YIELD
SUSTAINABILITY
GROWTH
ANNUAL REPORT 2012
THE RIGHT ASSETS.
THE RIGHT PEOPLE.
THE RIGHT STRATEGY.
Bonterra Energy Corp. is a high-yield, dividend paying oil and gas company
headquartered in Calgary, Alberta, Canada with a proven history of creating
growth and long-term value for shareholders on a per share basis. Bonterra has
paid a monthly dividend (distribution) since inception and intends to pay
approximately 50 to 65 percent of funds flow to investors. Bonterra’s successful
performance is due to its experienced management team, conservative capital
structure and sustainable pace of development.
Bonterra’s shares trade on the Toronto Stock Exchange under the symbol BNE.
Annual Highlights 2
Quarterly Highlights 3
Report to Shareholders 4
Cardium: The Right Assets 8
Statistical Review 12
Management’s Discussion & Analysis 19
Financial Statements 40
Notes to Financial Statements 44
Corporate Information 65
BONTERRA | ANNUAL REPORT 2012
2012 HIGHLIGHTS
YIELD
SUSTAINABILITY
GROWTH
Bonterra’s business strategy is to provide
income to shareholders on a monthly basis
in the form of a monthly dividend and to
generate above average returns for
shareholders over time through the
development and expansion of its high
quality asset base.
The company’s conservative capital
structure along with its large drilling
inventory and efficient horizontal drilling
program positions the company well
to continue to provide superior value
to its shareholders.
Bonterra’s operations are characterized by
a long reserve life index and low risk,
predictable returns. The company focuses
on the sustainable development of its
asset base through a steady pace of
development and efficient operating
practices. Bonterra’s implementation of
new drilling and completion methods
have decreased costs and improved
well performance and reserve recovery.
The company will continue to execute its
disciplined approach to operations in
2013 to maximize shareholder returns
on a long-term basis.
Bonterra’s track record of production,
reserves and dividend growth on both
a total and per share basis remains
unparalleled in the Canadian energy
industry. Bonterra has increased its
holdings in the Cardium during 2012
and its 2013 horizontal drill program
will continue to drive growth as the
company pursues the development of
its opportunities in both the Pembina
and Willesden Green fields. Bonterra will
maintain its focus on providing superior
growth to shareholders balanced by
conservative financial management.
$3.12
per share
paid out in 2012
$90 M
2013 capital
program
90.5%
five year return
to shareholders
>10 year
drilling
inventory
6,703
BOE per day
produced in 2012
100%
drilling success
rate in 2012
BONTERRA | ANNUAL REPORT 2012
1
ANNUAL HIGHLIGHTS
As at and for the year ended
($ 000s except $ per share)
December 31,
2012
December 31,
2011
December 31,
2010
FINANCIAL
Revenue – realized oil and gas sales
Funds flow (1)
Per share – basic
Per share – diluted
Payout ratio (2)
Cash flow from operations
Per share – basic
Per share – diluted
Payout ratio (2)
Cash dividends per share (2)
Net earnings
Per share – basic
Per share – diluted
Capital expenditures and acquisitions net of dispositions
Total assets
Working capital deficiency
Long-term debt
Shareholders’ equity
OPERATIONS
Oil
NGLs
– barrels per day
– average price ($ per barrel)
– barrels per day
– average price ($ per barrel)
– MCF per day
– average price ($ per MCF)
Total barrels of oil equivalent per day (BOE) (4)
Natural gas
142,770
80,429
4.07
4.06
77%
74,325
3.75
3.75
83%
3.12
33,211
1.68
1.68
98,130(3)
419,933
29,876
166,808
163,277
4,035
82.04
476
52.18
13,157
2.60
6,703
162,277
101,988
5.27
5.22
58%
97,409
5.04
4.98
61%
3.06
43,608
2.25
2.23
62,686
364,176
51,576
69,916
181,640
4,075
92.76
386
60.89
11,163
3.86
6,322
118,980
74,385
3.95
3.84
64%
66,238
3.52
3.42
72%
2.55
39,954
2.12
2.06
70,680
347,825
17,905
85,386
190,173
3,585
74.76
290
47.11
10,521
4.14
5,628
(1) Funds flow is not a recognized measure under IFRS. For these purposes, the Company defines funds flow as funds provided by operations including proceeds
from sale of investments and investment income received excluding the effects of changes in non-cash working capital items, decommissioning expenditures
settled and restricted cash.
(2) Cash dividends per share are based on payments made in respect of production months within the quarter.
(3) Includes an acquisition that closed on June 7, 2012 for $17,108,000.
(4) BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
2
BONTERRA | ANNUAL REPORT 2012
QUARTERLY HIGHLIGHTS
As at and for the periods ended
($ 000s except $ per share)
FINANCIAL
Revenue – realized oil and gas sales
Funds flow (1)
Per share – basic
Per share – diluted
Payout ratio (2)
Cash flow from operations
Per share – basic
Per share – diluted
Payout ratio (2)
Cash dividends per share (2)
Net earnings
Per share – basic
Per share – diluted
Capital expenditures and acquisitions, net of disposals
Total assets
Working capital deficiency
Long-term debt
Shareholders’ equity
OPERATIONS
Oil (barrels per day)
NGLs (barrels per day)
Natural gas (MCF per day)
Total BOE per day (4)
2012
Q4
Q3
Q2
Q1
39,624
19,796
1.00
1.00
78%
21,460
1.08
1.08
72%
0.78
6,082
0.31
0.31
24,069
419,933
29,876
166,808
163,277
4,400
595
16,009
7,663
35,204
21,705
1.10
1.09
71%
16,440
0.83
0.83
94%
0.78
7,746
0.39
0.39
27,360
412,812
49,808
128,779
169,839
4,108
461
12,583
6,666
31,049
16,621
0.84
0.84
93%
14,727
0.74
0.74
105%
0.78
9,201
0.47
0.46
25,288(3)
393,772
42,082
114,747
176,292
3,650
428
11,753
6,037
36,893
22,307
1.13
1.13
69%
21,698
1.10
1.10
71%
0.78
10,182
0.52
0.51
21,413
371,757
57,889
75,543
181,008
3,975
419
12,260
6,438
(1) Funds flow is not a recognized measure under IFRS. For these purposes, the Company defines funds flow as funds provided by operations including proceeds
from sale of investments and investment income received excluding the effects of changes in non-cash working capital items, decommissioning expenditures
settled and restricted cash.
(2) Cash dividends per share are based on payments made in respect of production months within the quarter.
(3) Includes an acquisition that closed on June 7, 2012 for $17,108,000.
(4) Barrels of oil equivalent (BOE) may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
BONTERRA | ANNUAL REPORT 2012
3
BONTERRA IS
COMMITTED TO
CREATING AND
DELIVERING
OUTSTANDING
VALUE ON BEHALF
OF ITS INVESTORS.
REPORT TO SHAREHOLDERS
Bonterra Energy Corp. (Bonterra or the Company) is pleased to report its financial and operational results for the year ended
December 31, 2012.
STRATEGY
It was a challenging year for the Canadian energy sector, including Bonterra, as the operating environment was hampered by a
number of significant issues including an extended spring break-up, weak commodity prices, including volatile price differentials
between WTI and average realized prices, lengthy plant turnarounds and pipeline issues. Despite these hurdles, Bonterra
continued to create value for its shareholders through the successful execution of its long-term business strategy which is
focused on:
• providing shareholders with income in the form of a monthly dividend;
• potential share price appreciation by growing production and reserves on both a total and per share basis through the
execution of a sustainable development program and the efficient management of its high-quality, low risk asset base; and
• preserving balance sheet strength.
4
BONTERRA | ANNUAL REPORT 2012
Bonterra continues to offer above average returns to investors.
Since inception Bonterra has provided investors with a
compound annual rate of return of over 40 percent and the
Company’s five year return to shareholders is 90.5 percent.
2012 highlights include:
• Paid $3.12 per share ($0.26 per share monthly) in dividends
to shareholders that has been increased to $0.28 per share
monthly effective March 31, 2013;
• Executed an $81.0 million capital program before
acquisitions comprised of 34 gross (22.9 net) Cardium
horizontal wells drilled with a 100 percent success rate;
• New production records set with average daily production
of 6,703 barrels of oil equivalent (BOE) per day (67 percent
oil and liquids) for the full year 2012 and 7,663 BOE per day
in the fourth quarter, an increase of 6.0 percent and
14.8 percent over the same periods in 2011;
• Production per share was 0.124 BOE per share, an increase
of 4.2 percent over 2011;
• Proved plus Probable (P+P) reserves of 45.0 million BOE
(approximately 75 percent oil and liquids), a 9.4 percent
increase over December 2011 reserves of 41.1 million BOE;
• Added a total of 6.3 million BOE of reserves (P+P) which
equates to 2.5 times 2012 production;
• Reserves per share (P+P) increased 7.0 percent to
2.28 BOE per share compared to 2.13 BOE per share
in the prior year; and
• The Company was successful in strengthening its Cardium
core area with two key acquisitions.
2012 challenges include:
• The debt to funds flow ratio at December 31, 2012 was in
excess of the Company’s guidance of 1.5 to 1 times.
(This has been rectified in 2013);
• A reduction of $11.11 in corporate netbacks per BOE from
$42.47 in 2011 to $31.36 in 2012 due to: the average annual
oil differential between the price of WTI and the Company’s
realized price of $12.07 in 2012 compared to $2.42 in 2011;
the reduction of natural gas prices from $3.86 per MCF in
2011 to $2.60 per MCF in 2012; and the reduction of natural
gas liquids from $60.89 per barrel in 2011 to $52.18 per
barrel in 2012. The decrease in corporate netbacks using
2012 average production reduced cash flow by
$27.2 million; and
• The Company exceeded its capital expenditure budget by
approximately $30 million in 2012 due to an unbudgeted
$17 million acquisition and additional drilling in Q4 2012.
Bonterra had considered issuing shares from treasury in
December 2012 to finance this increase in capital spending
and the negative effect on the debt to funds flow ratio but
did not need to proceed with this after the Spartan Oil Corp.
acquisition which closed in January 2013.
ASSETS
Bonterra holds an enviable suite of light oil properties in its
core area in the Cardium located in the Pembina and
Willesden Green fields in west central Alberta. Horizontal
drilling has revitalized this mature basin and the Company has
been at the forefront of increased development having drilled
the first horizontal well in the halo of the Pembina field that
commenced production in February 2009. The Company’s
high level of concentration and experience in the area provides
Bonterra with the knowledge to efficiently exploit the Cardium
AVERAGE DAILY PRODUCTION
(boe per day)
PRODUCTION PER SHARE
(boe)
RESERVES PER SHARE
(boe)
2012
2011
2010
2009
2008
6,703
6,322
5,628
4,994
4,346
2012
2011
2010
2009
2008
0.124
0.119
0.109
0.101
0.092
2012
2011
2010
2009
2008
2.28
2.13
2.09
1.99
1.83
BONTERRA | ANNUAL REPORT 2012
5
formation and the Company has pursued land and corporate
acquisitions to continue to acquire further interests in this key
resource play.
FINANCIAL RESULTS
AND COmmODITY PRICE ENVIRONmENT
During the second quarter of 2012, Bonterra completed a
tuck-in acquisition in the Willesden Green area adding 52.3
gross (10.5 net) sections of land and 250 BOE per day of
production, net to the Company. These lands are considered
underdeveloped and provide Bonterra with an additional 191
gross (37 net) potential Cardium drilling locations.
In late 2012, Bonterra announced its most significant
acquisition to date of a Cardium-focused producer Spartan Oil
Corp. (Spartan) which closed on January 25, 2013. The Spartan
assets further solidified Bonterra’s position as one of the
predominant sustaining light-oil dividend paying companies in
the Canadian energy sector, augmented Bonterra’s large
asset base in the Cardium formation which now totals 250.3
(193.7 net) sections and increased production to approximately
13,500 BOE per day of production at the date of acquisition.
The Spartan assets are expected to increase Bonterra’s liquids
weighting and the corporate production profile in 2013 is
anticipated to be approximately 75 percent light oil and
natural gas liquids which should result in increased netbacks.
The Company currently estimates that it has a greater than
10 year drilling inventory (based on drilling four horizontal wells
per section) and remains well-positioned to continue delivering
strong operational performance in 2013 through the continued
development of its significant portfolio of organic growth
opportunities. Bonterra will focus its efforts on improving
production rates, sustaining a consistent pace of development
and increasing project economics across its operations.
Oil and natural gas prices exhibited continued weakness in
2012 and price differentials between Bonterra’s average
realized price and WTI widened substantially from prices
received in 2011, due in most part to pipeline capacity
constraints, refinery outages, seasonal turnarounds and
quality adjustments. The price differential slightly decreased
during the fourth quarter of 2012 due to a combination of
increased rail shipments, decreased production of Alberta
synthetic crude and increased demand from U.S. and
Canadian refineries. However, continued European and
North American economic concerns and pipeline capacity
constraints continued to negatively affect the realized price
for oil in Canada.
The Company’s average realized price for crude oil was
$82.04 per barrel, a decrease of approximately 11.6 percent
when compared to 2011. In addition, natural gas prices
continued to remain extremely weak and Bonterra’s average
realized price decreased 32.6 percent to $2.60 per MCF in
2012 when compared to $3.86 per MCF in 2011.
Mainly as a result of this lower price environment, revenue
and cash flow from operations decreased 12.0 percent and
23.7 percent, respectively, year over year. However, Bonterra’s
strong operating results in 2012 along with the substantial
increase in production volumes allowed the Company to
maintain the monthly dividend level to shareholders at $0.26
per share, representing a payout ratio of 77 percent of funds
flow. Higher production volumes will, subject to commodity
prices, assist in reducing this payout ratio further in 2013.
FUNDS FLOW
($ thousands)
CASH DIVIDENDS/
DISTRIBUTIONS TO INVESTORS
($ per unit/share)
NETBACkS
($ per boe)
2012
2011
2010
2009
2008
80,429
101,988
74,385
69,975
70,448
2012
2011
2010
2009
2008
$4.07
77%
$5.27
58%
$3.95
64%
$3.69
44%
$4.13
76%
FUNDS FLOW
DIVIDENDS/DISTRIBUTIONS
2012
2011
2010
2009
2008
$31.36
$58.19
$42.47
$70.33
$33.45
$57.92
$23.13
$47.04
$45.59
CASH NETBACK
G&A
ROYALTIES
INTEREST & TAXES
FIELD OPERATING
6
BONTERRA | ANNUAL REPORT 2012
A number of pipeline expansions and reversals of flow
direction currently underway could alleviate pipeline capacity
issues later in 2013 and 2014. In addition, there are a number
of pipeline initiatives under review including the Keystone
XL pipeline in the United States and the Northern Gateway
pipeline in Canada. However, neither of these has received
government or regulatory approval at this time and Bonterra
will continue to focus on managing its funds flow, capital
expenditure ranges and dividend payments within the current
commodity environment.
A conservative approach to the Company’s capital structures
has been a key factor in building financial strength and
flexibility. Bonterra retains its strong financial position by
maintaining a sustainable growth strategy and minimizing the
amount and cost of debt. The Company’s current net debt
to funds flow ratio is less than 1.5 times (after the closing
of the Spartan acquisition) and Bonterra is well funded to
execute the 2013 capital program and to pursue any additional
acquisition opportunities that may become available.
Bonterra currently has approximately $600.0 million in tax
pools, $27.7 million in investment tax credits and $135.7 million
of capital loss carry forwards (which can only be claimed
against taxable capital gains). The Company anticipates that
these pools move Bonterra’s tax horizon beyond 2015.
Bonterra’s 2013 capital development
program is focused on sustaining its
current business model offering both solid
growth and yield to its shareholders.
2013 OUTLOOk
Bonterra’s 2013 capital development program is focused
on sustaining its current business model offering both solid
growth and yield to its shareholders. The Board of Directors
has approved a capital development program of $90.0 million
which mainly targets light oil prospects through its Cardium
horizontal drill program. The program plan in 2013 is to:
• Maintain a steady pace of development and manage
annual decline levels. Bonterra anticipates allowing current
production levels to reduce to an average daily production
rate of approximately 12,000 BOE per day;
• Drill 29 gross (28.1 net) operated horizontal wells and
participate in drilling 13 gross (4.3 net) non-operated wells;
• Seek out additional operating efficiencies and control
costs. Operating expenditures are expected to average
approximately $13.00 per BOE on an annualized basis;
• Ensure sustainability by managing the dividend payout ratio
to range between 50 and 65 percent of funds flow in 2013;
• Manage risk by maintaining balance sheet strength. Bonterra
anticipates maintaining its net debt to cash flow ratio at less
than 1.5 times in 2013; and
• Continue to provide increased value to shareholders.
Bonterra increased the monthly dividend to $0.28 per share
beginning in March 2013. Bonterra’s Board of Directors and
management will continue to take into account production
volumes and commodity prices in determining monthly
dividend amounts and will consider increasing the dividend
should crude oil pricing remain favourable coupled with
anticipated production increases.
THE RIGHT PEOPLE
Bonterra’s successful execution of its long-term strategy has
been dependent on the strength of its people. The Company’s
Board of Directors, management team, employees and field
staff have been instrumental in providing continued growth
and results on behalf of shareholders. We would like to
thank these people for their continued efforts in 2012 as the
Company looks forward to another year of growth for both its
operations and its investors.
This will be an exciting year for both Bonterra and its
shareholders. We would also like to take this opportunity to
thank our long-term shareholders for their continued support
as well as welcome our new shareholders through the Spartan
acquisition. The Company is committed to continue to create
and deliver outstanding value on behalf of its investors
and will continue to pursue the aggressive development of
its light oil targets in the Cardium to drive future growth.
The Company’s disciplined approach to its operations in
2013 should allow Bonterra to continue to capitalize on its
numerous opportunities and maximize shareholder value on a
long-term basis.
George F. Fink
Chief Executive Officer and Chairman of the Board
BONTERRA | ANNUAL REPORT 2012
7
CARDIUM:
THE RIGHT ASSETS.
OPERATIONS
Bonterra continues to provide value to shareholders through its holdings in the
Pembina Cardium in central Alberta, one of Canada’s largest oil fields. The pool is
characterized by stable production, high quality oil and high netbacks with only
14 percent of original oil in place having been produced.
During 2012 and 2013, Bonterra increased its land position in the Cardium
through two key acquisitions and this concentrated asset base now represents
approximately 93 percent of Bonterra’s Proved plus Probable (P+P) reserves.
The acquisitions were a strong strategic fit for the Company resulting in
significant development potential and ongoing value creation.
The revitalization of the Cardium through horizontal drilling and completion
technology has marked an evolution in the Company’s pool exploitation strategy
from conventional development to a more resource play-based development
program. However, Bonterra’s fundamental operational strategy remains
unchanged; provide production and reserves growth on both a total and per share
basis, effectively manage costs and seek out new operational efficiencies.
8
BONTERRA | ANNUAL REPORT 2012
STRENGTHENING OUR POSITION
In 2012, Bonterra focused on consolidating and developing
its Cardium core area and completed two acquisitions which
increased its significant land position and met its acquisition
criteria of high-quality production, significant reserves,
operational efficiencies and upside potential.
In the second quarter of 2012, Bonterra completed a tuck-in
acquisition in the Willesden Green field of 52.3 gross (10.5 net)
sections and most significantly, in late 2012 announced its
largest acquisition to date of Spartan Oil Corp. (Spartan)
which closed in January 2013. The Spartan assets included
60.75 gross (51.34 net) sections and the Company’s large,
concentrated asset base in the Cardium now totals 250.3 gross
(193.7 net) sections.
The Spartan properties are a strong geographical fit to
Bonterra’s asset base, have significant operational synergies,
provide additional drilling inventory over the long-term and
are anticipated to increase the Company’s 2013 oil and liquids
weighting. Bonterra has completed extensive geological
mapping of the Spartan land base and has fully integrated
the assets into its 2013 capital program.
PEMBINA CARDIUM LAND BASE
WILLESDEN GREEN CARDIUM LAND BASE
BONTERRA LANDS
SPARTAN AqUISITION
WILLESDEN GREEN ACqUISITION
Corporate Overview
2012 Highlights
2013 Guidance
•
•
•
•
Average Working Interest – 77%
Reserve Life Index (P+P) –
16.1 years
Proved + Probable Reserves –
70.5 MBOE
Land Position – 250.3 gross
(193.7 net) sections
• Booked Locations – 219 gross; 178.4 net
•
•
•
•
•
2012 Average Daily Production 6,703
BOE per day
34 gross (22.9 net) horizontal wells drilled
Production per share increased 4.2% to
0.124 BOE per share
P+P reserves increased 9.4 percent to
45.0 million BOE
Reserve per share increased (P+P)
increased 7.0% to 2.28 BOE per share
•
•
•
Average Daily Production
12,000 BOE per day
Production Profile – 75% Liquids; 25% Gas
Operating Costs – $13.00 per BOE
• Capital Budget – $90 million
•
Drilling Program – 29 gross (28.1 net)
operated and 13 gross (4.3 net)
non-operated horizontal wells
• Average Well Costs – $2.7 million
BONTERRA | ANNUAL REPORT 2012
9
PEMBINA CARDIUM MAIN POOL
ORIGINAL OIL IN PLACE
0 to 5,000 Mbbl
5,000 to 10,000 Mbbl
10,000 to 15,000 Mbbl
15,000 to 20,000 Mbbl
20,000+ Mbbl
Bonterra Land
HIGH AMOUNTS OF ORIGINAL OIL IN PLACE
WITH LOW RECOVERY FACTOR
5+ million bbl OOIP, Less than 15%RF
5+ million bbl OOIP, Less than 10%RF
5+ million bbl OOIP, Less than 5%RF
Bonterra Land
CURRENT RECOVERY FACTOR
0%-5% RF
5%-10% RF
10%-15% RF
15%-20% RF
20%-25% RF
25+% RFl
Bonterra
Land
mOmENTUm IN 2013
In 2013, Bonterra will execute a disciplined $90 million capital
program focused on its oil weighted opportunities in the
Cardium Formation. Bonterra has continued to improve and
refine its Cardium development strategy to both increase well
performance and reserve recoveries while minimizing costs.
In 2013, Bonterra will drill several different areas within the
Pembina and Willesden Green fields and expects to
transition to pad drilling in the future once delineation
drilling is completed.
As shown in these three maps, the majority of Bonterra’s land
position in the Pembina Cardium pool covers areas with high
original oil in place and low current recovery factors. The
Spartan transaction added a significant land position in areas
exhibiting these highly prospective characteristics. The
company is currently assessing additional opportunities to
further increase both recovery factors and rates of return
on its large asset base.
The Company recently completed a reservoir simulation
model to investigate optimal well densities, fracture spacing
and wellbore orientations in the Pembina field. The simulation
suggested that in some cases, increased well densities will
result in higher recoveries and ultimately higher rates of
return. The simulation also investigated the potential for
secondary recovery methods. Bonterra will use these findings
to further calibrate its development of the Cardium and
optimize overall recoveries.
Bonterra has continued to improve
and refine its Cardium development
strategy to both increase well
performance and reserve recoveries
while minimizing costs.
OPTImIzING PERFORmANCE
Bonterra’s operating strategy is aimed at enhancing cash flow
over the long-term to maintain sustainability in the dividends
paid to investors. Bonterra’s commitment to operational and
technical excellence helps to reduce development risks and
lower operating costs, thus allowing the Company to
maximize netbacks.
10
BONTERRA | ANNUAL REPORT 2012
A strong focus for Bonterra’s technical team in 2013 will be
continued optimization across its operations. Bonterra has
been refining its frac placement methods and fluid types to
decrease capital costs. In 2012, the Company fully transitioned
to water-based fracs which has significantly reduced overall
well costs and increased per well production results. In 2013,
Bonterra is currently targeting drilling, completion, equipping
and tie-in costs to average approximately $2.7 million per well.
The Spartan assets delivered significant efficiencies including a
100 percent owned gas plant and will provide the opportunity
for further facility consolidations. In addition, Spartan realized
significant capital savings through a monobore well design
and pad drilling in the Keystone Unit No. 2 to the point in
which Spartan’s average spud to rig release averaged just
seven days. Bonterra expects to realize similar efficiencies
as it transitions into similar drilling scenarios in the future.
Bonterra operates approximately 88.5 percent of its total
production, thereby allowing the Company to better manage
costs and efficiently invest capital. Bonterra is able to
strategically schedule development programs and well
workovers to control its pace as well as manage its corporate
decline through the prudent use of capital and selective timing
of its drilling program to deliver sustainable and consistent
growth to its shareholders.
Bonterra’s commitment to operational and technical excellence helps to reduce
development risks and lower operating costs, thus allowing the Company to
maximize netbacks.
PROVED PLUS
PROBABLE RESERVES
(MBOE)
2012 PRODUCTION
BY COMMODITY
2012 RESERVES
BY COMMODITY
2012
2012
2011
2010
2009
2008
Proforma Spartan
70,537
33%
45,032
41,149
39,397
35,824
31,241
67%
Natural gas
Oil & NGLs
25%
75%
Natural gas
Oil & NGLs
BONTERRA | ANNUAL REPORT 2012
11
STATISTICAL REVIEW
CORPORATE RESERVES INFORmATION:
Bonterra engaged the services of Sproule Associates Limited to prepare a reserve evaluation with an effective date of December
31, 2012. The reserves are located in the provinces of Alberta, British Columbia and Saskatchewan. The gross reserve figures from
the following tables represent Bonterra’s ownership interest before royalties and before consideration of the Company’s royalty
interests. Tables may not add due to rounding.
SUmmARY OF GROSS OIL AND GAS RESERVES AS OF DECEmBER 31, 2012
Reserve category:
PROVED
Developed producing
Developed non-producing
Undeveloped
TOTAL PROVED
PROBABLE
TOTAL PROVED PLUS PROBABLE
Light and
medium oil
(Mbbl)
14,415.7
366.3
8,151.6
22,933.6
8,013.1
30,946.7
Natural gas
(Mmcf)
Natural gas
liquids (Mbbl)
BOE(1)
(MBOE)
33,037
2,629
13,592
49,258
18,963
68,221
1,365.7
51.8
573.5
1,991.0
724.0
2,715.0
21,287.6
856.3
10,990.4
33,134.3
11,897.6
45,031.9
RECONCILIATION OF COmPANY GROSS RESERVES BY PRINCIPAL PRODUCT TYPE
AS OF DECEmBER 31, 2012
Light and medium oil
and natural gas liquids
Natural gas
BOE(1)
Proved plus
probable
(Mbbl)
Proved
(Mbbl)
Proved
(Mmcf)
Proved plus
probable
(Mmcf)
Proved
(MBOE)
Proved plus
probable
(MBOE)
21,160.1
1,142.7
4,482.4
(883.1)
-
770.0
-
(158.7)
(1,588.8)
24,924.6
30,492.4
1,403.6
5,792.5
(3,470.0)
-
1,200.3
-
(168.4)
(1,588.8)
33,661.7
41,822
1,279
7,769
403
-
2,685
-
(564)
(4,136)
49,258
63,941
1,624
10,039
(5,052)
-
3,769
-
(1,964)
(4,136)
68,221
28,130.4
1,355.9
5,777.2
(815.9)
-
1,217.5
-
(252.7)
(2,278.1)
33,134.3
41,149.2
1,674.3
7,465.7
(4,312.0)
-
1,828.5
-
(495.7)
(2,278.1)
45,031.9
December 31, 2011
Extension
Improved recovery
Technical revisions
Discoveries
Acquisitions
Dispositions
Economic factors
Production
December 31, 2012
12
BONTERRA | ANNUAL REPORT 2012
SUmmARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEmBER 31, 2012
($ Millions)
Reserve category:
PROVED
Developed producing
Developed non-producing
Undeveloped
TOTAL PROVED
PROBABLE
TOTAL PROVED PLUS PROBABLE
Net present value before income taxes
discounted at (% per year)
0%
5%
10%
841.9
26.8
393.1
1,261.8
614.6
1,876.4
542.9
16.5
191.5
750.9
236.0
986.9
406.5
11.5
96.2
514.2
118.7
632.9
CHANGES TO RESERVES AFTER DECEmBER 31, 2012
On January 25, 2013, Bonterra completed the acquisition of Spartan Oil Corp. (Spartan). Spartan engaged the services of Sproule
Associates Limited to prepare a reserve evaluation with an effective date of December 31, 2012. The gross reserve figures from
the following tables represent Spartan’s ownership interest before royalties and before consideration of the company’s royalty
interests at December 31, 2012.
SUmmARY OF GROSS OIL AND GAS RESERVES AS OF DECEmBER 31, 2012 (SPARTAN)
Reserve category:
PROVED
Developed producing
Developed non-producing
Undeveloped
TOTAL PROVED
PROBABLE
TOTAL PROVED PLUS PROBABLE
Light and
medium oil
(Mbbl)
6,019.8
600.2
8,115.4
14,735.4
4,941.0
19,676.4
Natural gas
(Mmcf)
Natural gas
liquids (Mbbl)
BOE(1)
(MBOE)
9,762
685
10,005
20,452
6,411
26,863
462.8
37.9
533.2
1,033.9
317.9
1,351.7
8,109.6
752.3
10,316.1
19,177.9
6,327.4
25,505.3
BONTERRA | ANNUAL REPORT 2012
13
RECONCILIATION OF COmPANY GROSS RESERVES BY PRINCIPAL PRODUCT TYPE
AS OF DECEmBER 31, 2012 (SPARTAN)
Light and medium oil
and natural gas liquids
Natural gas
BOE(1)
Proved plus
probable
(Mbbl)
Proved
(Mbbl)
Proved
(Mmcf)
Proved plus
probable
(Mmcf)
Proved
(MBOE)
Proved plus
probable
(MBOE)
12,838.2
966.2
690.0
-
2,027.0
-
77.2
-
0.2
(829.5)
15,769.3
18,639.4
1,628.3
1,110.3
-
380.1
-
98.1
-
1.4
(829.8)
21,028.1
11,822
740
390
-
8,515
-
40
-
(1)
(1,054)
20,452
16,750
1,214
793
-
9,109
-
51
-
-
(1,054)
26,863
14,808.5
1,089.5
755.0
-
3,446.2
-
83.9
-
-
(1,005.2)
19,177.9
21,431.1
1,830.6
1,242.5
-
1,898.3
-
106.6
-
1.4
(1,005.5)
25,505.3
December 31, 2011
Extension
Infill drilling
Improved recovery
Technical revisions
Discoveries
Acquisitions
Dispositions
Economic factors
Production
December 31, 2012
SUmmARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEmBER 31, 2012 (SPARTAN)
($ Millions)
Reserve category:
PROVED
Developed producing
Developed non-producing
Undeveloped
TOTAL PROVED
PROBABLE
TOTAL PROVED PLUS PROBABLE
Net present value before income taxes
discounted at (% per year)
0%
5%
10%
428.7
42.9
437.1
908.7
387.2
1,295.9
296.9
29.2
236.2
562.3
149.6
711.9
228.5
22.3
138.4
389.2
73.1
462.3
14
BONTERRA | ANNUAL REPORT 2012
PRO FORmA RESERVES AND NET PRESENT VALUES (BONTERRA AND SPARTAN)
SUmmARY OF GROSS OIL AND GAS RESERVES AS OF DECEmBER 31, 2012
Reserve category:
PROVED
Developed producing
Developed non-producing
Undeveloped
TOTAL PROVED
PROBABLE
TOTAL PROVED PLUS PROBABLE
Light and
medium oil
(Mbbl)
20,435.5
966.5
16,267.0
37,669.0
12,954.1
50,623.1
Natural gas
(Mmcf)
Natural gas
liquids (Mbbl)
BOE(1)
(MBOE)
42,799
3,314
23,597
69,710
25,374
95,084
1,828.5
89.7
1,106.7
3,024.9
1,041.9
4,066.7
29,397.2
1,608.6
21,306.5
52,312.2
18,225.0
70,537.2
SUmmARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEmBER 31, 2012
($ Millions)
Reserve category:
PROVED
Developed producing
Developed non-producing
Undeveloped
TOTAL PROVED
PROBABLE
TOTAL PROVED PLUS PROBABLE
Net present value before income taxes
discounted at (% per year)
0%
5%
10%
1,270.6
69.7
830.1
2,170.5
1,001.8
3,172.3
839.9
45.7
427.7
1,313.3
385.6
1,698.8
635.0
33.8
234.6
903.4
191.8
1,095.2
FINDING, DEVELOPmENT AND ACqUISITION (FD&A) COSTS
The Company has historically been active in its capital development program. Over three years, Bonterra has incurred the
following FD&A(3) costs excluding Future Development Costs:
Proved reserve net additions
Proved plus probable reserve net additions
$
$
13.64
16.05
$
$
33.22
15.38
$
$
13.89
13.02
$
$
16.22
14.79
2012 FD&A
costs per
BOE(1)(2)(3)
2011 FD&A
costs per
BOE(1)(2)(3)
2010 FD&A
costs per
BOE(1)(2)(3)
Three year
average(4)
BONTERRA | ANNUAL REPORT 2012
15
Over three years, Bonterra has incurred the following FD&A(3) costs including Future Development Costs:
2012 FD&A
costs per
BOE(1)(2)(3)
2011 FD&A
costs per
BOE(1)(2)(3)
2010 FD&A
costs per
BOE(1)(2)(3)
Three year
average(5)
Proved reserve net additions
Proved plus probable reserve net additions
$
$
20.91
21.62
$
$
57.53
35.40
$
$
21.98
19.19
$
$
19.47
17.92
(1) Barrels of Oil Equivalent may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
(2) The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future
development costs generally will not reflect total finding and development costs related to reserve additions for that year.
(3) FD&A costs are net of proceeds of disposal and the FD&A costs per BOE are based on reserves acquired net of reserves disposed of.
(4) Three year average is calculated using three year total capital costs and reserve additions on both a Proved and Proved plus Probable basis.
(5) Three year average is calculated using three year total capital costs and reserves additions on both a Proved and Proved plus Probable basis plus the average
change in future capital costs over the three year period.
COmmODITY PRICES USED IN THE ABOVE CALCULATIONS OF RESERVES ARE AS FOLLOWS:
Edmonton
par price
(Cdn $
per Bbl)
Natural gas
AECO-C spot
(Cdn $ per
MMbtu)
Butanes
Edmonton
(Cdn $
per Bbl)
Pentanes
Edmonton
(Cdn $
per Bbl)
Inflation
rate
(%/Yr)
Exchange
rate
($U.S./$Cdn)
84.55
89.84
88.21
95.43
96.87
98.32
99.79
101.29
104.35
105.92
3.31
3.72
3.91
4.70
5.32
5.40
5.49
5.58
5.67
5.76
63.02
66.96
65.74
71.13
72.20
73.28
74.38
75.50
76.63
77.78
90.53
96.19
94.44
102.18
103.71
105.27
106.85
108.45
110.08
111.73
1.5
1.5
1.5
1.5
1.5
1.5
1.5
1.5
1.5
1.5
1.001
1.001
1.001
1.001
1.001
1.001
1.001
1.001
1.001
1.001
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
Crude oil, natural gas and liquid prices escalate at 1.5 percent thereafter.
16
BONTERRA | ANNUAL REPORT 2012
PRODUCTION
Pembina and Willesden Green, Alberta
Saskatchewan
British Columbia
Other Alberta
2012
Oils and NGLs
(Bbls per day)
Natural gas
(MCF per day)
Total
(BOE per day)
4,170
199
27
115
4,511
10,634
45
2,179
299
13,157
5,942
207
390
165
6,703
LAND HOLDINGS
Bonterra’s holdings of petroleum and natural gas leases and rights are as follows:
Alberta
Saskatchewan
British Columbia
2012
2011
Gross acres
Net acres
Gross acres
Net acres
186,389
6,585
62,045
255,019
109,837
5,416
22,639
137,892
169,862
6,881
62,045
238,788
107,645
5,630
22,639
135,914
In 2012, Spartan’s holdings of petroleum and natural gas leases and rights are as follows:
Alberta
Saskatchewan
British Columbia
2012
Gross acres
Net acres
46,987
80,699
-
127,686
42,043
56,503
-
98,546
BONTERRA | ANNUAL REPORT 2012
17
PETROLEUm AND NATURAL GAS ExPENDITURES
The following table summarizes petroleum and natural gas capital expenditures incurred by Bonterra on acquisitions, land,
seismic, exploration and development drilling and production facilities for the years ended December 31:
($ 000s)
Land
Acquisitions
Disposals
Exploration and development costs
Net petroleum and natural gas capital expenditures
2012
182
17,108
(3,753)
84,593
98,130
2011
309
-
(238)
62,615
62,686
DRILLING HISTORY
The following tables summarize Bonterra’s gross and net drilling activity and success:
Crude oil
Natural gas
Dry
Total
Success rate
Crude oil
Natural gas
Dry
Total
Success rate
Development
Gross
Net
34
-
-
34
100%
22.9
-
-
22.9
100%
Development
Gross
25
-
-
25
100%
Net
17.29
-
-
17.29
100%
2012
Exploratory
Gross
Net
-
-
-
-
-
-
-
-
-
-
Total
Gross
34
-
-
34
100%
2011
Exploratory
Gross
Total
Net
Gross
-
-
-
-
-
-
-
-
-
-
25
-
-
25
100%
Net
22.9
-
-
22.9
100%
Net
17.29
-
-
17.29
100%
18
BONTERRA | ANNUAL REPORT 2012
MANAgEMENT’s DiscUssiON AND ANALysis
The following report dated March 21, 2013 is a review of the operations and current financial position for the year ended
December 31, 2012 for Bonterra Energy Corp. (Bonterra or the Company) and should be read in conjunction with the audited
financial statements presented under International Financial Reporting Standards (IFRS), including the notes related thereto.
Use of NoN‑IfRs fINaNcIal MeasURes
Throughout this Management’s Discussion and Analysis (MD&A), the Company uses the terms “payout ratio”, “cash netback”
and “net debt” to analyze operating performance, which are not standardized measures recognized under IFRS and do not have
a standardized meaning prescribed by IFRS. These measures are commonly used in the oil and gas industry and are considered
informative by management, shareholders and analysts. These measures may differ from those made by other companies and
accordingly may not be comparable to such measures as reported by other companies.
The Company calculates payout ratio by dividing cash dividends paid to shareholders by cash flow from operating activities,
both of which are measures prescribed by IFRS which appear on our statements of cash flows. We calculate cash netback by
dividing various financial statement items as determined by IFRS by total production for the period on a barrel of oil
equivalent basis.
fReqUeNtly RecURRINg teRMs
Bonterra uses the following frequently recurring terms in this MD&A: “bbl” refers to barrel, “NGL” refers to natural gas liquids,
“MCF” refers to thousand cubic feet and “BOE” refers to barrels of oil equivalent. Disclosure provided herein in respect of a
BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy conversion
method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
NUMeRIcal aMoUNts
The reporting and the functional currency of the Company is the Canadian dollar.
BONTERRA | ANNUAL REPORT 2012
19
fINaNcIal aNd opeRatIoNal dIscUssIoN
aNNUal coMpaRIsoNs
As at and for the year ended ($ 000s except $ per share)
December 31,
2012
December 31,
2011
December 31,
2010
FINANCIAL
Revenue – realized oil and gas sales
Cash flow from operations
Per share – basic
Per share – diluted
Payout ratio (1)
Cash dividends per share (1)
Net earnings
Per share – basic
Per share – diluted
Capital expenditures and acquisitions, net of dispositions
Total assets
Working capital deficiency
Long-term debt
Shareholders’ equity
OPERATIONS
Oil
NGLs
– barrels per day
– average price ($ per barrel)
– barrels per day
– average price ($ per barrel)
– MCF per day
– average price ($ per MCF)
Total barrels of oil equivalent per day (BOE)
Natural gas
142,770
74,325
3.75
3.75
83%
3.12
33,211
1.68
1.68
98,130(2)
419,933
29,876
166,808
163,277
4,035
82.04
476
52.18
13,157
2.60
6,703
162,277
97,409
5.04
4.98
61%
3.06
43,608
2.25
2.23
62,686
364,176
51,576
69,916
181,640
4,075
92.76
386
60.89
11,163
3.86
6,322
118,980
66,238
3.52
3.42
72%
2.55
39,954
2.12
2.06
70,680
347,825
17,905
85,386
190,173
3,585
74.76
290
47.11
10,521
4.14
5,628
(1) Cash dividends per share are based on payments made in respect of production months within the quarter.
(2) Includes an acquisition that closed on June 7, 2012 for $17,108,000.
20
BONTERRA | ANNUAL REPORT 2012
qUaRteRly coMpaRIsoNs
As at and for the periods ended
($ 000s except for $ per share)
FINANCIAL
Revenue – realized oil and gas sales
Cash flow from operations
Per share – basic
Per share – diluted
Payout ratio (1)
Cash dividends per share (1)
Net earnings
Per share – basic
Per share – diluted
Capital expenditures and acquisitions, net of disposals
Total assets
Working capital deficiency
Long-term debt
Shareholders’ equity
OPERATIONS
Oil (barrels per day)
NGLs (barrels per day)
Natural gas (MCF per day)
Total BOE per day
2012
Q4
Q3
Q2
Q1
39,624
21,460
1.08
1.08
72%
0.78
6,082
0.31
0.31
24,069
419,933
29,876
166,808
163,277
4,400
595
16,009
7,663
35,204
16,440
0.83
0.83
94%
0.78
7,746
0.39
0.39
27,360
412,812
49,808
128,779
169,839
4,108
461
12,583
6,666
31,049
14,727
0.74
0.74
105%
0.78
9,201
0.47
0.46
25,288(2)
393,772
42,082
114,747
176,292
3,650
428
11,753
6,037
36,893
21,698
1.10
1.10
71%
0.78
10,182
0.52
0.51
21,413
371,757
57,889
75,543
181,008
3,975
419
12,260
6,438
(1) Cash dividends per share are based on payments made in respect of production months within the quarter.
(2) Includes an acquisition that closed on June 7, 2012 for $17,108,000.
BONTERRA | ANNUAL REPORT 2012
21
As at and for the periods ended
($ 000s except for $ per share)
FINANCIAL
Revenue – oil and gas sales
Cash flow from operations
Per share – basic
Per share – diluted
Payout ratio (1)
Cash dividends per share (1)
Net earnings
Per share – basic
Per share – diluted
Capital expenditures and acquisitions,
net of dispositions
Total assets
Working capital deficiency
Long-term debt
Shareholders’ equity
OPERATIONS
Oil (barrels per day)
NGLs (barrels per day)
Natural gas (MCF per day)
Total BOE per day
2011
Q4
Q3
Q2
Q1
42,818
26,180
1.35
1.33
58%
0.78
6,067
0.31
0.31
20,529
364,176
51,576
69,916
181,640
4,096
493
12,541
6,679
36,535
21,730
1.12
1.10
69%
0.78
9,384
0.49
0.48
15,941
354,549
43,362
72,391
185,908
3,789
340
10,553
5,887
44,754
25,465
1.32
1.29
59%
0.78
14,533
0.75
0.74
5,872
348,097
30,823
72,608
192,297
4,164
372
11,024
6,373
38,170
24,034
1.25
1.22
58%
0.72
13,624
0.71
0.69
20,344
357,000
39,777
70,568
192,054
4,258
338
10,517
6,350
(1) Cash dividends per share are based on payments made in respect of production months within the quarter.
BUsINess eNvIRoNMeNt
Bonterra’s financial results are significantly influenced by fluctuations in commodity prices, including price differentials. The
following table depicts selective market benchmark prices and foreign exchange rates in the last eight quarters to assist in
understanding volatility in prices and foreign exchange rates that have impacted Bonterra’s financial and operating performance.
Crude oil
WTI (U.S.$/bbl)
Bonterra average realized
price (Cdn$/bbl)
Natural gas
AECO (Cdn$/mcf)
Bonterra average realized
price (Cdn$/mcf)
Foreign exchange
(Cdn$/U.S.$)
Q4-2012
Q3-2012
Q2-2012
Q1-2012
Q4-2011
Q3-2011
Q2-2011
Q1-2011
88.18
78.58
3.20
3.43
92.22
93.49
102.93
94.06
89.76
102.56
94.10
80.54
80.93
88.48
96.25
88.21
101.30
85.02
2.31
2.41
1.89
1.96
2.15
3.19
3.65
3.86
2.32
3.34
3.91
4.15
3.79
4.12
0.9913
0.9948
1.0102
1.0012
1.0231
0.9802
0.9677
0.9860
In 2012, the price differentials between Bonterra’s average realized price and WTI widened substantially from prices received in
2011, due in most part to reduced demand because of refinery outages and seasonal turnarounds and the inability to get oil to
markets because of pipeline capacity constraints and quality adjustments. The price differential did tighten during the fourth
quarter of 2012 due to a combination of increased rail shipments, a reduction in the production of Alberta synthetic crude and
increased demand from U.S. and Canadian refineries. However, continued European and North American economic concerns and
pipeline capacity constraints negatively affected the price for oil realized in Canada in the latter part of Q4 2012. A number of
pipeline expansions and pipeline reversals currently underway will assist in delivering more oil to markets later in 2013 and 2014.
22
BONTERRA | ANNUAL REPORT 2012
In addition, there are a number of ongoing pipeline initiatives including Keystone XL pipeline in the U.S. and Northern Gateway
pipeline in Canada to assist in delivering future increases in Canadian production volumes. However, neither of these have
received government or regulatory approval at this time.
Notwithstanding the current price challenges in both oil and natural gas markets, the Company expects to be able to continue
exploiting its current land base, growing production on a per share basis and maintaining payment of its dividend.
BUsINess oveRvIew, stRategy aNd Key peRfoRMaNce dRIveRs
Bonterra is a growing petroleum and natural gas focused Canadian energy corporation that actively develops, produces and sells
crude oil, natural gas and natural gas liquids, to provide ever increasing returns to its shareholders. Bonterra’s geographically
concentrated assets are primarily low‑risk, high working interest properties that provide abundant infill drilling opportunities and
good access to infrastructure and processing facilities. The Company continues to focus its exploration efforts primarily on
horizontal infill drilling opportunities for light crude oil in the Company’s core Pembina and Willesden Green Cardium properties.
In June 2012, the Company purchased Willesden Green oil and gas assets for consideration of $17,108,000. The purchase added
52.3 gross (10.5 net) sections of land, 191 gross (37 net) potential Cardium formation drilling locations and 250 BOE per day of
production, net to the Company. These lands are considered underdeveloped as horizontal well development is in its
early stages.
On January 25, 2013, Bonterra acquired 100 percent of the issued and outstanding common shares of Spartan Oil Corp. (Spartan)
pursuant to an arrangement agreement. Spartan was a public oil and gas company with properties in Alberta and Saskatchewan.
Consideration for Spartan shares was 0.1169 voting common shares of Bonterra, which amounted to the issuance of 10,711,405
Bonterra shares valued at $502,258,000. Spartan has contributed strong cash flow, positive working capital, no debt and a
light‑oil asset base primarily concentrated in the Pembina Cardium region, providing a complimentary production base and a
long‑term inventory of drilling opportunities. The acquisition is anticipated to assist Bonterra on a financial and operating basis,
continue to grow production and cash flow on a per share basis and to maintain a strong financial position. The acquisition adds
to Bonterra’s sustainable, high‑netback, production profile, company‑owned infrastructure and its high‑quality, multi‑year drilling
inventory that is in excess of 10 years (assuming four wells per section). On March 1, 2013 Spartan amalgamated with Bonterra.
Bonterra’s successful operations are dependent upon several factors, including but not limited to, the price of energy commodity
products, efficiently managing capital spending, its ability to maintain desired levels of production, control over its infrastructure,
its efficiency in developing and operating properties and its ability to control costs. The Company’s key measures of performance
with respect to these drivers include, but are not limited to, average production per day, average realized prices and average
operating costs per unit of production. Disclosure of these key performance measures can be found in the MD&A and/or previous
interim or annual MD&A disclosures.
dRIllINg
($ 000s)
December 31,
2012
Net(2) Gross(1)
Three months ended
September 30,
2012
Net(2) Gross(1)
Gross(1)
December 31,
2011
Net(2) Gross(1)
December 31,
2012
Net(2) Gross(1)
December 31,
2011
Net(2)
Year ended
Crude oil horizontal – operated
Crude oil horizontal – non-operated
Total
Success rate
6
6
12
4.6
1.6
6.2
100%
10
2
12
7.8
1.0
8.8
100%
6
2
8
5.2
0.6
5.8
100%
24
10
34
20.0
2.9
22.9
100%
20
5
25
16.3
1.0
17.3
100%
(1) “Gross” wells means the number of wells in which Bonterra has a working interest.
(2) “Net” wells means the aggregate number of wells obtained by multiplying each gross well by Bonterra’s percentage of working interest.
During 2012, the Company placed two gross (two net) wells on production that were drilled in 2011, drilled 24 gross (20.0 net)
wells, of which 21 gross (17.0 net) were placed on production. The remaining three (3.0 net) wells were placed on production in
the first quarter of 2013. In addition, 10 gross (2.9 net) non‑operated wells were drilled and placed on production during 2012.
BONTERRA | ANNUAL REPORT 2012
23
The majority of the Company’s 2012 drilling program was completed in the third quarter of 2012. Of the eight gross wells drilled
in the first half of 2012, five gross (4.6 net) were completed and placed on production in the third quarter.
In the second half of the year, the Company drilled 16 gross (12.4 net) wells of which nine gross (7.0 net) were placed on
production in the third quarter and four gross (2.4 net) were placed on production in the fourth quarter. Included in the fourth
quarter were three gross (3.0 net) wells drilled but originally budgeted for 2013. These wells commenced production in the
first quarter of 2013.
pRodUctIoN
($ 000s)
Crude oil (barrels per day)
NGLs (barrels per day)
Natural gas (MCF per day)
Average BOE per day
December 31,
2012
Three months ended
September 30,
2012
Year ended
December 31,
2011
December 31,
2012
December 31,
2011
4,400
595
16,009
7,663
4,108
461
12,583
6,666
4,096
493
12,541
6,679
4,035
476
13,157
6,703
4,075
386
11,163
6,322
Production volumes during 2012 increased to 6,703 BOE per day compared to 6,322 BOE per day during 2011. The increase in
production is due to the continued success of the Cardium horizontal drilling program in the Pembina and Willesden Green
areas and the accelerated drilling program in the second half of the year. During 2012, the increase in production was negatively
impacted by pipeline constraints, a saturated refining market, forest fires and high levels of precipitation during Q2 2012 which
significantly delayed drilling and completion of wells.
Production volumes for Q4 2012 increased by 15 percent to 7,663 BOE per day compared to Q3 2012, which was due to a full
quarter of production from newly tied‑in wells. The Company tied‑in four gross wells (2.4 net) in Q4 2012 compared to 14 gross
wells (11.6 net) late in Q3 2012. The increased production was partially offset by a pipeline apportionment for the month
of December.
Subsequent to year end, the Company purchased Spartan. At the time of closing, Bonterra was producing approximately
8,700 BOE per day and Spartan was producing approximately 4,800 BOE per day for a combined production of 13,500 BOE
per day that includes substantial flush production from a large number of new wells. These new wells have sizeable decline
rates during the first year of production and as such, average daily production volumes for 2013 are estimated to be
approximately 12,000 BOE per day (a reduction from the present level of 13,500 BOE per day). Spartan’s assets also consisted
of a 12 MMcf per day operated and wholly owned gas plant that will provide more flexibility for gas processing, help alleviate
pipeline constraints and reduce future shut‑in production issues.
oIl aNd gas sales
($ 000s)
Revenue – oil and gas sales
Average realized prices ($):
Crude oil (per barrel)
NGLs (per barrel)
Natural gas (per MCF)
Average (per BOE)
December 31,
2012
Three months ended
September 30,
2012
Year ended
December 31,
2011
December 31,
2012
December 31,
2011
39,624
35,204
42,818
142,770
162,277
78.58
50.41
3.43
56.20
80.54
46.40
2.41
57.40
96.25
59.46
3.34
69.68
82.04
52.18
2.60
58.19
92.76
60.89
3.86
70.33
Revenue from oil and gas sales decreased by $19,507,000 in 2012 or 12 percent compared to 2011. This decrease was due to an
11 percent decrease in the average realized price per BOE, made up of a combination of an 11 percent decrease in oil prices, a
14 percent decrease in NGL prices and 32 percent decrease in natural gas prices from one year ago. Overall pricing was the
significant factor in reduced revenues as oil production was relatively flat, natural gas production increased by 18 percent and
NGL production increased by 23 percent compared to 2011.
24
BONTERRA | ANNUAL REPORT 2012
The quarter over quarter increase in oil and gas revenues of 13 percent or $4,420,000, was in part due to a 15 percent increase
in production, being a combination of oil production increases of seven percent, NGL production increases of 29 percent and
natural gas production increases of 27 percent compared to the prior quarter. Average realized prices were also a factor in
increased revenues, as NGL prices increased nine percent and natural gas prices increased by 42 percent compared to the
prior quarter.
The Company’s product split on a revenue basis for the 2012 is approximately 91 percent weighted towards crude oil and NGLs.
This ratio will likely remain similar or increase as the Company continues to develop its Pembina and Willesden Green Cardium
(mainly oil) properties.
The Company did not enter into any commodity price hedges or other types of risk management contracts in either 2011 or 2012.
RoyaltIes
($ 000s)
Crown royalties
Freehold, gross overriding and
other royalties
Total royalties
Crown royalties – percentage of
revenue
Freehold, gross overriding and other
royalties – percentage of revenue
Royalties – percentage of revenue
Royalties $ per BOE
December 31,
2012
Three months ended
September 30,
2012
Year ended
December 31,
2011
December 31,
2012
December 31,
2011
2,436
1,017
3,453
6.1
2.6
8.7
4.90
1,942
720
2,662
5.5
2.1
7.6
4.34
2,993
1,277
4,270
7.6
2.4
10.0
6.95
9,727
4,033
13,760
6.8
2.8
9.6
5.61
12,316
5,261
17,577
7.6
3.2
10.8
7.62
Royalties paid by the Company consist primarily of Crown royalties paid to the Provinces of Alberta, Saskatchewan and British
Columbia. The Company’s average Crown royalty rate is approximately 6.8 percent for 2012 compared to 7.6 percent for 2011. The
decrease is primarily due to lower commodity prices for crude oil and natural gas attracting lower crown royalty rates, partially
offset by horizontal Cardium wells no longer being eligible for the initial five percent royalty rate due to accumulated production
thresholds being reached or the expiry of time allowed to reach the threshold levels. A significant portion of the Company’s
production is from low productivity wells and therefore have reduced Crown royalty rates.
The Crown royalty rate increased for Q4 2012 compared to Q3 2012 primarily due to increased volumes and prices for natural gas
and NGLs.
Non‑crown royalties decreased for 2012 compared to 2011 primarily due to less oil and gas revenue from wells subject to
non‑crown royalties as most new wells were drilled on crown lands. The percent increase in non‑crown royalties quarter over
quarter is primarily due to increased production from the new wells subject to freehold royalties that were placed on production
in the latter half of the year.
pRodUctIoN costs
($ 000s except $ per BOE)
Production costs
$ per BOE
December 31,
2012
Three months ended
September 30,
2012
Year ended
December 31,
2011
December 31,
2012
December 31,
2011
13,407
19.02
10,178
16.59
9,824
15.99
41,408
16.88
36,787
15.94
Total production costs for 2012 increased 13 percent from 2011. On a per BOE basis, production costs have increased by
six percent.
BONTERRA | ANNUAL REPORT 2012
25
In 2012, production costs increased due to higher costs associated with gas compression, gathering and processing fees. The
Company also experienced higher road maintenance costs due to extended wet weather in Q2 2012 and increased frequency of
plant turnarounds during year. In addition, the Company received third party equalization charges of approximately $1,650,000
in the fourth quarter. These onetime charges had the effect of increasing production costs by $0.67 per BOE in 2012. In addition,
the Company was unable to tie‑in a portion of its natural gas production due to pipeline constraints, thereby increasing costs on
a per BOE basis.
Production costs increased by $3,229,000 in Q4 2012 compared to Q3 2012, due to a 15 percent increase in production, including
a 38 percent increase in natural gas production. The Company experienced higher gas compression, gathering, processing fees
and operating charges. Also included in the production costs were onetime charges from third parties. These charges increased
production costs by $2.24 per BOE in Q4 2012.
With the acquisition of Spartan’s wholly owned gas plant facility, the Company now has access to alternative lower cost facilities
for its gas processing. This facility will help to increase gas processing capacity which should alleviate production
apportionments and reduce production costs on a per BOE basis in 2013.
otheR INcoMe
($ 000s)
Gain on sale of property
Realized gain on investments
Investment income
Administrative income
December 31,
2012
Three months ended
September 30,
2012
Year ended
December 31,
2011
December 31,
2012
December 31,
2011
-
943
39
37
1,019
7
1,317
50
83
1,457
-
-
5
79
84
3,616
2,705
161
285
6,767
162
2,126
27
327
2,642
During 2012, the Company disposed of a portion of its Central Alberta Redwater property for cash proceeds of $1,109,000,
equal to the accounting gain, as this property was recorded with no carrying value. The Company also disposed of a portion of
its Central Alberta Tomahawk property for cash proceeds of $2,500,000. At the time of disposition, the property had no carrying
value which results in a gain on sale equal to its proceeds. The Company maintained a non‑operated 50 percent working interest
in the Tomahawk property. One new well was drilled and placed on production in the third quarter and three more wells were
drilled and placed on production in the fourth quarter of 2012.
During 2012, the Company disposed of a portion of its investments for gross proceeds of $3,485,000 (December 31, 2011 ‑
$3,991,000). In addition, the Company realized a gain on investments of $631,000 on the share exchange between Pine Cliff
Energy Ltd. and Geomark Exploration Ltd. (see related party section). The market value of the investments held by the Company
is in excess of $5,000,000 at December 31, 2012 (December 31, 2011 ‑ $6,800,000). The decrease in carrying value is mainly due
to the sale of investments in 2012 partially offset by increased market value in the remaining investments.
The Company receives administrative income by way of management fees from related parties (see related party transactions).
26
BONTERRA | ANNUAL REPORT 2012
geNeRal aNd adMINIstRatIoN (g&a) expeNse
($ 000s except $ per BOE)
Employee compensation expense
Office and administration expense
$ per BOE
December 31,
2012
Three months ended
September 30,
2012
Year ended
December 31,
2011
December 31,
2012
December 31,
2011
875
755
1,630
2.31
935
600
1,535
2.50
896
1,059
1,955
3.18
3,974
2,121
6,095
2.48
4,456
2,332
6,788
2.94
Total G&A expense decreased 10 percent to $6,095,000 for the year ended December 31, 2012 from $6,788,000 in 2011.
The decrease in employee compensation expense of $482,000 for 2012 compared to a year ago was primarily due to reduced
number of staff and a decrease in accrued bonuses, due to lower net earnings before income taxes. The Company has a bonus
plan in which the bonus pool consists of three percent of earnings before income taxes. The Company firmly believes that tying
employee compensation (including the use of stock options) to the performance of the Company clearly aligns the interest of
the employees to that of the shareholders.
Quarter over quarter employee compensation expense decreased due to a reduction in accrued bonuses related to decreased
earnings before taxes.
The decrease in office and administration expense for 2012, related primarily to a decrease in costs of legal, engineering and
regulatory filing fees. This was partially offset by increased consulting fees and computer software costs compared to 2011.
Quarter over quarter office and administration expense increased by $155,000 due to increases in office rent, computer
software costs and additional bank fees relating to the increase in the credit facility during the fourth quarter of 2012.
fINaNce costs
($ 000s except $ per BOE)
Interest on long-term debt
Other interest
Interest expense
$ per BOE
Unwinding of the discounted value
of decommissioning liabilities
Total finance costs
December 31,
2012
Three months ended
September 30,
2012
Year ended
December 31,
2011
December 31,
2012
December 31,
2011
1,616
225
1,841
2.61
224
2,065
779
305
1,084
1.77
227
1,311
547
305
852
1.39
339
1,191
3,730
1,279
5,009
2.04
886
5,895
2,272
1,210
3,482
1.51
954
4,436
Interest on long‑term debt increased 64 percent in 2012 compared to 2011 as the Company increased the bank debt in the
second quarter of 2012 with the Willesden Green Asset acquisition for cash of $17,108,000, repaid a $20,000,000 related party
loan in the fourth quarter of 2012, increased the capital drilling program compared to 2011 and experienced decreased cash
flows as a result of lower commodity pricing from one year ago.
Other interest relates to amounts paid to related parties (see related party transactions), a $15,000,000 subordinated promissory
note from a private investor and a onetime interest charge of $145,000 for the period between the effective date of March 1, 2012
and the closing date of June 7, 2012 on the Willesden Green oil and gas asset purchase.
BONTERRA | ANNUAL REPORT 2012
27
shaRe‑Based payMeNts
($ 000s)
$ per BOE
December 31,
2012
Three months ended
September 30,
2012
Year ended
December 31,
2011
December 31,
2012
December 31,
2011
1,264
1,040
822
4,241
2,554
Share‑based payments are 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. Share‑based payments increased in 2012 over 2011 primarily due to the issuance of 496,500 options
issued in the fourth quarter of 2011 and 942,000 options that were issued during 2012. Quarter over quarter share‑based
payments increased as 734,000 of the 942,000 options issued in 2012 were issued during the fourth quarter of 2012.
Based on currently outstanding options, the Company anticipates that an expense of approximately $3,785,000 will be recorded
for 2013, $427,000 for 2014 and $107,000 for 2015. For more information about options issued and outstanding, please refer to
Note 15 of the December 31, 2012 audited annual financial statements.
depletIoN, depRecIatIoN aNd IMpaIRMeNt
($ 000s)
December 31,
2012
Three months ended
September 30,
2012
Year ended
December 31,
2011
December 31,
2012
December 31,
2011
Depletion and depreciation
Impairment of natural gas assets
10,585
-
8,010
-
13,467
2,585
33,521
-
32,699
2,585
Capital costs for oil and gas properties that result in the addition of reserves are depleted using the unit‑of‑production basis by
field over their total developed reserve life which includes proved plus probable developed reserves only. In 2012, the Company
adjusted its estimate from using a proved developed reserve base to total developed reserve base to better reflect the asset life
expectancy of the Company’s Pembina and Willesden Green Cardium properties through the application of the horizontal
drilling program.
For production facility and equipment expenditures such as well and production processing equipment, the Company uses a
10 percent declining basis for depreciation calculation.
Provision for depletion and depreciation increased by approximately three percent for 2012 over 2011. The increase in depletion
was the result of increased production volumes in 2012 of six percent partially offset by an eight percent increase in total
developed reserves.
Depletion and depreciation increased by 32 percent in the fourth quarter of 2012 over the prior quarter. This was primarily
attributable to increased production of 15 percent and additional capital costs being subject to depletion as the majority of the
2012 wells drilled were placed on production in the second half of the year.
There were no impairment provisions recorded for the year ended December 31, 2012. In 2011, there were significant reductions
in the future commodity price forecasts for natural gas used by the Company’s independent reserves evaluator when compared
to the previous year resulting in an impairment provision of $2,585,000 for minor natural gas assets in British Columbia.
taxes
The Company recorded a deferred tax expense of $11,406,000 for 2012 (2011 ‑ $17,885,000). The deferred tax expense decrease
in 2012 compared to 2011 is primarily related to decreased earnings before income taxes.
The Company has $424,101,000 of tax pools, which may be used to reduce taxable income in future years, limited to various
rates of utilization. The Company also has $27,670,000 (December 31, 2011 ‑ $27,670,000) remaining of investment tax credits
that expire between the years 2019 to 2028. In addition, the Company has $135,502,000 (December 31, 2011 ‑ $137,289,000) of
capital loss carry forwards which can only be claimed against taxable capital gains. For additional information regarding income
taxes, see Note 9 of the December 31, 2012 audited annual financial statements.
28
BONTERRA | ANNUAL REPORT 2012
Net eaRNINgs
($ 000s except $ per share)
Net earnings
$ per share – basic
$ per share – diluted
December 31,
2012
Three months ended
September 30,
2012
Year ended
December 31,
2011
December 31,
2012
December 31,
2011
6,082
0.31
0.31
7,746
0.39
0.39
6,067
0.31
0.31
33,211
1.68
1.68
43,608
2.25
2.23
Net earnings decreased in 2012 by $10,397,000 or 24 percent from 2011. Decreased net earnings resulted primarily from lower
crude oil and natural gas prices, along with increases to operating costs, finance costs and share‑based payments expense. This
decrease was partially offset by increased natural gas and NGL production and a gain on sale of assets along with decreased
royalties and deferred tax expense.
The decrease in net earnings for Q4 2012 compared to Q3 2012 resulted from increased operating costs, royalties, finance costs
and depletion and depreciation expense in Q4 2012 and a larger gain on sale of a portion of the Company’s investment in
marketable securities recorded in Q3 2012.
otheR coMpReheNsIve INcoMe
Other comprehensive loss for 2012 consists of an unrealized gain before tax on investments (including investments in a related
party) of $1,514,000 relating to an increase in the investments’ fair value (December 31, 2011 – unrealized loss of $1,462,000
relating to a decrease in the investments’ fair value). The Company also disposed of a portion of these investments in 2012 for
a realized gain before tax of $2,705,000 (December 31, 2011 ‑ $2,126,000). Realized gains decrease other comprehensive income
as these gains are transferred to net earnings. Other comprehensive income varies from net earnings by unrealized changes in
the fair value of Bonterra’s holdings of investments including the investment in related party, net of tax.
cash flow fRoM opeRatIoNs
($ 000s except $ per share)
Cash flow from operations
$ per share – basic
$ per share – diluted
December 31,
2012
Three months ended
September 30,
2012
Year ended
December 31,
2011
December 31,
2012
December 31,
2011
21,460
1.08
1.08
16,440
0.83
0.83
26,180
1.35
1.33
74,325
3.75
3.75
97,409
5.04
4.98
In 2012, cash flow from operations decreased by $23,084,000 or 24 percent compared to 2011. This was primarily due to
decreased crude oil and natural gas prices along with increases in operating and finance costs, partially offset by lower royalties
and G&A expenditures. The quarter over quarter increase of $5,020,000, or 31 percent, was due primarily to an increase in oil
and gas production and revenue, partially offset by higher operating and finance costs and royalties.
BONTERRA | ANNUAL REPORT 2012
29
cash NetBacK
The following table illustrates the calculation of the Company’s cash netback from operations for the periods ended:
$ per BOE
Production volumes (BOE)
Gross production revenue
Royalties
Field operating costs
Field netback
General and administrative
Interest and other
Cash netback
December 31,
2012
Three months ended
September 30,
2012
Year ended
December 31,
2011
December 31,
2012
December 31,
2011
705,001
$56.20
(4.90)
(19.02)
32.28
(2.31)
(2.51)
$27.46
613,296
$57.40
(4.34)
(16.59)
36.47
(2.50)
(1.56)
$32.41
614,482
$69.68
(6.95)
(15.99)
46.74
(3.18)
(1.25)
$42.31
2,453,474
$58.19
(5.61)
(16.88)
35.70
(2.48)
(1.86)
$31.36
2,307,465
$70.33
(7.62)
(15.94)
46.77
(2.94)
(1.36)
$42.47
Related paRty tRaNsactIoNs
On October 19, 2012, Pine Cliff Energy Ltd. (Pine Cliff), a company with some common directors and some common management
with Bonterra, acquired 100 percent of the issued and outstanding common shares of Geomark Exploration Ltd. (Geomark),
pursuant to an arrangement agreement. Consideration for each Geomark Share was 1.5 voting common shares of Pine Cliff.
Bonterra now holds 1,034,523 common shares in Pine Cliff (December 31, 2011 – 689,682 common shares in Geomark) which
represents 0.7 percent ownership in Pine Cliff’s outstanding common shares. Pine Cliff’s common shares have a fair market value
as of December 31, 2012 of $910,000 (December 31, 2011 ‑ $566,000 fair value of the Geomark shares). Geomark paid a
management fee to the Company of $225,000 (December 31, 2011 ‑ $270,000). With the arrangement, the management
agreement between Bonterra and Geomark was terminated effective October 19, 2012.
On November 9, 2012, Bonterra repaid the $20,000,000 (December 31, 2011 ‑ $20,000,000) loan with Geomark. Interest paid
on this loan during the year was $397,000 (December 31, 2011 ‑ $475,000).
The Company also has a management agreement with Pine Cliff. Pine Cliff paid a management fee to the Company of $60,000
(December 31, 2011 ‑ $60,000). Services provided by the Company include executive services, accounting services, oil and gas
administration and office administration. All services performed are charged at estimated fair value. As at December 31, 2012,
the Company had an account receivable from Pine Cliff of $45,000 (December 31, 2011 – $4,000).
As at December 31, 2012, the Company’s CEO, Chairman of the Board and major shareholder has loaned the Company
$12,000,000 (December 31, 2011 ‑ $12,000,000). The loan bears interest at Canadian chartered bank prime less 5/8th of a
percent and has no set repayment terms but is payable on demand. Security under the debenture is over all of the Company’s
assets and is subordinated to any and all claims in favour of the syndicate of senior lenders providing credit facilities to the
Company. The loan can only be repaid should the Company have sufficient available borrowing limits under the Company’s
credit facility. Interest paid on this loan during 2012 was $286,000 (December 31, 2011 ‑ $285,000). This loan results in a
substantial benefit to Bonterra as the interest paid to the CEO by Bonterra is lower than bank interest.
30
BONTERRA | ANNUAL REPORT 2012
lIqUIdIty aNd capItal ResoURces
woRKINg capItal defIcIeNcy
($ 000s)
Working capital deficiency
Long-term bank debt
Net debt
Shareholders' equity
Total
December 31,
2012
December 31,
2011
29,876
166,808
196,684
163,277
359,961
51,576
69,916
121,492
181,640
303,132
Net deBt aNd woRKINg capItal
Net debt is a combination of long‑term bank debt and working capital. The increase in net debt from $121,492,000 at
December 31, 2011 to $196,684,000 at December 31, 2012 is attributable primarily to the substantial decrease in commodity
prices in 2012 compared to 2011 and thus lower field net backs and cash flow from operations. In addition, the Company
increased capital spending during 2012 compared to 2011, while at the same time maintaining the dividends paid to shareholders.
Working capital is calculated as current liabilities less current assets. The Company finances its working capital deficiency
using cash flow from operations, its long‑term bank facility, share issuances, option exercises and sale of investments.
capItal expeNdItURes
During the year ended December 31, 2012, the Company incurred capital costs of $81,022,000 (2011 ‑ $62,686,000 net of
drilling credits) net of proceeds on disposal of property, plant and equipment. The costs relate primarily to the drilling of
24 gross (20.0 net) Pembina and Willesden Green Cardium operated horizontal wells and 10 (2.9 net) non‑operated wells,
facilities and gathering systems.
In June 2012, the Company purchased Willesden Green oil and gas assets for cash consideration of $17,108,000, which
included oil and gas properties and equipment and is not included in the above outlined capital costs for 2012.
loNg‑teRM deBt
Long‑term debt represents the outstanding draws from the Company’s credit facility as described in the notes to the
Company’s annual financial statements. As of December 31, 2012, the Company has a bank facility consisting of a $160,000,000
(December 31, 2011 ‑ $120,000,000) syndicated revolving credit facility and a $20,000,000 non‑syndicated revolving
credit facility. Amounts drawn under these facilities at December 31, 2012 were $166,808,000 (December 31, 2011 ‑ $69,916,000).
The interest rates on the outstanding debt as of December 31, 2012 were 3.8 percent and 3.0 percent on the Company’s Canadian
prime rate loan and Banker’s Acceptances, respectively. The loan is revolving to April 25, 2013 and with a maturity date of April
25, 2014 and is subject to annual review. The revolving credit facility has no fixed terms of repayment.
Advances drawn under the credit facility are secured by a fixed and floating charge debenture over the assets of the Company.
In the event the credit facility are not extended or renewed, amounts drawn under the facility would be due and payable on the
maturity date. The size of the committed credit facilities is based primarily on the value of the Company’s producing petroleum
and natural gas assets and related tangible assets as determined by the lenders. For more information please see Note 13 of the
December 31, 2012 audited annual financial statements.
BONTERRA | ANNUAL REPORT 2012
31
shaReholdeRs’ eqUIty
The Company is authorized to issue an unlimited number of common shares without nominal or par value.
December 31, 2012
December 31, 2012
Issued and fully paid – common shares
Balance, beginning of year
Issued pursuant to the Company share option plan
Transfer from contributed surplus to share capital
Balance, end of year
Number
19,571,316
338,225
19,909,541
Amount
($ 000s)
142,567
6,934
376
149,877
Number
19,219,541
351,775
19,571,316
Amount
($ 000s)
135,030
7,150
387
142,567
The Company is authorized to issue an unlimited number of Class “A” redeemable Preferred Shares and an unlimited number
of Class “B” Preferred Shares. There are currently no outstanding Class “A” redeemable Preferred Shares or Class “B”
Preferred Shares.
The Company provides a stock option plan for its directors, officers, employees and consultants. Under the plan, the Company
may grant options for up to 1,990,954 (December 31, 2011 – 1,957,131) common shares. The exercise price of each option granted
will not be lower than the market price of the common shares on the date of grant and the option’s maximum term is five years.
For additional information regarding options outstanding, please see Note 15 of the December 31, 2012 audited annual
financial statements.
dIvIdeNd polIcy
For the year ended December 31, 2012, Bonterra paid dividends of $61,707,000 ($3.12 per share) compared to $58,805,000
($3.04 per share) in the same period in 2011. Bonterra’s dividend policy is regularly monitored and is dependent upon
production, commodity prices, funds from operations, debt levels and capital expenditures. With its large inventory of
undrilled locations, Bonterra continues to be well positioned to provide its shareholders a combination of sustainable growth
and dividend income.
Bonterra’s dividends to its shareholders are funded by cash flow from operating activities with the remaining cash flow directed
towards capital spending and, where applicable, the repayment of debt. To the extent that the excess cash flow from operations
after dividends is not sufficient to cover capital spending, the shortfall is funded by funds from the exercising of employee stock
options, the sale of investments and by draw downs from Bonterra’s credit facilities. Bonterra intends to provide dividends to
shareholders that are sustainable to the Company considering its liquidity and its long‑term operational strategy. In addition,
since the level of dividends is highly dependent upon cash flow generated from operations, which fluctuates significantly in
relation to changes in financial and operational performance, commodity prices, interest and exchange rates and many other
factors, future dividends cannot be assured. Bonterra’s payout ratio based on cash flow was 83 percent for the year ended
December 31, 2012 (61 percent for the year ended December 31, 2011).
Net deBt to cash flow
Bonterra intends to continue focusing on managing its cash flow, capital expenditure ranges and dividend payments. At December 31, 2012,
the Company was in excess of its annual guidance of 1.5 to 1 times net debt to cash flow ratio with a ratio of 2.65 to 1 times. This
ratio was higher due to lower than budgeted commodity prices, higher than budgeted capital costs and the Willesden Green oil
and gas asset acquisition of $17.1 million. The Company believes the Spartan acquisition in January 2013 (see Note 20 to the
annual financial statements) and the Willesden Green asset acquisition will help to sustain future cash flows and shareholder
dividends and significantly improve the debt to cash flow ratio back to an annual range of 1.0 to 1 times and 1.5 to 1 times.
32
BONTERRA | ANNUAL REPORT 2012
qUaRteRly fINaNcIal INfoRMatIoN
For the periods ended
($ 000s except $ per share)
Revenue – oil and gas sales
Cash flow from operations
Net earnings
Per share – basic
Per share – diluted
For the periods ended
($ 000s except $ per share)
Revenue – oil and gas sales
Cash flow from operations
Net earnings
Per share – basic
Per share – diluted
2012
Q3
35,204
16,440
7,746
0.39
0.39
2011
Q3
36,535
21,730
9,384
0.49
0.48
Q2
31,049
14,727
9,201
0.47
0.46
Q2
44,754
25,465
14,533
0.75
0.74
Q4
39,624
21,460
6,082
0.31
0.31
Q4
42,818
26,180
6,067
0.31
0.31
Q1
36,893
21,698
10,182
0.52
0.51
Q1
38,170
24,034
13,624
0.71
0.69
The fluctuations in the Company’s revenue and net earnings from quarter to quarter are primarily caused by variations in
production volumes, realized oil and natural gas pricing and the related impact on royalties. Q4 2011 net earnings were lower
than the prior quarter due to the recording of an impairment of natural gas assets.
cRItIcal accoUNtINg estIMates
The historical information in this MD&A is based primarily on the Company’s financial statements, which have been prepared in
Canadian dollars in accordance with IFRS. The application of IFRS requires management to make estimates, judgements and
assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets or liabilities, if any,
at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Bonterra
bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the
circumstances. Actual results could differ materially from these estimates under different assumptions or conditions. The
following are estimates and judgements applied by management that most significantly affect the company’s
financial statements:
ReseRve estIMatIoN
The capitalized costs of proved oil and gas properties are amortized to expense on a unit of production basis at a rate calculated
by reference to proved plus probable developed reserves determined in accordance with National Instrument 51‑101 and the
Canadian Oil and Gas Evaluation Handbook. Commercial reserves are determined using best estimates of oil and gas in place,
recovery factors, future development and extraction cots and future oil and gas prices.
Proved reserves are those reserves that have a reasonable certainty (normally at least 90 percent confidence) of being
recoverable under existing economic and political conditions, with existing technology. Probable reserves are based on
geological and/or engineering data similar to that used in estimates of proved reserves, but technical, contractual, or regulatory
uncertainties preclude such reserves from being classified as proved. Probable reserves are attributed to known accumulations
that have a greater or equal to 50 percent confidence level of recovery.
BONTERRA | ANNUAL REPORT 2012
33
exploRatIoN aNd evalUatIoN expeNdItURes
Exploration and evaluation costs are initially capitalized with the intent to establish commercially viable reserves. Exploration and
evaluation assets include undeveloped land costs, licenses and exploration well costs. Exploration costs related to geophysical
and geological activities are immediately charged to earnings as incurred. The Company is required to make estimates and
judgments about future events and circumstances regarding the economic viability of extracting the underlying resources. The
costs are subject to technical, commercial and management review to confirm the continued intent to develop and extract the
underlying resources. Changes to project economics, resource quantities, expected production techniques, unsuccessful drilling,
expired mineral leases, production costs and required capital expenditures are important factors when making this
determination. To the extent a judgment is made that extraction of the reserves is not viable, the exploration and evaluation
costs will be impaired and charged to net earnings.
IMpaIRMeNt of NoN‑fINaNcIal assets
The recoverable amounts of Bonterra’s cash‑generating units and individual assets have been determined based on fair values
less costs to sell. This calculation requires the use of estimates and assumptions. Oil and gas prices and other assumptions will
change in the future, which may impact Bonterra’s recoverable amount calculated and may therefore require a material
adjustment to the carrying value of property and plant and equipment. Bonterra monitors internal and external indicators of
impairment relating to its exploration and evaluation assets and property, plant and equipment.
Impairment is evaluated at the cash‑generating unit (CGU) level. The determination of CGUs requires judgment in defining the
smallest identifiable group of assets that generate cash inflows that are largely independent of the cash inflows from other assets
or groups of assets. CGUs have been determined based on similar geological structure, shared infrastructure, geographical
proximity, commodity type and similar exposures to market risks.
decoMMIssIoNINg aNd RestoRatIoN costs
Decommissioning and restoration costs will be incurred by Bonterra at the end of the operating lives of Bonterra’s oil and gas
properties. The ultimate decommissioning and restoration costs are uncertain and cost estimates can vary in response to
many factors including assumptions of inflation, present value discount rates on future liabilities, changes to relevant legal
requirements and the emergence of new restoration techniques or experience at other production sites. The expected timing and
amount of expenditures can also change, for example, in response to changes in reserves or changes in laws and regulations or
their interpretation.
shaRe‑Based payMeNts
The Company accounts for share‑based payments 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. Estimating fair value
requires the determination of the most appropriate valuation model for a grant of equity instruments, which is dependent on
the terms and conditions of the grant. This also requires the determination of the most appropriate inputs to the valuation
model including the expected life of the option, risk free interest rates, volatility and dividend yield and making assumptions
about them.
defeRRed INcoMe taxes
Deferred income tax is recognized using the liability method, providing for unused tax losses, unused tax credits and temporary
differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for
taxation purposes. Deferred tax is not recognized for the following temporary differences: the initial recognition of assets and
liabilities in a transaction that is not a business combination and that affects neither accounting nor taxable profit, and
differences relating to investments in subsidiaries to the extent that they are unlikely to be reversed in the foreseeable future.
Deferred tax is measured at the tax rates that are expected to be applied to the temporary differences when they reverse,
based on the laws that have been enacted or substantively enacted by the reporting date.
34
BONTERRA | ANNUAL REPORT 2012
Bonterra recognizes the net future tax benefit related to deferred income tax assets to the extent that it is probable that the
deductible temporary differences will reverse in the foreseeable future. Assessing the recoverability of deferred income tax
assets requires Bonterra to make significant estimates related to expectations of future taxable income. Estimates of future
taxable income are based on forecasted cash flows from operations and Bonterra’s interpretation of the application of existing
tax laws. To the extent that any interpretation of tax law is challenged by the tax authorities or future cash flows and taxable
income differ significantly from estimates, the ability of Bonterra to realize the net deferred tax assets recorded at the balance
sheet date may be compromised.
fINaNcIal INstRUMeNts
The estimated fair values of financial assets and liabilities, by their very nature, are subject to measurement uncertainty due
to their exposure to credit, liquidity and market risks. Furthermore, the Company may use derivative instruments to manage
commodity price, foreign currency and interest rate exposures. The fair values of these derivatives are determined using
valuation models which require assumptions concerning the amount and timing of future cash flows and discount rates.
Management’s assumptions rely on external observable market data including quoted commodity prices and volatility,
interest rate yield curves and foreign exchange rates. The resulting fair value estimates may not be indicative of the amounts
realized or settled in current market transactions and as such are subject to measurement uncertainty.
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, 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; cash dividends;
future capital expenditures, including the amount and nature thereof; oil and natural gas prices and demand; expansion and
other development trends of the oil and gas industry; business strategy and outlook; expansion and growth of our business
and operations; and maintenance of existing customer, supplier and partner relationships; supply channels; accounting policies;
credit risks; and other such matters.
All such forward‑looking information is based on certain assumptions and analyses made by us in light of our experience and
perception of historical trends, current conditions and expected future developments, as well as other factors we believe are
appropriate in the circumstances. The risks, uncertainties, and assumptions are difficult to predict and may affect operations,
and may include, without limitation: foreign exchange fluctuations; equipment and labour shortages and inflationary costs;
general economic conditions; industry conditions; changes in applicable environmental, taxation and other laws and regulations
as well as how such laws and regulations are interpreted and enforced; the ability of oil and natural gas companies to raise
capital; the effect of weather conditions on operations and facilities; the existence of operating risks; volatility of oil and natural
gas prices; oil and gas product supply and demand; risks inherent in the ability to generate sufficient cash flow from operations
to meet current and future obligations; increased competition; stock market volatility; opportunities available to or pursued by
us; and other factors, many of which are beyond our control.
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, what benefits will be derived there from. Except as required by law, Bonterra
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 | ANNUAL REPORT 2012
35
dIsclosURe coNtRols aNd pRocedURes
Disclosure controls and procedures have been designed to ensure the information required to be disclosed by the Company is
accumulated and communicated to the Company’s management, as appropriate, to allow timely decisions regarding required
disclosures. The Company’s Chief Executive Officer (CEO) and Chief Financial Officer (CFO), together with management, have
concluded, based on their evaluation as of December 31, 2012 that the Company’s disclosure controls and procedures are
effective to provide reasonable assurance that material information related to the issuer, is made known to them by others
within the Company. It should be noted that while the Company’s CEO and CFO believe that the Company’s disclosure controls
and procedures provide a reasonable level of assurance that they are effective, they do not expect that the disclosure controls
and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how
well conceived or operated, can provide only reasonable, not absolute, assurance that the objective of the control system is met.
INteRNal coNtRol Update
The Company’s CEO and CFO are responsible for establishing and maintaining Disclosure Controls and Procedures (DC&P)
and adequate Internal Control over Financial Reporting (ICFR) to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements at December 31, 2012 for external purposes in accordance with
International Financial Reporting Standards. The control framework the Company used to design its ICFR was in accordance with
the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s CEO and CFO have evaluated,
or caused to be evaluated under their supervision, the effectiveness of the Company’s internal control over financial reporting at
December 31, 2012 of the Company and concluded that the Company’s internal control over financial reporting are effective for
the foregoing purpose.
No changes were made to the Company’s internal control over financial reporting during the year ended December 31, 2012, that
have materially affected, or are reasonably likely to materially affect, the internal control over financial reporting.
All internal control systems, no matter how well designed, have inherent limitations. These systems, therefore, provide reasonable
but not absolute assurance that financial information is accurate and complete.
fINaNcIal RepoRtINg Update
As of January 1, 2013, Bonterra will be required to adopt amendments to IAS 1 “Presentation of Financial Statements” which will
require companies to group together items within other comprehensive income that may be reclassified to the net earnings
section of the comprehensive income statement. Bonterra does not expect a material impact as a result of the amendments.
Each of the additional new standards outlined below is effective for annual periods beginning on or after January 1, 2013 with
early adoption permitted, except for IFRS 9 “Financial Instruments” which is effective for annual periods beginning on or after
January 1, 2015. The Company has not yet assessed the impact, if any, that the new amended standards will have on its financial
statements or whether to early adopt any of the new requirements.
IFRS 9 “Financial Instruments”
The result of the first phase of the IASB’s project to replace IAS 39, “Financial Instruments: Recognition and Measurement”.
The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with
a single model that has only two classification categories: amortized cost and fair value.
IFRS 10 “Consolidated Financial Statements”
Replaces Standing Interpretations Committee 12, “Consolidation ‑ Special Purpose Entities” and the consolidation requirements
of IAS 27 “Consolidated and Separate Financial Statements”. The new standard replaces the existing risk and rewards based
approaches and establish control as the determining factor when determining whether an interest in another entity should be
included in the consolidated financial statements.
36
BONTERRA | ANNUAL REPORT 2012
IFRS 11 “Joint Arrangements”
Replaces IAS 31 “Interests in Joint Ventures” along with amending IAS 28 “Investment in Associates”. IFRS 11, “Joint
Arrangements”, requires a venturer to classify its interest in a joint arrangement as a joint venture or joint operation.
Joint ventures will be accounted for using the equity method of accounting whereas for a joint operation the venturer will
recognize its share of the assets, liabilities, revenue and expenses of the joint operation. Under existing IFRS, entities have
the choice to proportionately consolidate or equity account for interests in joint ventures.
IFRS 12 “Disclosure of Interests in Other Entities”
Provides comprehensive disclosure requirements on interests in other entities, including joint arrangements, associates, and
special purpose vehicles. The new disclosure requires information that will assist financial statement users in evaluating the
nature, risks and financial effects of an entity’s interest in subsidiaries and joint arrangements.
IFRS 13 “Fair Value Measurement”
Provides a common definition of fair value within IFRS. The new standard provides measurement and disclosure guidance and
applies when IFRS requires or permits the item to be measured at fair value, with limited exceptions. This standard does not
determine when an item is measured at fair value and as such does not require new fair value measurements.
Additional information relating to the Company may be found on www.sedar.com or on our website at www.bonterraenergy.com.
BONTERRA | ANNUAL REPORT 2012
37
MANAgEMENT’s REsPONsiBiLiTy fOR
fiNANciAL sTATEMENTs
The information provided in this report, including the financial statements, is the responsibility of management. The timely
preparation of the financial statements requires that management make estimates and use judgment regarding the reported
amounts of assets and liabilities and disclosures of contingent assets and liabilities as at the date of the financial statements
and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions
and events as at the date of the financial statements. Accordingly, actual results may differ from estimated amounts as future
confirming events occur. 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 control to provide reasonable assurance that the Company’s assets are safeguarded
and to facilitate the preparation of relevant and timely information.
Deloitte LLP has been appointed by the Shareholders to serve as the Company’s external auditors. They have examined the
financial statements and provided their auditor’s report. The audit committee has reviewed these financial statements with
management and the auditors, and has reported to the Board of Directors. The Board of Directors has approved the financial
statements as presented in this annual report.
George F. Fink
Chief Executive Officer and
Chairman of the Board
Robb D. Thompson
Chief Financial Officer and
Corporate Secretary
March 21, 2013
March 21, 2013
38
BONTERRA | ANNUAL REPORT 2012
iNDEPENDENT AUDiTOR’s REPORT
to the shaReholdeRs of BoNteRRa eNeRgy coRp.
We have audited the accompanying financial statements of Bonterra Energy Corp., which comprise the statements of
financial position as at December 31, 2012 and 2011, and the statements of comprehensive income, statements of changes
in equity and statements of cash flows for the years then ended, and the notes to the financial statements.
MaNageMeNt’s RespoNsIBIlIty foR the fINaNcIal stateMeNts
Management is responsible for the preparation and fair presentation of these financial statements in accordance with
International Financial Reporting Standards, and for such internal control as management determines is necessary to enable
the preparation of financial statements that are free from material misstatement, whether due to fraud or error.
aUdItoR’s RespoNsIBIlIty
Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in
accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical
requirements and plan and perform the audit to obtain reasonable assurance about whether the financial statements are free
from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements.
The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of
the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control
relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are
appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal
control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting
estimates made by management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our
audit opinion.
opINIoN
In our opinion, the financial statements present fairly, in all material respects, the financial position of Bonterra Energy Corp. as
at December 31, 2012 and 2011, and its financial performance and its cash flows for the years then ended in accordance with
International Financial Reporting Standards.
Chartered Accountants
Calgary, Alberta
March 21, 2013
BONTERRA | ANNUAL REPORT 2012
39
fiNANciAL sTATEMENTs
stateMeNt of fINaNcIal posItIoN
As at
($ 000s)
Assets
Current
Accounts receivable
Crude oil inventory
Prepaid expenses
Investments
Investment in related party
Exploration and evaluation assets
Property, plant and equipment
Investment tax credit receivable
Deferred tax asset
Liabilities
Current
Accounts payable and accrued liabilities
Due to related parties
Subordinated promissory note
Bank debt
Decommissioning liabilities
Commitments and subsequent events
Shareholders’ equity
Share capital
Contributed surplus
Accumulated other comprehensive income
Retained earnings
See accompanying notes to these financial statements.
On behalf of the Board:
George F. Fink
Director
Bill Woodward
Director
Note
December 31,
2012
December 31,
2011
5
7
8
9
9
10
1 1
12
13
14
19, 20
15
19,158
797
1,635
4,136
25,726
910
1,982
341,452
27,670
22,193
419,933
28,602
12,000
15,000
55,602
166,808
34,246
256,656
149,877
9,167
1,620
2,613
163,277
419,933
17,094
1,092
1,688
6,266
26,140
566
1,989
274,361
27,670
33,450
364,176
30,716
32,000
15,000
77,716
69,916
34,904
182,536
142,567
5,302
2,662
31,109
181,640
364,176
40
BONTERRA | ANNUAL REPORT 2012
stateMeNt of coMpReheNsIve INcoMe
For the years ended December 31
($ 000s, except $ per share)
Revenue
Oil and gas sales, net of royalties
Other income
Expenses
Production costs
Office and administration
Employee compensation
Finance costs
Share-based payments
Depletion and depreciation
Impairment of natural gas assets
Earnings before income taxes
Deferred income taxes
Net earnings for the year
Other comprehensive income (loss)
Unrealized gains (losses) on investments
Deferred taxes on unrealized losses (gains) on investments
Realized gains on investments transferred to net earnings
Deferred taxes on realized gains on investments transferred to net earnings
Other comprehensive loss for the year
Total comprehensive income for the year
Net earnings per share – basic
Net earnings per share – diluted
Comprehensive income per share – basic
Comprehensive income per share – diluted
See accompanying notes to these financial statements.
Note
2012
2011
16
17
4
15
8
7,8
9
15
15
15
15
129,010
6,767
135,777
41,408
2,121
3,974
5,895
4,241
33,521
-
91,160
44, 617
11,406
33,211
1,514
(189)
(2,705)
338
(1,042)
32,169
1.68
1.68
1.63
1.63
144,700
2,642
147,342
36,787
2,332
4,456
4,436
2,554
32,699
2,585
85,849
61,493
17,885
43,608
(1,462)
266
(2,126)
282
(3,040)
40,568
2.25
2.23
2.10
2.07
BONTERRA | ANNUAL REPORT 2012
41
stateMeNt of cash flows
For the years ended December 31
($ 000s)
Operating activities
Earnings before income taxes
Items not affecting cash
Share-based payments
Depletion and depreciation
Impairment of natural gas assets
Unwinding of the fair value of decommissioning liabilities
Gain on sale of property
Gain on sale of investments
Investment income
Interest expense
Change in non-cash working capital
Change in accounts receivable
Change in crude oil inventory
Change in prepaid expenses
Change in accounts payable and accrued liabilities
Decommissioning expenditures
Interest paid
Cash provided by operating activities
Financing activities
Increase (decrease) in bank debt
Due to related parties
Stock option proceeds
Dividends
Cash provided by (used in) financing activities
Investing activities
Investment income received
Exploration and evaluation expenditures
Property, plant and equipment expenditures
Proceeds on sale of property
Purchase of investments
Proceeds on sale of investments
Acquisition
Change in non-cash working capital
Change in accounts payable and accrued liabilities
Change in accounts receivable
Cash used in investing activities
Net cash inflow
Cash, beginning of year
Cash, end of year
See accompanying notes to these financial statements.
Note
2012
2011
44,617
61,493
4,241
33,521
-
886
(3,616)
(2,705)
(161)
5,009
1,580
194
53
(3,743)
(542)
(5,009)
74,325
96,892
(20,000)
6,934
(61,707)
22,119
161
(182)
(84,593)
3,753
(185)
3,485
(17,108)
1,629
(3,404)
(96,444)
-
-
-
2,554
32,699
2,585
954
(162)
(2,126)
(27)
3,482
(2,313)
(417)
(57)
3,057
(831)
(3,482)
97,409
(470)
-
7,150
(58,805)
(52,125)
27
(309)
(62,615)
238
-
3,991
-
10,820
2,564
(45,284)
-
-
-
6
42
BONTERRA | ANNUAL REPORT 2012
stateMeNt of chaNges IN eqUIty
($ 000s, except number of shares outstanding)
Number of
shares
outstanding
(Note 15)
Share capital
(Note 15)
Contributed
surplus (1)
Accumulated
other
comprehensive
income (2)
Retained
earnings
Total
shareholders’
equity
January 1, 2011
Share-based payments
Exercise of options
Transfer to share capital on
exercise of options
Comprehensive income (loss)
Dividends
December 31, 2011
Share-based payments
Exercise of options
Transfer to share capital on
exercise of options
Comprehensive income (loss)
Dividends
December 31, 2012
19,219,541
135,030
351,775
7,150
3,135
2,554
387
(387)
19,571,316
142,567
338,225
6,934
5,302
4,241
5,702
46,306
(3,040)
2,662
43,608
(58,805)
31,109
376
(376)
(1,042)
19,909,541
149,877
9,167
1,620
33,211
(61,707)
2,613
190,173
2,554
7,150
-
40,568
(58,805)
181,640
4,241
6,934
-
32,169
(61,707)
163,277
(1) Contributed surplus comprises of share-based payments.
(2) Accumulated other comprehensive income comprises of unrealized gains and losses on available-for-sale investments.
See accompanying notes to these financial statements.
BONTERRA | ANNUAL REPORT 2012
43
NOTEs TO THE fiNANciAL sTATEMENTs
As at and for the years ended December 31, 2012 and 2011.
1. NatURe of BUsINess aNd segMeNt INfoRMatIoN
Bonterra Energy Corp. (Bonterra or the Company) is a public company listed on the Toronto Stock Exchange and incorporated
under the Business Corporations Act (Alberta). The address of the Company’s registered office is Suite 901, 1015‑4th Street SW,
Calgary, Alberta, Canada, T2R 1J4.
Bonterra operates in one industry and has only one reportable segment being the development and production of oil and
natural gas in the Western Canadian Sedimentary Basin.
2. BasIs of pRepaRatIoN
a) stateMeNt of coMplIaNce
These financial statements have been prepared by management in accordance with International Financial Reporting Standards
(IFRS), as issued by the International Accounting Standards Board (IASB).
The financial statements were authorized for issue by the Company’s Board of Directors on March 21, 2013.
B) chaNge IN accoUNtINg estIMate
Property, Plant and Equipment
On January 1, 2012, the Company prospectively began depleting oil and gas properties using the unit‑of‑production method
over their proved plus probable developed reserve life (Total Developed Method), a change from the unit–of‑production
method over their proved developed reserve life (Proved Developed Method). The change of estimate was due to the Total
Developed Method providing a better reflection of the estimated service life of the related assets. For 2012, the Company
recorded less depletion and depreciation of $9,692,000 under the Total Developed Method, compared to what would have
been recorded using the Proved Developed Method. The Company believes it is not practical to estimate the effect on depletion
and depreciation expense for future periods.
c) BasIs of MeasUReMeNt
These financial statements have been prepared on a historical cost basis, except for certain financial instruments and
share‑based payment transactions which are measured at fair value.
d) fUNctIoNal aNd pReseNtatIoN cURReNcy
The Company’s functional and presentation currency is the Canadian dollar.
Monetary assets and liabilities are translated into Canadian dollars at the rates prevailing on the reporting date. Non‑monetary
assets and liabilities are translated into Canadian dollars at the rates prevailing on the transaction dates. Exchange gains and
losses are recorded as income or expense in the period in which they occur.
44
BONTERRA | ANNUAL REPORT 2012
e) sIgNIfIcaNt accoUNtINg estIMates aNd JUdgMeNts
The timely preparation of financial statements 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 statement of financial
position 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.
Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in
the year in which the estimates are revised and in any future years affected. The following are the estimates and judgments
applied by management that most significantly affect the Company’s financial statements.
Exploration and Evaluation Expenditures
Exploration and evaluation costs are initially capitalized with the intent to establish commercially viable reserves. Exploration
and evaluation assets include undeveloped land and costs related to exploratory wells. The Company is required to make
estimates and judgments about future events and circumstances regarding the future economic viability of extracting the
underlying resources. Changes to project economics, resource quantities, expected production techniques, unsuccessful drilling,
expired mineral leases, production costs and required capital expenditures are important factors when making this
determination. To the extent a judgment is made, that the underlying reserves are not viable, the exploration and evaluation
costs will be impaired and charged to net earnings.
Impairment of Non-Financial Assets
Property, plant and equipment are aggregated into cash generating units (CGUs) based on their potential ability to generate
largely independent cash flows and are used for impairment assessment. CGUs have been determined based on similar
geological structure, shared infrastructure, geographical proximity, commodity type, and similar markets risks, oil and gas prices
and other assumptions will change in the future, which may impact the Company’s recoverable amounts and may therefore
require a material adjustment to the carrying value of property, plant and equipment. The determination of the Company’s CGUs
is subject to management’s judgment.
Reserves Estimation
The capitalized costs of oil and gas properties are depleted on a unit‑of‑production basis at a rate calculated by reference to
proved plus probable developed reserves determined in accordance with National Instrument 51‑101 and the Canadian Oil and
Gas Evaluation handbook. Commercial reserves are determined using best estimates of oil and gas in place, recovery factors and
future oil and gas prices. Amounts used for impairment calculations are also based on estimates of crude oil and natural gas
reserves and future costs required to develop those reserves.
Share-based Payments
The Company measures the cost of equity‑settled transactions with employees by reference to the fair value of the equity
instruments at the date they are granted. Estimating the fair value requires the determination of the most appropriate valuation
model for a grant, which is dependent on the terms and conditions of the grant. This also requires the determination of the most
appropriate inputs to the valuation model including the expected life of the option, risk free interest rates, volatility and
dividend yield.
Decommissioning and Restoration Costs
Decommissioning and restoration costs will be incurred by the Company at the end of the operating lives of the Company’s oil
and gas properties. Provisions for decommissioning liabilities are uncertain and cost estimates can vary in response to many
factors including timing of abandonment, inflation, change in legal requirements, new restoration techniques and interest rates.
BONTERRA | ANNUAL REPORT 2012
45
Income Taxes
The Company recognizes the net future tax benefit related to deferred income tax assets to the extent that it is probable that the
deductible temporary differences will reverse in the foreseeable future. Assessing the recoverability of deferred tax assets and
investment tax credit receivable requires the Company to make significant estimates related to expectations of future taxable
income. The provision for income taxes is based on judgments in applying income tax law and estimates of the timing, likelihood
and reversal of temporary differences between the accounting and tax basis of assets and liabilities. The ability to realize on the
deferred tax assets and investment tax credit receivable recorded on the balance sheet may be compromised to the extent that
any interpretation of tax law is challenged or taxable income differs significantly from estimates.
Further details regarding accounting estimates and judgments are discussed in Note 3.
f) ReceNt accoUNtINg pRoNoUNceMeNts
As of January 1, 2013, Bonterra will be required to adopt amendments to IAS 1 “Presentation of Financial Statements” which
will require companies to group together items within other comprehensive income that may be reclassified to the net earnings
section of the statement of comprehensive income. Bonterra does not expect a material impact as a result of the amendments.
Each of the additional new standards outlined below is effective for annual periods beginning on or after January 1, 2013 with
early adoption permitted, except for IFRS 9 “Financial Instruments” which is effective for annual periods beginning on or after
January 1, 2015. The Company has not yet assessed the impact, if any, that the new amended standards will have on its financial
statements or whether to early adopt any of the new requirements.
IFRS 9 “Financial Instruments”
The result of the first phase of the IASB’s project to replace IAS 39, “Financial Instruments: Recognition and Measurement”.
The new standard replaces the current multiple classification and measurement models for financial assets and liabilities
with a single model that has only two classification categories: amortized cost and fair value.
IFRS 10 “Consolidated Financial Statements”
Replaces Standing Interpretations Committee 12, “Consolidation ‑ Special Purpose Entities” and the consolidation requirements
of IAS 27 “Consolidated and Separate Financial Statements”. The new standard replaces the existing risk and rewards based
approaches and establish control as the determining factor when determining whether an interest in another entity should be
included in the consolidated financial statements.
IFRS 11 “Joint Arrangements”
Replaces IAS 31 “Interests in Joint Ventures” along with amending IAS 28 “Investment in Associates”. IFRS 11,
“Joint Arrangements,” requires a venturer to classify its interest in a joint arrangement as a joint venture or joint operation.
Joint ventures will be accounted for using the equity method of accounting whereas for a joint operation the venturer will
recognize its share of the assets, liabilities, revenue and expenses of the joint operation. Under existing IFRS, entities have
the choice to proportionately consolidate or equity account for interests in joint ventures.
IFRS 12 “Disclosure of Interests in Other Entities”
Provides comprehensive disclosure requirements on interests in other entities, including joint arrangements, associates, and
special purpose vehicles. The new disclosure requires information that will assist financial statement users in evaluating the
nature, risks and financial effects of an entity’s interest in subsidiaries and joint arrangements.
IFRS 13 “Fair Value Measurement”
Provides a common definition of fair value within IFRS. The new standard provides measurement and disclosure guidance and
applies when IFRS requires or permits the item to be measured at fair value, with limited exceptions. This standard does not
determine when an item is measured at fair value and as such does not require new fair value measurements.
46
BONTERRA | ANNUAL REPORT 2012
3. sIgNIfIcaNt accoUNtINg polIcIes
a) ReveNUe RecogNItIoN
Revenues from the sale of petroleum and natural gas are recorded when the significant risks and rewards of ownership have
been transferred to the customer. This generally occurs when the product is physically transferred into a third‑party pipeline or
when the delivery truck arrives at a customer’s receiving location. Items such as royalties from crown, freehold, gross overriding
(GORR) and Saskatchewan surcharge are netted against revenue. These items are netted to reflect the deduction for other
parties’ proportionate share of the revenue.
Administration fee income is recorded when management services and office administration are provided (see related parties
disclosure Note 11 and Note 17).
B) JoINtly coNtRolled opeRatIoNs
Certain exploration, development and production activities are conducted jointly with others. These financial statements reflect
only the Company’s interests in such activities. A jointly controlled operation involves the use of assets and other resources of
the Company and those of other venturers rather than through the establishment of a corporation, partnership or other entity.
The Company has no interests in jointly controlled entities. The Company recognizes in its financial statements the interest
in assets that it owns, the liabilities and expenses that it incurs and its share of income earned by the joint venture through
proportionate consolidation. The Company has no material individual capital commitments in any joint venture interest or
in any joint venture.
c) INveNtoRIes
Inventories consist of crude oil. Crude oil stored in the Company’s tanks is 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, depletion and depreciation for the period and net realizable value is determined based on estimated sales price less
transportation costs.
d) INvestMeNts aNd INvestMeNt IN Related paRty
Investments and investment in related party consist of equity securities classified on initial recognition as available‑for‑sale and
are carried at fair value. Fair value is determined by multiplying the period end trading price of the investments by the number
of common shares held as at period end. Unrealized holding gains and losses are recognized in other comprehensive income.
Net gains and losses arising on disposal are recognized in net earnings.
e) exploRatIoN aNd evalUatIoN assets
General exploration or evaluation (E&E) expenditures incurred prior to acquiring the legal right to explore are charged to
expense as incurred.
E&E expenditures represent undeveloped land costs, licenses and exploration well costs.
Undeveloped land costs, licenses and exploration well costs are initially capitalized and, if subsequently determined to have not
found sufficient reserves to justify commercial production, are charged to expense. E&E assets continue to be capitalized as long
as sufficient progress is being made to assess the reserves and economic viability of the asset. Once technical feasibility and
commercial viability has been established, E&E assets are transferred to property, plant and equipment (PP&E). E&E assets are
assessed for impairment either annually, upon transfer to PP&E assets or whenever indications of impairment exist to ensure
they are not carried above their recoverable amounts.
BONTERRA | ANNUAL REPORT 2012
47
f) pRopeRty, plaNt aNd eqUIpMeNt
PP&E assets include transferred‑in E&E costs, development drilling and other subsurface expenditures. PP&E assets are carried
at cost less depletion and depreciation of all development expenditures and include all other expenditures associated with
PP&E assets.
When commercial production in an area has commenced, PP&E properties, excluding surface costs are depleted using the
unit‑of‑production method over their total developed reserve life. Total developed reserves are determined annually by qualified
independent reserve engineers. Changes in factors such as estimates of total developed reserves that affect unit‑of‑production
calculations are accounted for on a prospective basis. Surface costs such as production facilities and furniture, fixtures and other
equipment are depreciated over their estimated useful lives.
Oil and Gas Properties
The initial cost of an asset is comprised of its purchase price or construction cost, including expenditures such as drilling costs,
the present value of the initial and changes in the estimate of any decommissioning obligation associated with the asset and
finance charges on qualifying assets, that are directly attributable to bringing the asset into operation and to its present location.
Production Facilities
Production facilities are comprised of costs related to petroleum and natural gas plant and production equipment.
Depletion and Depreciation
Depletion and depreciation is recognized in the statement of comprehensive income. Production facilities, furniture, fixtures
and other equipment are depreciated over the individual assets’ estimated economic lives.
These assets are depreciated on a declining balance method as follows:
Production facilities
Furniture, fixtures and other equipment
10 percent per year
10 percent to 20 percent per year
g) IMpaIRMeNt of assets
Impairment of Financial Assets
A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect
on the estimated future cash flows of that asset. An impairment loss in respect of a financial asset measured at amortized cost
is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted
at the original effective interest rate. Individually significant financial assets are tested for impairment on an individual basis.
The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics. An impairment
loss in respect of an available‑for‑sale financial asset is calculated by reference to its current fair value.
All impairment losses are recognized in net earnings. An impairment loss is reversed if there is an indicator that the impairment
reversal can be related objectively to an event occurring after the impairment loss was recognized. Any subsequent recovery of
an impairment loss in respect of an investment in an equity instrument classified as available‑for‑sale is reversed through other
comprehensive income instead of net earnings. For financial assets measured at amortized cost, the reversal is recognized in
net earnings.
48
BONTERRA | ANNUAL REPORT 2012
Impairment of Non-Financial Assets
The carrying amounts of the Company’s non‑financial assets are reviewed at the end of each reporting period to determine whether
there is any indication of impairment. If such indication exists, then the assets’ carrying amounts are assessed for impairment.
For the purpose of impairment testing, assets (which include E&E and PP&E assets) are grouped together into the smallest group
of assets that generates cash flows from continuing use that are largely independent of the cash flows of other assets or groups
of assets (the cash‑generating unit or CGU). The recoverable amount of an asset or a CGU is the greater of its value‑in‑use (VIU)
and its fair value less costs to sell (FVLCS).
An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its recoverable amount. Impairment
losses are recognized in the statement of comprehensive income. Impairment losses recognized in respect of a CGU are allocated
first to reduce the carrying amount of any goodwill allocated to the CGU and then to reduce the carrying amount of the other
assets of the CGU on a pro‑rata basis.
An impairment loss in respect of goodwill cannot be reversed. In respect of other assets, impairment losses recognized in prior
periods are assessed at each reporting date for any indications that the loss has decreased or no longer exists. If the amount of
the impairment loss decreases in a subsequent period and the decrease can be objectively related to an event occurring after the
impairment was recognized, the impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed
the carrying amount that would have been determined, net of depletion and depreciation, if no impairment loss had
been recognized.
h) decoMMIssIoNINg lIaBIlItIes
The fair value of the statutory, contractual, constructive or legal liabilities associated with the retirement and reclamation of oil
and gas properties is recorded when incurred, with a corresponding increase to the carrying amount of the related PP&E. The
amount recognized is the estimated cost of decommissioning, discounted to its present value using the Company’s risk free rate.
Changes in the estimated timing of decommissioning or decommissioning cost estimates and changes to the risk free rates are
dealt with prospectively by recording an adjustment to the provision, and a corresponding adjustment to property, plant and
equipment. The unwinding of the discount on the decommissioning provision is charged to net earnings as a finance cost.
The Company recognizes a decommissioning liability 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 and if there are any, they will be
applied prospectively. The fair value of the estimated provision 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
proved plus probable developed reserves. The liability amount is increased each reporting period due to the passage of time and
this amount is charged to earnings in the period. Actual costs incurred upon settlement of the obligations are charged against
the provision to the extent of the liability recorded and the remaining balance of the actual costs is recorded in the statement
of comprehensive income.
I)
INcoMe taxes
Tax expense comprises current and deferred taxes. Tax is recognized in the statement of comprehensive income or directly
in equity.
Current tax expense is based on the results for the period as adjusted for items that are not taxable or not deductible.
Current tax is calculated using tax rates and laws that are substantively enacted at the end of the reporting period.
Management periodically evaluates positions taken in tax returns with respect to situations in which applicable tax regulation
is subject to interpretation. Provisions are established where appropriate on the basis of amounts expected to be paid to the
tax authorities.
Deferred tax is recognized using the liability method, providing for unused tax losses, unused tax credits and temporary
differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for
taxation purposes. Deferred tax is not recognized for the following temporary differences: the initial recognition of assets
and liabilities in a transaction that is not a business combination and that affects neither accounting nor taxable profit, and
differences relating to investments in subsidiaries to the extent that they are unlikely to be reversed in the foreseeable future.
BONTERRA | ANNUAL REPORT 2012
49
Deferred tax is measured at the tax rates that are expected to be applied to the temporary differences when they reverse,
based on the laws that have been enacted or substantively enacted by the reporting date.
A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which
unused tax losses, unused tax credits and temporary differences can be utilized. Deferred tax assets are reviewed at each
balance date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.
The amount and timing of reversals of temporary differences will also depend on the Company’s future operating results, and
acquisitions and dispositions of assets and liabilities. A significant change in any of the preceding assumptions could materially
affect the Company’s estimate of the deferred income tax asset.
J) shaRe‑Based payMeNts
The Company accounts for share‑based payments 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. Share‑based payments
are recognized through the statement of comprehensive income over the vesting period with a corresponding amount reflected
in contributed surplus in equity. For awards issued in tranches that vest at different times, the fair value of each tranche is
recognized over its respective vesting period.
At the grant date and at the end of each reporting period, the Company assesses and re‑assesses for subsequent periods its
estimates of the number of awards that are expected to vest and recognizes the impact of the revisions in the statement of
comprehensive income. Upon exercise of share‑based options, the proceeds received net of any transaction costs and the fair
value of the exercised share‑based options is credited to share capital.
K) 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: fair‑value through profit or loss, loans and receivables, held‑to‑maturity investments, available‑for‑sale
financial assets and financial liabilities at amortized cost.
Subsequent measurement of financial instruments is based on their initial classification. Fair‑value through profit or loss financial
instruments are measured at fair value and changes in fair value are recognized in the statement of comprehensive income.
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.
Cash and restricted cash are classified as fair‑value through profit and loss. Accounts receivable are classified as loans and
receivables which are measured at amortized cost. Investments are classified as available‑for‑sale which is measured at fair
value and any gains or losses are recognized in other comprehensive income in the period they occur. Accounts payable and
accrued liabilities, bank debt, subordinated promissory note and amounts due to related parties are classified as financial
liabilities at amortized cost.
Bank debt, subordinated promissory note and due to related parties are classified as current liabilities unless the Company
has an unconditional right to defer settlement of the liability for at least 12 months after the reporting date.
50
BONTERRA | ANNUAL REPORT 2012
l) 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 net 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, 2012 and December 31, 2011, the Company did not designate any of its financial
instruments as hedges. There were no risk management contracts outstanding as at December 31, 2012 and December 31, 2011.
M) Net eaRNINgs aNd coMpReheNsIve INcoMe peR shaRe
Per share amounts are calculated by dividing the net earnings or comprehensive income attributable to common shareholders
of the Company by the weighted average number of common shares outstanding during the reporting period.
Diluted per share amounts are calculated similar to basic per share amounts except that the weighted average common shares
outstanding are increased to include additional common shares from the assumed exercise of dilutive share options. The number
of additional outstanding common shares is calculated by assuming that the outstanding in‑the‑money share options were
exercised and that the proceeds from such exercises were used to acquire common shares at the average market price during
the reporting period.
4. fINaNce costs
A breakdown of finance costs for the current and previous year is:
($ 000s)
Interest expense on bank debt
Interest expense on amounts owing to related parties
Interest expense on subordinated promissory note and other
Unwinding of the fair value of decommissioning liabilities
Total
5. INvestMeNt IN Related paRty
December 31,
2012
December 31,
2011
3,730
683
596
886
5,895
2,272
760
450
954
4,436
On October 19, 2012, Pine Cliff Energy Ltd. (Pine Cliff), a company with some common directors and some common management
with Bonterra, acquired 100 percent of the issued and outstanding common shares of Geomark Exploration Ltd. (Geomark),
pursuant to an arrangement agreement. Geomark became a wholly‑owned subsidiary of Pine Cliff and its shares were delisted
from the TSX Venture Exchange on October 22, 2012. Consideration for each Geomark Share was 1.5 voting common shares of
Pine Cliff. Bonterra now holds 1,034,523 common shares in Pine Cliff (December 31, 2011 – 689,682 common shares in Geomark)
which represents 0.7 percent ownership in Pine Cliff’s outstanding common shares. The investment in Pine Cliff is recorded at fair
market value.
In addition, Geomark owns 204,633 (December 31, 2011 – 204,633) common shares in Bonterra.
BONTERRA | ANNUAL REPORT 2012
51
6. acqUIsItIoN
On June 7, 2012, Bonterra acquired oil and natural gas assets in the Willesden Green area of Alberta for cash consideration of
$17,108,000. The results of the Willesden Green oil and gas assets have been included in the financial statements since that date.
The Willesden Green oil and gas assets contributed oil and gas sales, net of royalties, of $1,785,000 and operating expenses of
$688,000 for the period from June 7, 2012 to December 31, 2012. If the acquisition had occurred on January 1, 2012, total oil
and gas sales, net of royalties, would have been approximately $3,416,000 and total operating expenses would have been
approximately $1,163,000 for the year ended December 31, 2012.
The acquisition has been accounted for using the acquisition method and the purchase price was allocated to the assets acquired
and the liabilities assumed as follows:
Net assets acquired
Property, plant and equipment
Decommissioning liabilities
Working capital
Total
Consideration:
Cash
Total purchase price
7. exploRatIoN aNd evalUatIoN assets
($ 000s)
Cost and carrying amount
Balance at January 1, 2011
Additions
Transfers to property, plant and equipment
Impairment (Note 8)
Balance at December 31, 2011
Additions
Transfers to property, plant and equipment
Balance at December 31, 2012
($ 000s)
19,603
(2,735)
240
17,108
17,108
17,108
E&E assets
4,595
309
(2,001)
(914)
1,989
182
(189)
1,982
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BONTERRA | ANNUAL REPORT 2012
8. pRopeRty, plaNt aNd eqUIpMeNt
Cost
($ 000s)
Oil and gas
properties
Production
facilities
Balance at January 1, 2011
Additions
Transfers from exploration and evaluation assets
Disposal
Balance at December 31, 2011
Additions
Transfers from exploration and evaluation assets
Acquisition
Disposal
Balance at December 31, 2012
283,484
58,874
2,001
(166)
344,193
67,003
189
16,117
(261)
427,241
62,728
15,019
-
(136)
77,611
13,931
-
3,486
(126)
94,902
Accumulated Depletion and Depreciation
($ 000s)
Oil and gas
properties
Production
facilities
Balance at January 1, 2011
Depletion and depreciation
Disposal and other
Impairment
Balance at December 31, 2011
Depletion and depreciation
Disposal and other
Balance at December 31, 2012
Carrying amounts as at:
($ 000s)
December 31, 2011
December 31, 2012
(88,297)
(27,435)
(5)
(784)
(116,521)
(27,187)
101
(143,607)
(25,265)
(5,181)
44
(887)
(31,289)
(6,232)
-
(37,521)
Furniture,
fixtures
& other
equipment
Total property,
plant &
equipment
1,474
77
-
(41)
1,510
183
-
(32)
1,661
347,686
73,970
2,001
(343)
423,314
81,117
189
19,603
(419)
523,804
Furniture,
fixtures
& other
equipment
Total property,
plant &
equipment
(1,098)
(83)
38
-
(1,143)
(102)
21
(1,224)
(114,660)
(32,699)
77
(1,671)
(148,953)
(33,521)
122
(182,352)
227,672
283,634
46,322
57,381
367
437
274,361
341,452
In January 2012, the Company disposed of its Central Alberta Redwater property. The proceeds of disposition was cash of
$1,109,000. At the time of disposition, the property had no carrying value resulting in a gain on sale equal to its proceeds.
In June 2012, the Company disposed of a portion of its Central Alberta Tomahawk property. The proceeds of disposition was cash
of $2,500,000. At the time of disposition, the property had no carrying value resulting in a gain on sale equal to its proceeds.
BONTERRA | ANNUAL REPORT 2012
53
IMpaIRMeNt
Management has determined four cash generating units for the Company, which are comprised of one core cash‑generating
unit (CGU) for the Pembina Cardium and Willesden Green assets in Alberta, Canada and three other non‑core CGUs.
These CGUs are the Company’s producing fields. As part of its annual impairment analysis, the Company assessed its PP&E
assets, production facilities, furniture and other equipment by CGU for possible impairment.
The assessment for impairment has been determined based on the value‑in‑use (VIU) method. VIU was determined on the
basis of the discounted expected future cash flows based on the Company’s plans to continue to produce total proved and
probable reserves.
Projected estimates of cash flows from the CGUs have been determined based on the economic life of the reserves using an
inflation rate of 1.5 percent (2011 ‑ 2.0 percent). The pre‑tax discount rate applied to the cash flows for the Company’s total
proved and probable assets is 10 percent (2011 – proved and probable developed assets was 10 percent and probable
undeveloped assets was 15 percent).
There were no impairment provisions recorded for the year ended December 31, 2012. In 2011, there were significant reductions
in the future commodity price forecasts for natural gas used by the Company’s independent reserves evaluator when compared
to the previous year resulting in an impairment provision of $2,585,000 for minor natural gas assets in British Columbia.
9. INcoMe taxes
($ 000s)
Deferred tax asset (liability) related to:
Investments
Exploration and evaluation assets and property, plant and equipment
Decommissioning liabilities
Corporate tax losses and SR&ED claims
Corporate capital tax loss
Unrecorded benefit of capital tax losses
Deferred tax asset
December 31,
2012
December 31,
2011
(302)
(34,856)
8,575
48,474
16,964
(16,662)
22,193
(308)
(27,354)
8,737
52,067
17,212
(16,904)
33,450
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 taxes
Combined federal and provincial income tax rates
Income tax provision calculated using statutory tax rates
Increase (decrease) in taxes resulting from:
Share-based payments
Non-taxable portion of realized gains
Unrecorded benefit of capital tax losses
Recorded benefit (expense) in other comprehensive income
Change in effective tax rate
Others
Deferred income tax expense
December 31,
2012
December 31,
2011
44,617
25.04%
11,172
1,062
(381)
(242)
(189)
11
(27)
11,406
61,493
26.53%
16,314
677
(300)
31
266
789
108
17,885
54
BONTERRA | ANNUAL REPORT 2012
The Company has the following tax pools, which may be used to reduce taxable income in future years, limited to the applicable
rates of utilization:
($ 000s)
Undepreciated capital costs
Eligible capital expenditures
Canadian oil and gas property expenditures
Canadian development expenditures
Canadian exploration expenditures
Income tax losses carried forward (1)
Rate of
Utilization (%)
20-100
7
10
30
100
100
Amount
39,200
5,924
25,114
121,417
11,174
221,272
424,101
(1)
Federal income tax losses carried forward expire in the following years; 2024 - $1,501,000, 2025 - $7,532,000, 2026 - $46,671,000, 2027 - $117,189,000,
2028 - $35,248,000, 2029 - $13,131,000.
The Company has $27,670,000 (December 31, 2011 ‑ $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 $135,502,000 (December 31, 2011 ‑ $137,289,000) of capital loss carry forwards which can only be
claimed against taxable capital gains.
10. accoUNts payaBle aNd accRUed lIaBIlItIes
Total accounts payable and accrued liabilities comprise of the following categories:
($ 000s)
Accounts payable
Accrued liabilities
December 31,
2012
December 31,
2011
20,181
8,421
28,602
25,890
4,826
30,716
11. tRaNsactIoNs wIth Related paRtIes
As at December 31, 2012, the Company’s CEO, Chairman of the Board and major shareholder has loaned the Company
$12,000,000 (December 31, 2011 ‑ $12,000,000). The loan bears interest at Canadian chartered bank prime less 5/8th of
a percent and has no set repayment terms but is payable on demand. Security under the debenture is over all of the
Company’s assets and is subordinated to any and all claims in favour of the syndicate of senior lenders providing credit
facilities to the Company. Interest paid on this loan during the year was $286,000 (December 31, 2011 ‑ $285,000).
On November 9, 2012, Bonterra repaid the $20,000,000 (December 31, 2011 ‑ $20,000,000) loan with Geomark. Interest paid
on this loan during the year was $397,000 (December 31, 2011 ‑ $475,000).
The Company received a management fee from Geomark of $225,000 for the year (December 31, 2011 ‑ $270,000) for
management services and office administration. This fee has been included in other income. With the arrangement agreement
between Pine Cliff and Geomark, the management agreement between Bonterra and Geomark was terminated effective
October 19, 2012.
The Company received a management fee of $60,000 for the year ended December 31, 2012 (December 31, 2011 ‑ $60,000)
for management services and office administration from Pine Cliff. This fee has been included in other income. As at
December 31, 2012, the Company had an account receivable from Pine Cliff of $45,000 (December 31, 2011 ‑ $4,000).
BONTERRA | ANNUAL REPORT 2012
55
coMpeNsatIoN foR Key MaNageMeNt peRsoNNel
($ 000s)
Compensation
Share-based payments
Total compensation
December 31,
2012
December 31,
2011
1,529
2,445
3,974
1,352
1,289
2,641
Key management personnel are those persons, including all directors, having authority and responsibility for planning,
directing and controlling the activities of the Company.
12. sUBoRdINated pRoMIssoRy Note
As at December 31, 2012, Bonterra has borrowed $15,000,000 (December 31, 2011 ‑ $15,000,000) from a private investor, in
exchange for a Subordinated Promissory Note. The terms of the Subordinated Promissory Note are that it bears interest at
three percent and is payable after thirty days written notice by either party. Security consists of a floating demand debenture
totaling $15,000,000 over all of the Company’s assets and is subordinated to any and all claims in favor of the syndicate of
senior lenders providing credit facilities to the Company. Interest paid on the subordinated promissory note during the year
was $451,000 (December 31, 2011 ‑ $450,000).
The Company’s bank agreement requires that the above loan can only be repaid should the Company have sufficient available
borrowing limits under the Company’s credit facility.
13.
BaNK deBt
As at December 31, 2012, the Company has a bank facility consisting of $160,000,000 syndicated revolving credit facility
and a $20,000,000 non‑syndicated revolving credit facility. Amounts drawn under the facilities at December 31, 2012 were
$166,808,000 (December 31, 2011 ‑ $69,916,000). Amounts borrowed under the credit facilities at December 31, 2012 bear
interest at a floating rate based on the applicable Canadian prime rate, which is presently three percent or Banker’s Acceptance
rate, plus between 0.75 percent and 3.50 percent, depending on the type of borrowing and the Company’s consolidated total
funded debt to consolidated cash flow. The terms of the revolving credit facilities provided that the loan is revolving to April
25, 2013 and with a maturity date of April 25, 2014 and is subject to annual review. The revolving credit facilities have no fixed
terms of repayment.
The amount available for borrowing under the credit facilities is reduced by outstanding letters of credit. Letters of credit totaling
$400,000 were issued as at December 31, 2012 (December 31, 2011 ‑ $400,000). Security for credit facilities consists of various
and floating demand debentures totaling $300,000,000 over all of the Company’s assets and a general security agreement with
first ranking over all personal and real property.
The following is a list of the material covenants on the banking facility:
• The Company is required to not exceed $180,000,000 in consolidated debt (includes working capital but excludes amounts
due to related parties and subordinated promissory note).
• Dividends paid in the current quarter shall not exceed 80 percent of the average available cash flow for the preceding four
fiscal quarters.
Available cash flow is defined to be cash provided by operating activities excluding gains on sale of property and investments,
the change in non‑cash working capital and decommissioning liabilities settled and including all net proceeds of dispositions
included in cash used in investing activities. At December 31, 2012, the Company is in compliance with all covenants.
56
BONTERRA | ANNUAL REPORT 2012
14. decoMMIssIoNINg lIaBIlItIes
At December 31, 2012, the estimated total undiscounted amount required to settle the decommissioning liabilities was
$67,684,000 (December 31, 2011 ‑ $73,475,000). The provision has been calculated assuming a 1.5 percent inflation rate
(December 31, 2011 – 2.0 percent inflation rate). These obligations will be settled based on the useful lives of the underlying
assets, which extend up to 54 years into the future. This amount has been discounted using a risk‑free interest rate of
2.4 percent (December 31, 2011 ‑ 2.5 percent).
Changes to decommissioning liabilities were as follows:
($ 000s)
Decommissioning liabilities, January 1
Adjustment to decommissioning liabilities
Acquistion
Disposals
Liabilities settled during the period
Unwinding of the fair value of decommissioning liabilities
Decommissioning liabilities, end of year
15.
shaReholdeRs’ eqUIty
aUthoRIzed
December 31,
2012
December 31,
2011
34,904
(3,477)
2,735
(260)
(542)
886
34,246
23,427
11,354
-
-
(831)
954
34,904
The Company is authorized to issue an unlimited number of common shares without nominal or par value.
December 31, 2012
December 31, 2011
Issued and fully paid – common shares
Balance, beginning of year
Issued pursuant to the Company share option plan
Transfer from contributed surplus to share capital
Balance, end of year
Number
19,571,316
338,225
19,909,541
Amount
($ 000s)
142,567
6,934
376
149,877
Number
19,219,541
351,775
19,571,316
Amount
($ 000s)
135,030
7,150
387
142,567
The Company is authorized to issue an unlimited number of Class “A” redeemable Preferred Shares and an unlimited number of
Class “B” Preferred Shares. There are currently no outstanding Class “A” redeemable Preferred Shares or Class “B”
Preferred Shares.
The weighted average common shares used to calculate basic and diluted net earnings per share for the years ended
December 31 is as follows:
Basic shares outstanding
Dilutive effect of share options (1)
Diluted shares outstanding
2012
19,780,814
13,120
19,793,934
2011
19,341,514
212,643
19,554,157
(1)
The Company did not include 1,215,000 share options (December 31, 2011 – 599,000) in the dilutive effect of share options calculation as these share options
were anti-dilutive.
For the year ended December 31, 2012, the Company declared and paid dividends of $61,707,000 ($3.12 per share)
(December 31, 2011 ‑ $58,805,000 ($3.04 per share)).
The Company provides an equity settled option plan for its directors, officers, employees and consultants. Under the plan, the
Company may grant options for up to 1,990,954 (December 31, 2011 – 1,957,131) common shares. The exercise price of each option
granted cannot be lower than the market price of the common shares on the date of grant and the option’s maximum term is
five years.
BONTERRA | ANNUAL REPORT 2012
57
A summary of the status of the Company’s stock option plan as of December 31, 2012, and changes during the year ended on
those dates is presented below:
At January 1, 2011
Options granted
Options exercised
Options cancelled
Options forfeited
At December 31, 2011
Options granted
Options exercised
Options cancelled
Options forfeited
At December 31, 2012
Number of
options
747,000
1,142,000
(351,775)
(11,000)
(58,000)
1,468,225
942,000
(338,225)
(18,000)
(152,000)
1,902,000
Weighted-
average
exercise price
$20.56
54.54
20.32
14.90
32.14
$46.63
45.38
20.50
51.61
54.07
$49.99
The following table summarizes information about options outstanding at December 31, 2012:
Options Outstanding
Options Exercisable
Number
outstanding at
December 31,
2012
855,000
1,047,000
1,902,000
Weighted-average
remaining
contractual life
Weighted-average
exercise price
1.8 years
2.4 years
2.1 years
$44.61
54.38
$49.99
Number
exercisable at
December 31,
2012
6,000
442,500
448,500
Weighted-average
exercise price
$48.60
57.96
$57.83
Range of exercise
prices
$ 40.00 – $ 49.00
50.00 – 59.00
$ 40.00 – $ 59.00
The Company records compensation expense over the vesting period, which ranges between one to three years, based on the
fair value of options granted to employees, directors and consultants. In 2012, the Company granted 942,000 stock options
(December 31, 2011 – 1,142,000) with an estimated fair value of $3,814,000 or $4.05 per option (December 31, 2011 ‑ $8,394,000
or $7.35 per option) using the Black‑Scholes option pricing model with the following key assumptions:
Weighted-average risk free interest rate (%) (1)
Expected life (years)
Weighted-average volatility (%) (2)
Forfeiture rate (%)
Weighted average dividend yield
December 31,
2012
December 31,
2011
1.12
1.42
28.23
-
6.90
1.40
2.03
32.41
-
5.53
(1)
Risk-free interest rate is based on the weighted average Government of Canada benchmark bond yields for one, two, and three year terms to match
corresponding vesting periods.
(2) The expected volatility is measured as the standard deviation of expected share price returns based on statistical analysis of historical weekly share prices for a
representative period.
The weighted average share price of the options exercised in 2012 was $49.17 (2011 ‑ $53.38).
58
BONTERRA | ANNUAL REPORT 2012
December 31,
2012
December 31,
2011
142,770
162,277
(9,727)
(4,033)
129,010
(12,316)
(5,261)
144,700
December 31,
2012
December 31,
2011
161
285
3,616
2,705
6,767
27
327
162
2,126
2,642
16. oIl aNd gas sales, Net of RoyaltIes
($ 000s)
Oil and gas sales
Less:
Crown royalties
Freehold, gross overriding royalties and other
Oil and gas sales, net of royalties
17. otheR INcoMe
($ 000s)
Investment income
Administrative income
Gain on sale of property
Realized gain on investments
Other income
18. fINaNcIal aNd capItal RIsK MaNageMeNt
fINaNcIal RIsK factoRs
The Company undertakes transactions in a range of financial instruments including:
• Accounts receivable
• Accounts payable and accrued liabilities
• Common share investments
• Due to related parties
• Bank debt
• Subordinated promissory note
The Company’s activities result in exposure to a number of financial risks including market risk (commodity price risk, interest
rate risk, and foreign exchange risk), credit risk, liquidity risk and equity price 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 is managed by senior management under the direction of the Board of Directors.
The Company may enter into various risk management contracts 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 a capital structure that provides a low 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 | ANNUAL REPORT 2012
59
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. During the current year the Company exceeded the targeted debt level due to decreasing commodity prices,
the Willesden Green asset acquisition, an increased capital drilling program, while sustaining current dividend levels. On
January 25, 2013, the Company completed a business acquisition of Spartan Oil Corp. which is expected to increase cash flows,
restore targeted debt levels to less than 1.5:1 on an annual basis, and increase its holding in its core area, the Pembina and
Willesden Green Cardium properties (see Note 20).
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 the table below.
($ 000s)
Financial assets
Accounts receivable
Investments
Investments in related party
Financial liabilities
Accounts payable and accrued
liabilities
Due to related parties
Subordinated promissory note
Bank debt
As at December 31, 2012
As at December 31, 2011
Carrying
value
Fair
value
Face
value
Carrying
value
Fair
value
Face
value
19,158
4,136
910
19,158
4,136
910
19,389
N/A
N/A
17,094
6,266
566
17,094
6,266
566
17,136
N/A
N/A
28,602
12,000
15,000
166,808
28,602
12,000
15,000
166,808
28,602
12,000
15,000
166,808
30,716
32,000
15,000
69,916
30,716
32,000
15,000
69,916
30,716
32,000
15,000
69,916
Financial instruments consisting of accounts receivable, accounts payable and accrued liabilities, due to related parties,
subordinated promissory note and bank debt on the statement of financial position are carried at amortized cost. Investments
and investments in related party are carried at fair value. All of the fair value items are transacted in active markets.
Bonterra classifies the fair value of these transactions according to the following hierarchy based on the amount of observable
inputs used to value the instrument.
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets
are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly
or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for
commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.
Level 3 – Valuations in this level are those with inputs for the asset or liability that are not based on observable market data.
Bonterra’s investments and investments in related party have been assessed on the fair value hierarchy described above and
are all considered Level 1.
60
BONTERRA | ANNUAL REPORT 2012
The net debt and cash flow figures as of December 31, 2012 are as follows:
($ 000s)
Bank debt
Accounts payable and accrued liabilities
Due to related parties
Subordinated promissory note
Current assets
Net debt
Cash flow from operations
Net debt to annual cash flow from operations
B) RIsKs aNd MItIgatIoNs
166,808
28,602
12,000
15,000
(25,726)
196,684
74,325
2.65
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, including fluctuations in the differential between West Texas Intermediate prices and Bonterra’s
realized prices, directly impact the Company’s performance and ability to continue with its dividends.
The Company has used various risk management contracts to set price parameters for a portion of its production. Management,
in agreement with the Board of Directors, decided that at least in the near term it will discontinue the use of commodity price
agreements. The Company will assume full risk in respect of commodity prices.
Interest Rate Risk
Interest rate risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument will
fluctuate due to changes in market interest rates. Interest rate risk arises from interest bearing financial assets and liabilities that
the Company uses. The principal exposure of the Company is on its borrowings which have a variable interest rate which gives
rise to a cash flow interest rate risk.
The Company’s debt facilities consist of a $160,000,000 syndicated revolving operating line, $20,000,000 non‑syndicated
operating line, $12,000,000 due to a related party and a $15,000,000 subordinated promissory note. The borrowings under
these facilities, except for the subordinated promissory note, are at bank prime plus or minus various percentages as well as by
means of banker’s acceptances (BAs) within the Company’s credit facility. The subordinated promissory note is at a fixed interest
rate of three percent. The Company manages its exposure to interest rate risk on its floating interest rate debt through
entering into various term lengths on its BAs but in no circumstances do the terms exceed six months.
Sensitivity Analysis
Based on historic movements and volatilities in the interest rate markets and management’s current assessment of the financial
markets, the Company believes that a one percent variation in the Canadian prime interest rate is reasonably possible over a
12‑month period.
A one percent increase (decrease) in the Canadian prime rate would decrease (increase) both annual net earnings and
comprehensive income by $1,340,000.
Equity Price Risk
Equity price risk refers to the risk that the fair value of the investments and investment in related party will fluctuate due to
changes in equity markets. Equity price risk arises from the realizable value of the investments that the Company holds which
are subject to variable equity market prices which on disposition gives rise to a cash flow equity price risk. The Company will
assume full risk in respect of equity price fluctuations.
BONTERRA | ANNUAL REPORT 2012
61
Foreign Exchange Risk
The Company has no foreign operations and currently sells all of 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 not use 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 statement
of financial position. To help mitigate this risk:
• The Company only enters into material agreements with credit worthy counterparties. These include major oil and gas
companies or major Canadian chartered banks; and
• Agreements for product sales are primarily on 30 day renewal terms.
Of the $19,158,000 accounts receivable balance at December 31, 2012 (December 31, 2011 ‑ $17,094,000) over 60 percent
(2011 – 70 percent) relates to product sales with international oil and gas companies and from the provincial government
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, 2012, there was no material impairment provision required on any of the financial assets of the Company due to
historical success of realizing financial assets. The Company does have a credit risk exposure as the majority of the Company’s
accounts receivable is 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, 2012, approximately $1,330,000 or 6.9 percent of the Company’s total accounts receivable are aged over
90 days and considered past due. The majority of these accounts are due from various joint venture partners. The Company
actively monitors past due accounts and takes the necessary actions to expedite collection, which can include withholding
production or netting payables when the accounts are with joint venture partners. Should the Company determine that the
ultimate collection of a receivable is in doubt, it will provide the necessary provision in its allowance for doubtful accounts with
a corresponding charge to earnings. If the Company subsequently determines an account is uncollectable, the account is written
off with a corresponding charge to the allowance account. The Company’s allowance for doubtful accounts balance at
December 31, 2012 is $231,000 (December 31, 2011 ‑ $42,000) with the difference being included in general and administrative
expenses. There were no material accounts written off during the period.
The maximum exposure to credit risk is represented by the carrying amounts of accounts receivable, accounts payable and
accrued liabilities and the continuing availability of subordinated promissory note, due to related parties and bank debt on
the statement of financial position. There are no material financial assets that the Company considers past due.
Liquidity Risk
Liquidity risk includes the risk that, as a result of the Company’s operational liquidity requirements:
• The Company will not have sufficient funds to settle a transaction on the due date;
• The Company will not have sufficient funds to continue with its dividends;
• The Company will be forced to sell assets at a value which is less than what they are worth; or
• The Company may be unable to settle or recover a financial asset at all.
To help reduce these risks the Company:
• Maintains a portfolio of high‑quality, long reserve life oil and gas assets.
62
BONTERRA | ANNUAL REPORT 2012
The Company has the following maturity schedule for its financial liabilities:
($ 000s)
Accounts payable and accrued liabilities
Due to related parties
Subordinated promissory note
Bank debt
Office leases
Total
Recognized
on financial
statements
Yes - Liability
Yes - Liability
Yes - Liability
Yes - Liability
No
Less than 1
year
Over 1 year to
3 years
4 to 5 years
28,602
12,000
15,000
-
538
56,140
-
-
-
166,808
28
166,836
-
-
-
-
-
-
c) RIsK MaNageMeNt coNtRacts
The Company has no outstanding risk management contracts at December 31, 2012.
19. coMMItMeNts
opeRatINg leases
The Company has entered into leases for buildings and office equipment. These leases have an average life of 0.7 years. There
are no restrictions placed upon the lessee by entering into these leases. Future minimum lease payments under non‑cancellable
operating leases as at December 31, 2012 are as follows:
($ 000s)
Within one year
After one year but not more than five years
Total
20. sUBseqUeNt eveNts
I) acqUIsItIoN
2012
538
28
566
On January 25, 2013, Bonterra acquired 100 percent of the issued and outstanding common shares of Spartan Oil Corp. (Spartan)
pursuant to an arrangement agreement (Spartan Transaction). Spartan was a public oil and gas company with properties in
Alberta and Saskatchewan. The acquisition of Spartan, including the complementary light oil assets in Bonterra’s core area of
the Pembina and Willesden Green Cardium properties, will contribute increased cash flows, controlled infrastructure, positive
working capital and no debt which positively affects the Company’s net debt to cash flow ratio. Consideration for Spartan shares
was 0.1169 voting common shares of Bonterra, which amounted to the issuance of 10,711,405 Bonterra shares valued at
$502,258,000, using the closing share price of $46.89 per share on the date of the Spartan Transaction. The exchange ratio
for the transaction represents a deemed price of $5.03 per Spartan Share. The Spartan Transaction will be accounted for as a
business combination with Bonterra identified as the acquirer.
BONTERRA | ANNUAL REPORT 2012
63
The preliminary purchase price allocation using the acquisition method was allocated to the assets acquired and the liabilities
assumed as follows:
Net assets acquired:
Exploration and evaluation assets
Property, plant and equipment
Goodwill
Working capital
Decommissioning liabilities
Deferred tax liability
Total
Consideration:
Bonterra shares (10,711,405 shares at $46.89)
Total purchase price
($ 000s)
8,829
462,269
98,369
10,685
(11,657)
(66,237)
502,258
502,258
502,258
The purchase price allocation is subject to change as of the issue date of these financial statements. Bonterra does not believe it
is practical to estimate the effect on net earnings for future periods. On March 1, 2013, Spartan was amalgamated with Bonterra.
II) dIvIdeNds
Subsequent to December 31, 2012, the Company has declared the following dividends:
Date declared
January 3, 2013
February 4, 2013
March 4, 2013
III) BaNK facIlIty
Record date
$ per share
Date payable
January 15, 2013
February 15, 2013
March 15, 2013
0.26
January 31, 2012
0.26 February 28, 2013
March 28, 2013
0.28
The Company’s banking syndicate have provided approvals in connection with the annual redetermination of the borrowing base,
subject to normal closing conditions. Management expects that on or around March 28, 2013, the Company will amend its bank
facilities under similar terms and conditions with exception of extending the revolving period and maturity date, and increasing
the total syndicated and non‑syndicated credit facilities to $250 million from $180 million. In addition, security for the credit
facilities, consisting of various and floating demand debentures, will increase to $400 million from $300 million.
64
BONTERRA | ANNUAL REPORT 2012
cORPORATE iNfORMATiON
BoaRd of dIRectoRs
stocK lIstINg
G.J. Drummond, Nassau, Bahamas
The Toronto Stock Exchange
G.F. Fink, Calgary, Alberta
R.M. Jarock, Calgary, Alberta
C.R. Jonsson, Vancouver, British Columbia
F.W. Woodward, Calgary, Alberta
offIceRs
Trading Symbol: BNE
head offIce
901, 1015 – 4th Street SW
Calgary, Alberta T2R 1J4
PH 403.262.5307
B.A. Curtis – Vice President, Business Development
FX 403.265.7488
G.F. Fink – Chief Executive Officer and Chairman of the Board
A. Neumann – Vice President, Engineering and Operations
R.D. Thompson – Chief Financial Officer and Secretary
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www.bonterraenergy.com
RegIstRaR & tRaNsfeR ageNt
Olympia Trust Company, Calgary, Alberta
aUdItoRs
Deloitte LLP, Calgary, Alberta
solIcItoRs
Borden Ladner Gervais LLP, Calgary, Alberta
BaNKeRs
CIBC, Calgary, Alberta
Alberta Treasury Branch, Calgary, Alberta
National Bank of Canada, Calgary, Alberta
BONTERRA | ANNUAL REPORT 2012
65
901, 1015 – 4th Street SW
Calgary, Alberta T2R 1J4
www.BoNteRRaeNeRgy.coM