was primarily due to a special bonus accrual of approximately
$532,000 on the gain on sale of the Shaunavon property, legal and accounting costs increase of approximately
$80,000 associated with the amalgamation of the various Bonterra entities in December of 2009 and $55,000
of engineering costs associated with various horizontal well evaluations.

During the year the Company capitalized $359,000 (2008 – $426,000) of general and administrative costs.

interest expense

($ 000s) except $ per BOE

december
31, 2009

September
30, 2009

December
31, 2008

december
31, 2009

December
31, 2008

Three months ended

Twelve months ended

Interest Expense

$ per BOE

738

1.64

815

1.81

746

1.77

3,294

1.81

2,740

1.72

Bank debt at December 31, 2009 was $59,823,000 (December 31, 2008 – $93,235,000). 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 $23,500,000 from two related parties. Please see Related Party Transactions
section for further details.

Interest charges increased in 2009 as the average outstanding debt balance (including related party
balances) increased by approximately $22 million over 2008. The acquisitions of Silverwing and Cobalt as
well as the reorganization costs to change Bonterra into a corporation resulted in approximately $47 million
of additional debt. In addition the Company has incurred approximately $28 million in capital expenditures
during this period. These increases were partially offset by net proceeds of approximately $17,000,000 from
a 2009 second quarter private equity issue and approximately $24 million cash on the sale of the Shaunavon
property in November. Offsetting the increased debt balance was an average reduction of 0.3 percent
(4.3 percent in 2008 to 4.0 percent in 2009) in interest rates paid on the outstanding debt balances.

Quarter over quarter saw a decrease in interest charges due to reduced debt balances resulting from
proceeds of the Shaunavon sale being applied to the bank debt.

Effective April 29, 2009, the Company entered into a new bank facility with new terms and conditions. The
new facility consists of a $100,000,000 syndicated revolving credit facility and a $20,000,000 non-syndicated
revolving credit facility.

BONTERRA ENERGY CORP. 40

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

125

275

Level II

Level III

Level IV

Level V

Over 1.0:1
to 1.5:1

Over 1.5:1
to 2.0:1

Over 2.0:1
to 2.5:1

150

300

175

325

200

350

Over
2.5:1

250

400

(1) Consolidated total funded debt excludes related party amounts but includes working capital.
(2) Numbers in table represent basis points.

Consolidated total funded debt to consolidated cash flow ratio shall be adjusted effective as of the first day
of the next fiscal quarter following the end of each fiscal quarter, with each such adjustment to be effective
until the next such adjustment.

As of December 31, 2009 the Company will qualify for the Level I interest rates. The revised rates will apply
commencing April 1, 2010 resulting in a reduction of 50 basis points in the cost of the Company’s bank
borrowings.

reorgAnizAtion costs

Based on accounting principles, costs associated with
into
Bonterra Oil and Gas Ltd. must be expensed. The costs consisted of a $1,000,000 finders fee paid to a company
that facilitated the reorganization, $931,000 of professional fees, $150,000 stock exchange fees and $40,000
of costs associated with the distribution of the reorganization document. These costs were all one-time
costs and no further costs were incurred by the Company in direct relation to the reorganization.

the Trust’s 2008 reorganization

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 33,000 stock
options during 2009 resulting in a reduction of stock-based compensation by $296,000.

The 33,000 common share options were issued with an exercise price of $14.90 per share and a fair value of
$1.58 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 1.4 percent (2008 – 2.2 percent), expected
weighted average volatility of 33 percent (2008 – 31 percent), expected weighted average life of 3.0 years
(2008 – 3.5 years) and an annual dividend/distribution rate based on the dividends paid to the shareholders
during the year.

BONTERRA ENERGY CORP. 41

depletion, depreciAtion, Accretion And dry hole costs

The Company follows the successful efforts method of accounting for petroleum and natural gas exploration
and development costs. Under this method, the costs associated with dry holes are charged to operations.
For intangible capital costs that result in the addition of reserves, the Company depletes its oil and natural
gas intangible assets using the unit-of-production basis by field.

For tangible assets such as well equipment, a life span of ten years is estimated and the related tangible costs
are depreciated at one tenth of original cost per year. The use of a ten year life span instead of calculating
depreciation over the life of reserves was determined to be more representative of actual costs of tangible
property. Given the Company’s long production life of its wells, the wells generally require replacement of
tangible assets more than once during their life time. Most of the Company’s wells have been producing since
the 1960’s and are expected to continue to produce for at least another twenty years.

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, 2009, the estimated total undiscounted amount required to settle the asset retirement
obligations was $64,482,000 (2008 – $58,903,000). Of the $5,579,000 increase, the majority is due to increases
in anticipated costs of abandoning the Company’s producing and non producing wells.

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 $2,870,000. While a one percent decrease in the risk adjusted rate would increase the asset
retirement obligation by $3,949,000.

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.

BONTERRA ENERGY CORP. 42

For the fiscal year ending December 31, 2009, the Company expensed $19,277,000 (2008 – $14,749,000) for the
above-described items. The increase is predominately due to increased production volumes resulting from
the Silverwing acquisition and higher per BOE depletion charges on the Company’s horizontal Cardium oil
wells compared to Bonterra’s other production. The higher BOE depletion charges on the horizontal wells are
primarily due to lack of production history on these wells resulting in lower proved reserve 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. It is anticipated that as there is more production history on the horizontal wells
there will be a conversion of the probable reserves to proven reserves resulting in a reduction of depletion
charges per BOE in future years.

The Company continues to have relatively low finding and development costs (see discussion under Finding
and Development Costs). Based on year end reserves, the Company’s average cost of proved reserves is
$6.62 (2008 – $6.40) per BOE.

The Company currently has an estimated reserve life for its proved developed producing reserves of
11.7 (2008 – 12.5) years calculated using the Company’s gross reserves (prior to allowance for royalties)
based on the third party engineering report dated December 31, 2009 and using fourth quarter 2009 average
production rates of 4,879 BOE per day (2008 – 4,587 BOE per day). Based on total proved reserves the Company
has a 14.2 (2008 – 14.4) year reserve life and on a proved and probable basis the reserve life increases to
20.1 (2008 – 18.7) years. These figures are some of the longest reserve life indexes (excluding oil sands) in the
Canadian oil and gas industry.

income tAxes

On November 12, 2008, Bonterra Energy Income Trust converted to a corporation. As a result of the
reorganization, the Company has recorded a future income tax asset and a corresponding deferred tax
credit. These amounts will be amortized into future tax expense as the associated tax pools are consumed.

The current tax provision of $551,000 consists of a resource surcharge of $282,000 payable to the Province
of Saskatchewan and a tax amount of $269,000 payable to the Province of Quebec. 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 was three percent in 2009. The tax payable to the Province of
Quebec is a one-time charge that resulted from the Company’s conversion to a corporation.

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:

BONTERRA ENERGY CORP. 43

($ 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 %

Amount

20-100

21,671

100

7,363

2,973

26,282

59,141

11,174

80,357

223,629

432,590

(1) Federal income tax losses carried forward expire in the following years; 2013 – $1,069,000, 2024 – $3,347,000,

2025 – $7,532,000, 2026 – $46,670,000, 2027 – $117,189,000, 2028 – $34,726,000, 2029 – $13,096,000.

The Company also has $143,061,000 of capital loss carry forwards which can only be claimed against taxable
capital gains.

net eArnings

($ 000s) except $ per share

Net Earnings

$ per share- Basic

$ per share- Fully Diluted

Three months ended

Twelve months ended

december
31, 2009

September
30, 2009

December
31, 2008

december
31, 2009

December
31, 2008

52,136

2.88

2.85

5,790

0.32

10,585

68,563

55,426

0.62

3.81

3.78

3.25

3.23

BONTERRA ENERGY CORP. 44

Bonterra’s net earnings for the year ended December 31, 2009 represents a 23.7 percent increase over the
Company’s 2008 net earnings. The Company recorded net earnings per share in 2009 of $3.81 compared
to $3.25 in the 2008 year. This represents a return on Shareholders’ equity of approximately 57.7 percent
(2008 – 97.6 percent) based on year end Shareholders’ equity.

Two significant factors contributing to 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 decreased by $23,611,000 from $55,426,000 in 2008 to an adjusted net earnings
of $31,815,000 in 2009. Reduced revenues resulting from decreased commodity prices were the main reason
for the reduction. This reduction was partially offset by production volume gains. The Company continues to
return in excess of 25 percent of its gross realized oil and 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.

comprehensiVe income

Other comprehensive income for 2009 consists of an unrealized gain on investments (including investments
in a related party) of $600,000 (2008 loss of $1,611,000) including a fourth quarter loss of $478,000 relating to a
reduction in the investments fair value. Other comprehensive income varies from net earnings by changes in
the fair value of Bonterra’s holdings of investments including the investment in Comaplex.

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, 2009

September
30, 2009

December
31, 2008

december
31, 2009

December
31, 2008

13,673

0.76

0.75

9,350

0.50

10,336

38,893

69,570

0.59

2.16

2.15

4.07

4.06

Cash flow from operations decreased 44 percent year over year, mainly due to decreased commodity prices
received in 2009. Fourth quarter cash flow increased by $4,325,000 over Q3 due to recovering commodity
prices. The Company has not entered into any risk management agreements and as such is fully exposed to
changes in commodity prices and exchange rates.

BONTERRA ENERGY CORP. 45

cAsh netbAcks

The following table illustrates the Company’s cash netback:

$ per Barrel of Oil Equivalent (BOE)

Production volumes (BOE)

Gross production revenue

Realized gain (loss) on risk management contracts

Royalties

Production costs

Field netback

General and administrative (1)

Interest and taxes

Cash netback

2009

2008

1,822,628

1,590,666

47.04

81.15

(4.07)

(15.28)

27.69

(2.16)

(2.11)

(4.62)

(10.82)

(15.98)

49.73

(2.14)

(2.00)

23.42

45.59

The following table illustrates the Company’s cash netback for the three months ended:

$ per Barrel of Oil Equivalent (BOE)

Production volumes (BOE)

Gross production revenue

Royalties

Production costs

Field netback

General and administrative (1)

Interest and taxes

Cash netback

december 31,
2009

September 30,
2009

448,892

450,616

55.50

47.81

(5.22)

(15.30)

34.98

(2.43)

(1.80)

(4.32)

(15.79)

27.70

(1.75)

(1.99)

30.75

23.96

(1) General and administrative costs have been reduced by $532,000 relating to the bonus payment on the gain on sale

of property as the benefit has not been included in the above cash net back calculation.

BONTERRA ENERGY CORP. 46

relAted pArty trAnsActions

The Company holds 689,682 (2008 – 689,682) common shares in Comaplex which have a fair market value as
of December 31, 2009 of $4,827,000 (2008 – $2,131,000). Comaplex is a publically traded mineral company on
the Toronto Stock Exchange. The Company’s ownership in Comaplex represents less than one percent of the
issued and outstanding common shares of Comaplex. The Company has common directors and management
with Comaplex.

Comaplex paid a management fee to the Company of $330,000 (2008 – $330,000). Comaplex also shares office
rental costs and reimburses the Company for costs related to employee benefits and office materials. In
addition, Comaplex owns 204,633 (December 31, 2008 – 204,633) common shares in the Company. Services
provided by the Company include executive services (president and vice president, finance duties), accounting
services, oil and gas administration and office administration. In addition, Bonterra allocated $102,000 of
drilling tax credits to Comaplex for $51,000. All services performed are charged at estimated fair value. At
December 31, 2009, Comaplex owed the Company $105,000 (December 31, 2008 – $56,000).

As of December 31, 2009, Comaplex has loaned the Company $12,000,000 (December 31, 2008 – Nil). The loan
is unsecured and it has no set repayment terms. Until June 30, 2009 the Company paid interest at Canadian
chartered bank prime plus one quarter of a percent. Effective July 1, 2009, the interest rate was reduced
to Canadian chartered bank prime less 0.25 percent. The reduction in rate was due to the lowering of the
Company’s bank interest rate with its banking syndicate resulting from an improved debt to cash flow ratio
(see Interest Expense and Liquidity and Capital Resources sections) and since the benefits of this loan are
shared with Comaplex, the interest rate was reduced accordingly.

In 2008, in order to facilitate the acquisition of Silverwing, the Company borrowed on a short-term basis
$20,000,000 from Comaplex to allow time to finalize documentation for its new bank line of credit. The funds
were repaid on November 21, 2008.

Interest paid on these loans during 2009 and 2008 was $194,000 and $21,000, respectively. The loans result in a
substantial benefit to Bonterra and to Comaplex. The interest paid to Comaplex by Bonterra is substantially
lower than bank interest and the amount drawn on the bank line of credit is lower reducing the bank interest
rate. For Comaplex, the interest earned is substantially higher than Comaplex would receive by investing in
bank instruments such as BA’s or GIC’s.

The Company also has a management agreement with Pine Cliff. Pine Cliff has common directors and
management with the Company. Pine Cliff trades on the TSX Venture Exchange. Pine Cliff paid a management
fee to the Company of $120,000 (2008 – $238,000). Services provided by the Company include executive
services (president and vice president, finance duties), accounting services, oil and gas administration and

BONTERRA ENERGY CORP. 47

office administration. All services performed are charged at estimated fair value. The Company has no share
ownership in Pine Cliff. As at December 31, 2009 the Company had an account receivable from Pine Cliff of
$1,000 (December 31, 2008 – $1,000).

As of December 31, 2009, the Company’s CEO and major shareholder has loaned the Company $11,500,000
(December 31, 2008 – $6,000,000). The loan is unsecured, bears interest at Canadian chartered bank prime
and has no set repayment terms. Effective July 1, 2009, the interest rate was also decreased to Canadian
chartered bank prime less .25 percent. Interest paid on this loan in 2009 was $209,000 (2008 – $7,000). 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.

commitments

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

Total

944

932

829

496

3,201

FinAnciAl reporting UpdAte

On January 1, 2009, the Company adopted the Canadian Institute of Chartered Accountants (CICA)
Handbook Section 3064, “Goodwill and Intangible Assets”. The new section replaces the previous goodwill
and intangible asset standard and revises the requirement for recognition, measurement, presentation and
disclosure of intangible assets. The adoption of this standard had no impact on the Company’s consolidated
financial statements.

On January 20, 2009, the Company adopted the CICA’s Emerging Issues Committee (EIC) EIC-173, “Credit
Risk and the Fair Value of Financial Assets and Financial Liabilities”. The EIC provides guidance on how
to take into account credit risk of an entity and counterparty when determining the fair value of financial
assets and financial liabilities, including derivative instruments. The adoption of EIC-173 had no impact on
the Company’s consolidated financial statements.

BONTERRA ENERGY CORP. 48

In December 2008, the CICA issued Section 1582, “Business Combinations”, which will replace former
guidance on business combinations. Section 1582 establishes principles and requirements of the acquisition
method for business combinations and related disclosures. This statement applies prospectively to business
combinations for which the acquisition date is on or after the beginning of the first annual reporting period
beginning on or after January 1, 2011 with earlier adoption permitted.

In December 2008, the CICA issued Sections 1601, “Consolidated Financial Statements”, and 1602,
“Non-controlling Interests”, which replaces existing Section 1600. Section 1601 establishes standards for
the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for
a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business
combination. These standards are effective on or after the beginning of the first annual reporting period
beginning on or after January 2011 with earlier adoption permitted. Section 1602 currently does not impact
the Company as it has full controlling interest of all of its subsidiaries.

In 2009, the CICA issued amendments to CICA Handbook Section 3862, “Financial Instruments – Disclosures”.
The amendments include enhanced disclosures related to the fair value of financial instruments and the
liquidity risk associated with financial instruments. Section 3862 now requires that all financial instruments
measured at fair value be categorized into one of three hierarchy levels. The amendments will be effective for
annual financial statements for fiscal years ending after September 30, 2009. The amendments are consistent
with recent amendments to financial instrument disclosure standards in IFRS. The Company has included
these additional disclosures in Note 16.

internAtionAl FinAnciAl reporting stAndArds (iFrs)

The Accounting Standards Board has confirmed the convergence of Canadian GAAP with International
Financial Reporting Standards (IFRS) will be effective January 1, 2011. From that point onward the Company
will be required to account for and report under IFRS.

Although the International Accounting Standards Board (IASB) intends to revise several standards between
now and 2011, IFRS will be adopted in Canada utilizing a “big bang” approach, with the exception of some
Canadian GAAP changes that have occurred or will occur in periods leading up to the transition date.

The IASB has undertaken a number of projects, many being joint projects with the Financial Accounting
Standards Board in the U.S., that may significantly change existing international standards.

This degree of activity currently being undertaken by the standard setters makes the convergence from
Canadian GAAP to IFRS a moving target. Due to these likely changes, careful monitoring of developments will
be required in order to understand fully the accounting and business implications of the new requirements.

The Company in the fourth quarter of 2009 commenced phase two of the process of conversion to IFRS
by engaging its external auditors to perform a detailed review of the of the implementation of IFRS on the
Company’s high impact and medium impact areas identified below:

BONTERRA ENERGY CORP. 49

High impact areas:

• IFRS 1 – First time adoption of IFRS

• IFRS 3 – Business combinations

• IAS 16 – Property and equipment

• IAS 36 – Impairment of assets

Medium impact areas include:

• IFRS 6 – Exploration and evaluation of mineral resources

• IFRS 2 – Share-based payments

• IAS 1 – Presentation of financial statements

• IAS 10 – Events after the balance sheet date

• IAS 12 – Income Taxes

• IAS 18 – Revenues

• IAS 23 – Borrowing costs

• IAS 39 – Financial instruments, recognition and measurement

• IAS 37 – Provisions, contingent liabilities and contingent assets

The Company in conjunction with its auditors are currently finalizing phase two with an anticipated
completion date of June 3, 2010 to determine accounting policies and the resulting numerical changes to
opening balance sheet items. The Company anticipates commencing phase three (financial statement and
note compilation) during the third quarter of 2010. Key information will be disclosed as it becomes available
during the transition period.

The impact of IFRS will be significant; however the Company has always maintained an accounting policy of
successful efforts for property and equipment that will result in a major reduction in the level of conversion
compared to most oil and gas companies who used the full cost accounting policy.

The Company has implemented a new financial accounting system that provides for sufficient detail to
comply with the IFRS requirements. As the Company has been using successful efforts since its inception,
detail at a well level has been maintained under its past and current financial accounting systems as well as
procedures are in place to capture this information at the operational level.

BONTERRA ENERGY CORP. 50

Implications to the Company’s controls for DC&P and ICFR are being reviewed; however the Company believes
that the majority of the procedures in place will apply once IFRS is implemented. Training will be required
and is ongoing. Individuals within the Company have been and will continue to attend courses, seminars
and other training activities to ensure the Company is adequately prepared for IFRS. Use of external legal
expertise will be used to ensure compliance is maintained with all contractual agreements.

liQUidity And cApitAl resoUrces

During 2009, Bonterra participated in drilling 17 gross wells (12.8 net) at a total cost of $22,912,000. Included
in the above figure is approximately $1,300,000 of costs associated with the completion and tie-in of wells the
Company drilled in 2008. The above capital cost is net of $3,836,000 in drilling tax credits. In addition, Bonterra
acquired and paid $5,814,000 for mineral rights in the greater Pembina area of Alberta.

On July 2, 2009, Bonterra completed its acquisition of Cobalt. The Company issued 201,438 common shares
and assumed $2,856,000 of negative working capital and incurred approximately $170,000 in acquisition costs
for a total calculated accounting cost of $7,105,000. This acquisition resulted in acquiring an additional 40
BOE per day of production as well as increasing the Company’s working interest in approximately 11 gross
sections of land with potential Cardium horizontal locations in the Pembina area of Alberta.

As previously discussed, the Company closed a purchase and sale agreement to divest of a portion of its
Shaunavon oil production to Eagle Rock. The proceeds of disposition included cash of $23,729,000 and
30,769,200 common shares. These funds were used to retire debt and therefore provide additional room in
Bonterra’s line of credit for additional 2010 drilling. In addition, the common shares received for the Shaunavon
properties will provide further funds upon their ultimate sale.

Subsequent to December 31, 2009, the Company entered into a purchase and sale agreement to divest its
Southeast Saskatchewan Pinto property. Production from this property was approximately 60 BOE per day
consisting primarily of light sweet crude oil. The proceeds of disposition consist of approximately $5,600,000
cash. The disposition closed in February, 2010. The proceeds were applied to the Company’s debt.

The government of Alberta announced drilling incentives and royalty reductions in respect of wells drilled
after April 1, 2009 and prior to March 31, 2011. The Company is planning to maximize the crown royalty credits
available under the new drilling incentive program which will result in a substantial reduction of capital
costs on a per well basis. The Company currently has plans to spend between $40,000,000 and $50,000,000
(net of drilling incentives) in 2010 on development of its oil and gas properties. Any land, property or corporate
acquisitions will be in addition to this amount.

BONTERRA ENERGY CORP. 51

Bonterra anticipates funding the 2010 capital program from cash flow, the Company’s existing line of credit,
sale of investments, proceeds from the above mentioned Pinto sale as well as proceeds received on the
exercise of employee stock options.

Effective April 29, 2009, the Company entered into a new bank facility. The new facility consists of a
$100,000,000 syndicated revolving credit facility and a $20,000,000 non-syndicated revolving credit facility. At
December 31, 2009, the Company’s bank loan was $59,823,000 (December 31, 2008 – $93,235,000). The terms
of the new facility provides that the loan is revolving until April 28, 2011, is subject to annual review and has
no fixed payment requirements.

The following is a list of the material bank covenants:

The Company is required to not exceed $120,000,000 in consolidated debt (includes negative working
capital but excludes debt to related parties). As of December 31, 2009 the Company had consolidated
debt of $46,485,000.

Dividends paid in any quarter shall not exceed 80 percent of the average of the previous four quarters’
cash flow as defined under GAAP. The Company has received a waiver of this requirement for the fourth
quarter 2009 and the first quarter of 2010 and instead is restricted to paying no more than the lesser of
80 percent of each quarters cash flow or $10,000,000 or $12,500,000 respectively. Quarter four dividends
were $8,907,000 with 80 percent of Q4 cash flow being $10,718,000.

Bonterra is continuing with its efforts to acquire producing and non-producing properties through
either property or entity acquisitions. Funding for any acquisition would depend on items such as the
type of acquisition, quality of the assets, size of the purchase and Bonterra’s trading price at the time
of the acquisition.

BONTERRA ENERGY CORP. 52

The Company is authorized to issue an unlimited number of common shares without nominal or par value.

2009

2008

Issued

Common Shares

Balance, beginning of year

Issued pursuant to private placement

Issued on acquisition of Cobalt

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

Issued on reorganization to a corporation

number

17,257,603

1,068,000

201,438

92,600

Amount
($ 000s)

Number

Amount
($ 000s)

99,530

17,996

3,207

1,898

103

(1,046)

267

17,257,603

99,530

Balance, end of year

18,619,641

121,955

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 1,861,964 common shares (2008 – 1,725,760). 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, 2009 and 2008, and changes
during the twelve month periods ended on those dates is presented below:

december 31, 2009

December 31, 2008

weighted-
Average
exercise
price

options

Weighted-
Average
Exercise
Price

Options

Outstanding at beginning of period

1,390,500

20.50

Options granted

Options exercised

Outstanding at end of period

Options exercisable at end of period

33,000

(92,600)

1,330,900

370,900

14.90

20.50

20.36

20.50

1,390,500

20.50

BONTERRA ENERGY CORP. 53

The following table summarizes information about options outstanding at December 31, 2009:

Options Outstanding

Options Exercisable

Number
Outstanding
At 12/31/09

Weighted-
Average
Remaining
Contractual Life

Weighted-
Average
Exercise
Price

33,000

1,297,900

1,330,900

3.1 years

2.9 years

14.90

20.50

20.36

Number
Exercisable
at 12/31/09

370,900

Weighted-
Average
Exercise
Price

20.50

Range of Exercise Prices

$14.90

20.50

$14.90-20.50

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 2010:

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 18,619,641.

Additional information

Cash Flow

$ 1,124,000

347,000

834,000

Cash Flow
Per Share(1)

0.060

0.019

0.045

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.

BONTERRA ENERGY CORP. 54

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 auditors’ report. The audit committee has
reviewed these financial statements with management and the auditors, and has reported to the Board of
Directors. The Board of Directors has approved the financial statements as presented in this annual report.

george F. Fink
CEO
March 9, 2010

garth e. schultz
Vice President, Finance and CFO
March 9, 2010

Auditors’ Report

BONTERRA ENERGY CORP. 55

to the shareholders of bonterra energy corp. (formerly bonterra oil & gas ltd.):

We have audited the consolidated balance sheets of Bonterra Oil & Gas Ltd. as at December 31, 2009 and
2008 and the consolidated statements of shareholders’ equity, operations and deficit, comprehensive income
and cash flow for the years then ended. These financial statements are the responsibility of the Company’s
management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those
standards require that we plan and perform an audit to obtain reasonable assurance whether the financial
statements are free of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as well as evaluating the overall
financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial
position of the Company as at December 31, 2009 and 2008 and the results of its operations and its cash flows
for the years then ended in accordance with Canadian generally accepted accounting principles.

Chartered Accountants
Calgary, Alberta
March 9, 2010

BONTERRA ENERGY CORP. 56

Consolidated
Financial Statements

Consolidated
Balance Sheets

As at December 31
($ 000s)
Assets
cUrrent
Restricted term deposit
Accounts receivable (Notes 4 & 15)
Crude oil inventory
Prepaid expenses (Note 4)
Future income tax asset (Note 11)

Investments (Note 8)
Investment in related party (Note 6)

Restricted cash (Note 7)
Investment tax credit receivable (Note 11)
Future income tax asset (Note 11)
property And eQUipment (Note 8)
Petroleum and natural gas properties and related equipment
Accumulated depletion and depreciation
net property And eQUipment

liAbilities
cUrrent
Accounts payable and accrued liabilities (Note 4)
Due to related parties (Note 9)
Deferred credit (Note 11)
Short-term bank debt (Note 10)

Long-term bank debt (Note 10)
Deferred credit (Note 11)
Asset retirement obligations (Note 12)

Commitments, Contingencies and Guarantees (Note 17)
shAreholders’ eQUity (Note 13)
Share capital
Contributed surplus

Deficit
Accumulated other comprehensive income (Note 14)

Total Shareholders’ Equity

See the accompanying notes to the consolidated financial statements

On behalf of the Board:

george F. Fink
Director

bill woodward
Director

BONTERRA ENERGY CORP. 57

2009

2008

14,713
431
3,247
11,889
4,462
4,827
39,569
812
27,670
58,265

20
11,753
845
4,222
2,669
-
2,131
21,640
1,252
-
85,416

255,840
(88,169)
167,671
293,987

232,685
(75,692)
156,993
265,301

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

23,888
6,000
2,305
13,325
45,518
79,910
64,758
18,338
208,524

99,530
2,542
102,072
(46,715)
1,420
(45,295)
56,777
265,301

BONTERRA ENERGY CORP. 58

Consolidated
Statements of
Shareholders’ Equity

Consolidated
Statements of
Operations and
Deficit

For the Years Ended December 31
($ 000s)
Unitholders’ equity, beginning of year
Shareholders’ equity, beginning of year
Comprehensive income for the year
Net capital contributions (Note 13)
Stock-based compensation
Conversion of the Trust to a Corporation (Note 4)
Distributions declared
Unitholders’ eQUity, end oF yeAr
Conversion of the Trust to a Corporation (Note 4)
Dividends declared
shAreholders’ eQUity, end oF yeAr

For the Years Ended December 31
($ 000s except $ per share)
reVenUe And other income
Oil and gas sales
Loss on risk management contracts-cash
Gain on risk management contracts – non-cash
Royalties

Investment tax credit recovery (Note 11)

Gain on sale of property (Note 8)

Interest and other

expenses
Production costs
General and administrative (Note 8 and 15)

Interest on debt (Notes 9 and 10)

Reorganization costs (Note 4)
Stock-based compensation
Depletion, depreciation and accretion

eArnings beFore tAxes
Taxes (Note 11)
Current
Future

net eArnings For the yeAr
Deficit, beginning of year
Distributions declared
Dividends declared
deFicit, end oF yeAr
net eArnings per shAre – bAsic (Note 13)
net eArnings per shAre – dilUted (Note 13)

See the accompanying notes to the consolidated financial statements

2009

56,777
69,163
22,322
911
-
-
-
-
(30,299)
118,874

2008
44,218

53,815
8,135
1,207
(64,715)
(42,660)
-
64,715
(7,938)
56,777

2009

2008

85,712
-
-
(7,414)
27,670
24,198
158
130,324

27,848
4,458
3,294
-
911
19,277
55,788
74,536

551
5,422
5,973
68,563
(46,715)
-
(30,299)
( 8,451)
3.81
3.78

129,083
(7,353)
3,085
(17,215)
-
-
45
107,645

25,413
3,401
2,740
2,121
1,207
14,749
49,631
58,014

437
2,151
2,588
55,426
(51,543)
(42,660)
(7,938)
(46,715)
3.25
3.23

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 (loss) gain on investments (net of income taxes of

(97), (2008-(272))

Other Comprehensive Income (Loss)
comprehensiVe income
comprehensiVe income per shAre – bAsic (Note 13)
comprehensiVe income per shAre – dilUted (Note 13)

See the accompanying notes to the consolidated financial statements

BONTERRA ENERGY CORP. 59

2009
68,563

600
600
69,163
3.84
3.81

2008
55,426

(1,611)
(1,611)
53,815
3.15
3.14

BONTERRA ENERGY CORP. 60

Consolidated
Statements of
Cash Flow

For the Years Ended December 31
($ 000s)
operAting ActiVities
Net earnings for the year
Items not affecting cash
Gain on risk management contracts – non-cash
Stock-based compensation
Depletion, depreciation and accretion
Gain on sale of property
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 12)

cAsh proVided by operAting ActiVities
FinAncing ActiVities

Increase (decrease) in debt

Due to related parties

Issue of shares pursuant to private placement

Share issue costs
Stock option proceeds
Unit distributions
Dividends
cAsh Used in FinAncing ActiVities
inVesting ActiVities
Property and equipment expenditures
Acquisition (Note 5)
Disposition of property and equipment (Note 5)
Reorganization (Note 4)
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

2009

68,563

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

(3,613)
(739)
(9,329)
-
-
-
3,294
616

2008

55,426

(3,085)
1,207
14,749
-
2,151
70,448

2,642
(40)
(360)
(57)
-
-
(3,063)
(878)
69,570

20,698
6,000

-
7,935
(46,384)
(7,938)
(19,689)

(30,060)
(13,816)
-
(11,257)
(20)

-
5,272
(49,881)
-
-
-
2,740
582

Notes to the
Consolidated
Financial Statements

BONTERRA ENERGY CORP. 61

For the Years Ended December 31, 2009 and 2008

1. chAnge oF orgAnizAtion

On November 12, 2008, Bonterra Energy Income Trust (the “Trust”) was acquired by Bonterra Oil & Gas Ltd.
(the “Company”) through a reverse takeover by the Trust of SRX Post Holdings Inc. (SRX). In conjunction
with the reorganization, the Trust acquired all the issued and outstanding shares of Silverwing Energy Inc.
(Silverwing). Concurrently, all of the Company’s subsidiaries, including Silverwing were amalgamated into
Bonterra Energy Corp. (a subsidiary of Bonterra Energy Income Trust).

Prior to the reorganization on November 12, 2008, the consolidated financial statements included the
accounts of the Trust and its subsidiaries. After giving effect to the reorganization, the consolidated financial
statements have been prepared on a continuity of interests basis, which recognizes Bonterra Oil & Gas Ltd.
as the successor entity to the Trust.

Effective January 1, 2010, the Trust was wound up into Bonterra Oil & Gas Ltd. and Bonterra Oil & Gas Ltd.
was amalgamated with Bonterra Energy Corp. The continuing entity officially changed its name to Bonterra
Energy Corp. 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 its wholly owned subsidiary Bonterra Energy Corp. (Bonterra).
Inter-company transactions and balances are eliminated upon consolidation.

measurement Uncertainty

The preparation of financial statements in 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.

BONTERRA ENERGY CORP. 62

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.

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 as 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.

BONTERRA ENERGY CORP. 63

Producing properties are assessed annually or more frequently as economic events dictate, for potential
impairment. Impairment is assessed by comparing the estimated net undiscounted future cash flows to the
carrying value of the asset. If required, the impairment recorded is the amount by which the carrying value
of the asset exceeds its fair value.

Costs related to undeveloped properties are excluded from the depletion base until it is determined whether
or not proved reserves exist or if impairment of such costs has occurred. These properties are assessed at
least annually to determine whether impairment has occurred.

Depreciation and depletion of capitalized costs of oil and gas producing properties are calculated using
the per-unit-of-production method. Development and exploration drilling and equipment costs are depleted
over the remaining proved developed reserves. Depreciation of other plant and equipment is provided on the
straight line method. Straight line depreciation is based on the estimated service lives of the related assets
which is estimated to be ten years.

Furniture, Fixtures and Office Equipment

These assets are recorded at cost and depreciated over a three to ten year period representing their estimated
useful lives.

income taxes

The Company accounts for income taxes using the liability method. Under this method, the Company records
a future income tax asset or liability to reflect any difference between the accounting and tax basis of assets
and liabilities, using substantively enacted income tax rates. The effect on future tax assets and liabilities of
a change in tax rates is recognized in net earnings in the period in which the change occurs. Future income
tax assets are only recognized to the extent it is more likely than not that sufficient future taxable income will
be available to allow the future income tax asset to be realized.

Asset retirement obligations

The Company recognizes an Asset Retirement Obligation (ARO) in the period in which it is incurred when
a reasonable estimate of the fair value can be made. On a periodic basis, management will review these
estimates and changes, if any, will be applied prospectively. The fair value of the estimated ARO is recorded as
a long-term liability, with a corresponding increase in the carrying amount of the related asset. The capitalized
amount is depleted on a unit-of-production basis over the life of the reserves. The liability amount is increased
each reporting period due to the passage of time and the amount of accretion is charged to earnings in the
period. Revisions to the estimated timing of cash flows or to the original estimated undiscounted cost would
also result in an increase or decrease to the ARO. Actual costs incurred upon settlement of the obligations
are charged against the ARO to the extent of the liability recorded.

BONTERRA ENERGY CORP. 64

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.

Cash and restricted cash are classified as held-for-trading and are measured at fair value which equals
the carrying value and any gains or losses are recognized in earnings in the period they occur. Accounts
receivable are classified as loans and receivables which are measured at amortized cost. Investments 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 and amounts due to related parties are classified as other financial liabilities, which are measured at
amortized cost.

BONTERRA ENERGY CORP. 65

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, 2009 and
December 31, 2008, the Company did not designate any of its financial instruments as hedges. There are no
risk management contracts outstanding as at December 31, 2009 and December 31, 2008.

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. chAnges in AccoUnting policies

On January 20, 2009, the Company adopted the CICA’s Emerging Issues Committee (EIC) EIC-173, “Credit
Risk and the Fair Value of Financial Assets and Financial Liabilities”. EIC-173 provides guidance on how to
take into account credit risk of an entity and counterparty when determining the fair value of financial assets
and financial liabilities, including derivative instruments. The adoption of EIC-173 did not have a material
impact on the Company’s consolidated financial statements.

BONTERRA ENERGY CORP. 66

recent Accounting pronouncements

In December 2008, the CICA issued Sections 1601, “Consolidated Financial Statements”, and 1602,
“Non-controlling Interests”, which replaces existing Section 1600. Section 1601 establishes standards for
the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for
a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business
combination. These standards are effective on or after the beginning of the first annual reporting period
beginning on or after January 1, 2011 with earlier adoption permitted. Section 1602 currently does not impact
the Company as it has full controlling interest of all of its subsidiaries.

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.

4. reorgAnizAtion

As part of the 2008 reorganization of the Trust, SRX acquired all the issued and outstanding trust units of
Bonterra Energy Income Trust on a basis of one Trust Unit for one Common Share of SRX. Immediately
preceding the reorganization, SRX was under the protection of Companies’ Creditors Arrangement Act
(CCAA). Prior to the conversion, the Trust advanced $11,257,000 to SRX for settlement of claims pursuant to
the CCAA proceedings. Upon completion of the CCAA procedures, SRX was owed $2,224,000 in outstanding
tax and legal claims that have been used by the CCAA Monitor to settle secured creditor claims. This amount
was recorded as an outstanding account receivable by the Company. As of December 31, 2009 the entire
amount has been received.

BONTERRA ENERGY CORP. 67

In addition, SRX paid an advance of $1,800,000 to the CCAA Monitor for costs and payment of the unsecured
creditors. This amount was recorded as a prepaid expense in the accounts of the Company. As of December
31, 2009, $791,000 remains unpaid to the unsecured creditors.

Included in accounts payable is $791,000 (December 31, 2008 – $4,024,000) to account for the amount due to
the secured and unsecured creditors.

5. 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:

Cost of acquisition ($ 000s)

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

On November 12, 2008, the Company acquired all the common shares of Silverwing for cash consideration
of $13,816,000 (including acquisition costs of $334,000) plus the issuance of 7,745 common shares at a value
of $25.85 per common share plus the assumption of $14,979,000 of negative working capital. The results of
Silverwing’s operations have been included in the consolidated financial statements since that date. The
acquisition was funded through the Company’s bank facility (see Note 10).

BONTERRA ENERGY CORP. 68

The acquisition was accounted for using the purchase method and the purchase price was allocated to the
fair value of the assets acquired and the liabilities assumed as follows:

Cost of acquisition ($ 000s)

Cash paid

Value of common stock

Acquisition costs

Allocation of purchase price:

Restricted cash

Future income tax benefit

Property and equipment

Working capital deficiency

Asset retirement obligations

13,482

200

334

14,016

1,252

18,325

15,347

(14,979)

(5,929)

14,016

6. inVestment in relAted pArty

The investment consists of 689,682 (December 31, 2008 – 689,682) common shares in Comaplex Minerals Corp
(Comaplex), a company with common directors and management with the Company and its subsidiaries. The
investment is recorded at fair market value. The common shares trade on the Toronto Stock Exchange under
the symbol CMF. The investment represents less than a one percent ownership in the outstanding shares of
Comaplex.

7. restricted cAsh

An escrow account was held by Silverwing prior to its acquisition by the Company. The escrow account was
created to support eligible expenditures related to a farm-in agreement. The Company may access the funds
upon completion and tie-in or abandonment and reclamation of 11 (December 31, 2008 – 21) wells. The funds
are administered by the farmors’ legal counsel. The funds in the escrow account are invested in interest
bearing term deposits.

BONTERRA ENERGY CORP. 69

8. property And eQUipment

($ 000s)

Undeveloped land

Petroleum and natural gas properties

and related equipment

Furniture, equipment and other

2009

2008

Accumulated
depletion and
depreciation

87,153

1,016

88,169

cost

7,992

246,387

1,461

255,840

Accumulated
Depletion and
Depreciation

74,844

848

75,692

Cost

2,295

229,136

1,254

232,685

On November 6, 2009, the Company divested of a portion of its Shaunavon oil production to Eagle Rock
Exploration Ltd. (Eagle Rock) (TSXV: ERX). The proceeds of disposition consist 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). 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.

During the year the Company capitalized $359,000 (2008 – $426,000) of general and administrative costs.

9. dUe to relAted pArties

As of December 31, 2009, the Company’s CEO and major shareholder has loaned the Company $11,500,000
(December 31, 2008 – $6,000,000). The loan is unsecured, bore interest at Canadian chartered bank prime less
one half of a percent and has no set repayment terms but is payable on demand. Effective July 1, 2009 the
interest rate was adjusted to Canadian chartered bank prime less .25 percent. The interest rate was adjusted
to keep the loan rate at approximately two percent below the Company’s bank financing rate. Interest paid
on this loan during 2009 was $209,000 (2008 – $7,000).

As of December 31, 2009, Comaplex has loaned the Company $12,000,000 (December 31, 2008 – Nil). The loan
is unsecured, bore interest at Canadian chartered bank prime plus one quarter of a percent and has no set
repayment terms but is payable on demand. Effective July 1, 2009 the interest rate was adjusted to Canadian
chartered bank prime less 0.25 percent. The interest rate was adjusted to keep the loan rate at approximately
two percent below the Company’s bank financing rate. Interest paid on this loan during 2009 was $194,000.

BONTERRA ENERGY CORP. 70

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.

Please refer to Notes 6 and 15 for additional related party transactions.

10. bAnk debt

As of December 31, 2009, the Company has a bank facility consisting of a $100,000,000 syndicated and
$20,000,000 non-syndicated revolving credit facility (December 31, 2008 – $80,000,000 syndicated and
$20,000,000 non-syndicated demand credit facility). This new facility became effective April 29, 2009, when
the Company agreed to new terms and conditions. Amounts drawn under the facility at December 31, 2009
was $59,823,000 (December 31, 2008 – $93,235,000). The interest rate on the outstanding debt during 2009 was
approximately 4.0 percent. The Company at December 31, 2009 was in level III (see below) in respect of its
various borrowing charges. The term of the new facility provides that the loan is revolving until April 28, 2011,
is subject to annual review and has no fixed payment requirements.

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, 2009 (December 31, 2008 – $525,000). 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

125

275

Level II

Level III

Level IV

Level V

Over 1.0:1
to 1.5:1

Over 1.5:1
to 2.0:1

Over 2.0:1
to 2.5:1

150

300

175

325

200

350

Over
2.5:1

250

400

(1) Consolidated total funded debt excludes related party amounts but includes working capital.
(2) Numbers in table represent basis points.

The consolidated total funded debt to consolidated cash flow ratio shall be adjusted effective as of the
first day of the next fiscal quarter following the end of each fiscal quarter, with each such adjustment to be
effective until the next such adjustment.

BONTERRA ENERGY CORP. 71

The following is a list of the material covenants:

• The Company is required to not exceed $120,000,000 in consolidated debt (includes negative working

capital but excludes debt to related parties).

• Dividends paid in any quarter shall not exceed 80 percent of the average of the previous four quarters’
cash flow as defined under GAAP. During the third quarter the Company received a waiver of this
requirement for the fourth quarter and instead is restricted to paying no more than the lesser of 80
percent of quarter four cash flow or $10,000,000. In addition the Company received a waiver of this
requirement for the first quarter of 2010 and instead is restricted to paying no more than the lesser of
80 percent of the first quarter 2010 cash flow or $12,500,000

At December 31, 2009, the Company is in compliance with all covenants.

11. 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

2009

(824)

(5,855)

4,474

802

59,668

17,883

(17,883)

58,265

11,889

2008

(212)

(7,097)

4,593

1,134

86,998

17,883

(17,883)

85,416

2,669

As a result of the reorganization as described in Note 1 the Company recorded a deferred credit of $71,303,000
relating to the difference between the future income tax asset generated on the reorganization and the
amount of the cash payment made to SRX immediately before the reorganization. This credit is being
amortized (2009 – $12,356,000, 2008 – $4,240,000) on the same basis as the related future income tax asset
(2009 – $14,306,000, 2008 – $4,909,000).

BONTERRA ENERGY CORP. 72

A reconciliation of the deferred credit is as follows:

($ 000s)

Amount recorded on reorganization

Amortized in 2008

Rate adjustment

Amortized in 2009

Balance as of December 31, 2009

Current portion

Long-term portion

71,303

(4,240)

425

(12,356)

55,132

7,363

47,769

55,132

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

Change in effective tax rate

Trust income allocated to Unitholders prior to conversion

Others

Income tax expense

2009

74,536

29.15%

21,727

282

269

266

(11,931)

(4,708)

5,973

2008

58,014

29.62%

17,184

437

357

(4,240)

(499)

(10,291)

(360)

2,588

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:

BONTERRA ENERGY CORP. 73

($ 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

100

Amount

21,671

7,363

2,973

26,282

59,141

11,174

80,357

223,629

432,590

(1) Federal income tax losses carried forward expire in the following years; 2013 – $1,069,000, 2024 – $3,347,000,

2025 – $7,532,000, 2026 – $46,670,000, 2027 – $117,189,000, 2028 – $34,726,000, 2029 – $13,096,000.

The Company also has $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.

12. Asset retirement obligAtions

At December 31, 2009, the estimated total undiscounted amount required to settle the asset retirement
obligations was $64,482,000 (2008 – $58,903,000). Costs for asset retirement have been calculated assuming
a two percent inflation rate. These obligations will be settled based on the useful lives of the underlying
assets, which extend up to 50 years into the future. This amount has been discounted using a credit-adjusted
risk-free interest rate of five percent (2008 – five percent).

BONTERRA ENERGY CORP. 74

Changes to asset retirement obligations were as follows:

($ 000s)

Asset retirement obligations, January 1

Adjustment to asset retirement obligations

Adjustment related to asset additions (net of disposals)

Liabilities settled during the year

Accretion

Asset retirement obligations, December 31

13. shAreholders’ eQUity

Authorized

2009

18,338

(138)

(750)

(573)

913

17,790

2008

14,904

(217)

5,929

(3,063)

785

18,338

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

2009

2008

Common Shares

Balance, beginning of year

Issued pursuant to private placement

Issued on acquisition of Cobalt (Note 5)

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

Issued on reorganization to a corporation

number

17,257,603

1,068,000

201,438

92,600

Balance, end of year

18,619,641

121,955

Amount
($ 000s)

Number

Amount
($ 000s)

99,530

17,996

3,207

1,898

103

(1,046)

267

17,257,603

99,530

Issued

Trust Units

Balance, beginning of year

Transfer of contributed surplus to unit capital

Issued pursuant to Trust unit option plan

Issued on acquisition of Silverwing (Note 5)

Cancelled on conversion to a corporation

Balance, end of 2008

BONTERRA ENERGY CORP. 75

2008

Number

16,928,158

321,700

7,745

Amount
($ 000s)

90,590

805

7,935

200

(17,257,603)

(99,530)

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, 2009 of 18,131,085 shares (2008 – 17,119,517) included the basic weighted average number of common
shares outstanding of 18,006,320 shares (2008 – 17,075,647) plus 124,765 shares (2008 – 43,870) related to the
dilutive effect of common share options.

A summary of the changes of the Company’s contributed surplus is presented below:

Contributed surplus

($ 000s)

Balance, beginning of year

Stock-based compensation expensed (non-cash)

Stock-based options exercised (non-cash)

Balance, end of year

2009

2,542

911

(103)

3,350

2008

2,140

1,207

(805)

2,542

BONTERRA ENERGY CORP. 76

The deficit balance is composed of the following items:

($ 000s)

Accumulated earnings

Accumulated cash dividends and distributions

Deficit

2009

276,745

(285,196)

(8,451)

2008

208,182

(254,897)

(46,715)

A summary of the status of the Company’s stock option plan as of December 31, 2009 and 2008, and changes
during the years ended on those dates is presented below:

december 31, 2009

December 31, 2008

Outstanding at beginning of period

Options granted

Options exercised

weighted-
Average
exercise
price

$ 20.50

14.90

20.50

options

1,390,500

33,000

(92,600)

Options

1,390,500

Outstanding at end of period

1,330,900

$ 20.36

1,390,500

Options exercisable at end of period

370,900

$ 20.50

The following table summarizes information about options outstanding at December 31, 2009:

Weighted-
Average
Exercise
Price

$ -

20.50

$20.50

$ -

Options Outstanding

Options Exercisable

Number
Outstanding
At 12/31/09

33,000

1,297,900

1,330,900

Weighted-
Average
Remaining
Contractual Life

Weighted-
Average
Exercise
Price

Number
Exercisable at
12/31/09

3.1 years

2.9 years

$14.90

20.50

$20.36

370,900

Weighted-
Average
Exercise
Price

$ -

20.50

$20.50

Range of Exercise Prices

$14.90

20.50

$14.90-20.50

BONTERRA ENERGY CORP. 77

The Company records compensation expense over the vesting period based on the fair value of options
granted to employees, directors and consultants. In 2009, the Company granted 33,000 stock options with
an estimated fair value of $52,000 ($1.58 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 2009 and 2008

2009

2008

1.4

3.0

33.0

2.2

3.5

31.3

based on the percentage of dividends
(2008 – dividends or distributions) paid
during the period granted

14. AccUmUlAted other comprehensiVe income

($ 000s)

January 1, 2009

other
comprehensive
income (loss)

december 31,
2009

Unrealized gains (losses) on available for sale

financial assets

1,420

600

2,020

($ 000s)

January 1, 2008

Other
Comprehensive
Income (Loss)

December 31, 2008

Unrealized gains on available for sale

financial assets

3,031

(1,611)

1,420

15. relAted pArty trAnsActions

The Company received a management fee from Comaplex of $330,000 (2008 – $330,000) for management
services and office administration. This fee has been included as a recovery in general and administrative
expenses and represents the fair value of the services rendered. The Company also allocated $102,000 of
drilling royalty credits to Comaplex for $51,000. As at December 31, 2009, the Company had an account
receivable from Comaplex of $105,000 (December 31, 2008 – $56,000).

BONTERRA ENERGY CORP. 78

The Company received a management fee from Pine Cliff Energy Ltd., a company with common directors and
management with the Company and its subsidiaries, of $120,000 (2008 – $238,000) for management services
and office administration. This fee has been included in general and administrative expenses as a recovery
and represents the fair value of the services rendered. As at December 31, 2009 the Company had an account
receivable from Pine Cliff of $1,000 (December 31, 2008 – $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.

16. FinAnciAl And cApitAl risk mAnAgement

Financial Risk Factors

The Company undertakes transactions in a range of financial instruments including:

• Receivables

• Restricted cash

• Payables

• Common share investments

• Due to related parties

• Bank loans

The Company’s activities result in exposure to a number of financial risks including market risk (commodity
price risk, interest rate risk, foreign exchange risk), credit risk, and liquidity risk.

The Company’s overall risk management program seeks to mitigate these risks and reduce the volatility
on the Company’s financial performance. Financial risk management is carried out by senior management
under the direction of the Directors of the Company.

The Company 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 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.

BONTERRA ENERGY CORP. 79

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.

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

Investment in related party

Restricted cash

Financial liabilities

Accounts payable and accrued liabilities

Due to related parties

Long-term debt

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

812

18,868

23,500

59,823

BONTERRA ENERGY CORP. 80

Financial instruments consisting of accounts receivable, accounts payable and accrued liabilities, due
to related parties and long-term debt carried on the consolidated balance sheet are carried at amortized
cost. Restricted cash, 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 restricted cash, 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)

Long-term debt

Due to related parties

Accounts payable and accrued liabilities

Current assets (1)

Net Debt

Cash flow from operations(2)

Net debt to cash flow from operations

december 31, 2009

59,823

23,500

18,868

(27,680)

74,511

38,893

1.92

(1)

Current assets include accounts receivable, crude oil inventory, prepaid expenses, investments and
investment in related party.

(2) Cash flow from operations includes annual net earnings less adjustment for non-cash (gain) loss on risk

management contracts, stock-based compensation, depletion, depreciation and accretion, gain on sale of
property, future income taxes, changes in non-cash working capital items, asset retirement obligations settled
and investment tax credit receivable.

BONTERRA ENERGY CORP. 81

b) Risks and mitigations

Market risk is the risk that the fair value or future cash flow of the Company’s financial instruments will
fluctuate because of changes in market prices. Components of market risk to which the Company is
exposed are discussed below.

Commodity price risk

The Company’s principal operation is the production and sale of crude oil, natural gas and natural gas
liquids. Fluctuations in prices of these commodities directly impact the Company’s performance and
ability to continue with its dividends.

The Company has used various risk management contracts to set price parameters for a portion of its
production. Management, in agreement with the Board of Directors, recently decided that at least in the
near term it will discontinue the use of commodity price agreements. The Company will assume full risk
in respect of commodity prices.

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 and $23,500,000 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 net earnings and
comprehensive income by $591,000 (increase by $591,000).

BONTERRA ENERGY CORP. 82

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;

• Agreements for product sales are primarily on 30 day renewal terms; and

• Investments are generally only with companies that have common management with the Company.

Of the accounts receivable balance of December 31, 2009 ($14,713,000) and December 31, 2008
($11,753,000) over 87 (2008 – 82) 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, 2009, there was no impairment provision required on
any of the financial assets of the Company due to historical success of collecting receivables. The
Company does have a credit risk exposure as the majority of the Company’s accounts receivable are with
counterparties having similar characteristics. However, payments from the Company’s largest accounts
receivable 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, 2009, approximately $244,000 or 1.6 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

BONTERRA ENERGY CORP. 83

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, 2009 is $160,000
(December 31, 2008 – $85,000) with the difference being included in general and administrative expenses.
There were no accounts written off during the year.

The carrying value of accounts receivable approximates their fair value due to the relatively short periods
to maturity on this instrument. The maximum exposure to credit risk is represented by the carrying amount
on the balance sheet. There are no material financial assets that the Company considers past due.

Liquidity risk

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)

Financial Statements Less than 1 year

1-3 years

4-5 years

Recognized on

Payments Due By Period

Accounts payable and

accrued liabilities

Due to related party

Long-term bank debt

Office leases

Total

Yes – Liability

18,868

23,500

944

43,312

59,823

1,761

61,584

496

c) Risk management contracts

The Company has no outstanding risk management contracts.

BONTERRA ENERGY CORP. 84

17. commitments, contingencies And gUArAntees

The Company has no contractual obligations that last more than a year other than its office lease agreements
which are as follows:

Lease Obligations ($ 000s)

Year 1

Year 2

Year 3

Year 4

Total

944

932

829

496

3,201

18. sUbseQUent eVents-diVidends

Subsequent to December 31, 2009, the Company has declared the following dividends:

Date declared

January 5, 2010

February 3, 2010

March 3, 2010

Record date

January 15, 2010

February 16, 2010

March 15, 2010

$ per share

$0.18

Date payable

January 29, 2010

February 26, 2010

March 31, 2010

19. sUbseQUent eVent – disposition

Subsequent to December 31, 2009, the Company entered into a purchase and sale agreement to divest its
Southeast Saskatchewan Pinto property. The proceeds of disposition consist of approximately $5,600,000
cash and resulted in a gain of approximately $5,800,000. The disposition closed on February 23, 2010.

BONTERRA ENERGY CORP. 85

Corporate
Information

BOARd Of diREcTORs
G.J. Drummond, Nassau, Bahamas

G.F. Fink, Calgary, Alberta

C.R. Jonsson, Vancouver, British Columbia

F. W. Woodward, Calgary, Alberta

OfficERs
G.F. Fink – Chief Executive Officer

R.M. Jarock – President and Chief Operating Officer

G.E. Schultz – Vice President, Finance,

Chief Financial Officer & Secretary

REgisTRAR & TRANsfER AgENT
Olympia Trust Company, Calgary, Alberta

AUdiTORs
Deloitte & Touche LLP, Calgary, Alberta

sOLiciTORs
Borden Ladner Gervais LLP, Calgary, Alberta

BANkERs
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

WEBsiTE
www.bonterraenergy.com

BONTERRA ENERGY CORP. 1

901, 1015 – 4th Street SW
Calgary, Alberta T2R 1J4