Efficient.
Sustainable.
Disciplined.
BONTERRA ENERGY CORP. 2015 ANNUAL REPORT
1
BONTERRA ANNUAL REPORT 2015
Efficient. Sustainable. Disciplined.
BONTERRA ENERGY CORP. IS A DIVIDEND-PAYING, CONVENTIONAL OIL AND GAS COMPANY
FOCUSED ON GROWING FUNDS FLOW, PRODUCTION AND RESERVES ON A PER SHARE BASIS.
THE COMPANY’S HIGH QUALITY ASSET BASE, CONSERVATIVE FINANCIAL MANAGEMENT AND
STRONG CAPITAL EFFICIENCIES POSITION BONTERRA FOR LONG-TERM SUSTAINABILITY
ACROSS A VARIETY OF COMMODITY PRICE CYCLES.
HIGH QUALITY ASSETS
Bonterra’s assets are concentrated in the Pembina Cardium, a well-
delineated, low-risk reservoir containing an estimated 10.6 billion barrels
of oil in place with less than 13% produced to date. As one of the area’s
largest operators, Bonterra has over 200 net sections of land and over
20 years of drilling inventory including 230+ net booked and 770+ net
identified low-risk locations. Access to infrastructure supports high
netback, low-decline, and light oil production growth.
Low Production
Decline
18%
DRIVING DOWN WELL COSTS
Per well capital costs to drill, complete and tie-in (DC&T) were lowered in
2015 by approximately 27% through a combination of increased technology,
pad drilling and lower industry cost structure. Bonterra’s improved
operational efficiencies contributed to significant structural cost reductions
that can be maintained through future cost fluctuations. Further, increased
collaboration on frac design and reservoir simulations enabled the Company
to streamline drilling and completion techniques while building important
intellectual capital that supports enhanced efficiencies going forward.
DC&T Costs
27%
IMPROVED GAS TRANSPORTATION
increased
in 2015, Bonterra
Late
its firm transportation service
commitments from 30% previously to 90% going forward, which
greatly improves access to markets. The importance of consistent
and reliable infrastructure was demonstrated during 2015 as Bonterra
experienced production impacts caused by non-operated facility and
transportation issues.
90%
Natural Gas Production
on Firm Transportation
ANNUAL HIGHLIGHTS ___________________________________________ 2
QUARTERLY HIGHLIGHTS _______________________________________ 3
MESSAGE TO SHAREHOLDERS __________________________________ 4
OPERATIONS ____________________________________________________ 6
STATISTICAL REVIEW ___________________________________________ 8
MANAGEMENT’S DISCUSSION AND ANALYSIS __________________11
FINANCIAL STATEMENTS ______________________________________ 28
NOTES TO THE FINANCIAL STATEMENTS ______________________ 32
CORPORATE INFORMATION ____________________________________ 49
REDUCED OPERATING COSTS
Bonterra successfully reduced 2015 operating expenses (opex) per BOE by
approximately 14% over 2014 through a combination of field optimizations
leading to reduced well maintenance, more efficient produced-water
handling and decreased chemical costs. The Company will continue to
control expenses and seek opportunities for further opex reductions through
reduced trucking, waterflood support and lower labour costs.
2015 OPEX
14%
to $11.95 per BOE
FINANCIAL FLEXIBILITY SUPPORTS GROWTH
Bonterra continues to explore ways to enhance recoveries and reduce
costs through the use of technology and increased well density, and
will prudently allocate capital to opportunities offering the best results
and highest economic returns. Maintaining financial flexibility enables
Bonterra to grow production and reduce debt, while positioning the
Company to increase capital spending, dividends or a combination of the
two when commodity prices stabilize at higher levels.
P+P RESERVES GROWTH
(mmboe)
RESERVES PER SHARE
(proved + probable reserves)
90.6
80.3
75.0
41.1 45.0
100
80
60
40
20
0
3.0
2.5
2.0
1.5
1.0
0.5
0.0
2.78
2.47 2.50
2.28
2.13
2011
2012
2013
2014
2015
2011
2012
2013
2014
2015
BONTERRA ANNUAL REPORT 2015
1
ANNUAL HIGHLIGHTS
As at and for the year ended ($ 000s except $ per share)
FINANCIAL
Revenue – realized oil and gas sales
Funds flow(5)
Per share – basic
Per share – diluted
Payout ratio
Cash flow from operations
Per share – basic
Per share – diluted
Payout ratio
Cash dividends per share
Earnings before income taxes
Net earnings (loss)
Per share – basic
Per share – diluted
Capital expenditures, net of dispositions
Acquisition
Total assets
Working capital deficiency
Long-term debt
Shareholders’ equity
OPERATIONS
Oil
– bbl per day
– average price ($ per bbl)
NGLs
– bbl per day
– average price ($ per bbl)
Natural gas – mcf per day
– average price ($ per mcf)
Total barrels of oil equivalent (BOE) per day(6)
DECEMBER 31,
2015(1)
December 31,
2014
December 31,
2013(3)
197,239
117,948
3.61
3.61
54%
339,694
209,665
6.57
6.54
54%
295,675
181,574
6.01
5.99
55%
107,871
222,353
173,896
3.30
3.30
59%
1.95
1,982
(9,080)
(0.28)
(0.28)
58,498
170,430(2)
6.97
6.94
51%
3.54
109,593
38,761
1.21
1.21
155,565
-
5.76
5.74
58%
3.33
84,782
62,758
2.08
2.07
119,227
502,258(4)
1,183,593
1,042,938
1,000,531
29,804
332,471
595,805
8,641
54.08
733
20.80
19,694
2.94
12,656
53,642
154,723
635,198
8,582
90.61
807
52.26
22,833
4.86
13,195
35,985
156,764
667,641
7,787
89.26
744
52.41
21,954
3.46
12,190
(1) Annual figures for 2015 include the results of a purchase (the Acquisition) of primarily Pembina Cardium oil and gas assets (Pembina Assets) for the period of
April 15, 2015 to December 31, 2015. For the year ended December 31, 2015, production includes 260 days for the Pembina Assets and 365 days for the original
Bonterra assets.
(2) Represents the Acquisition that closed April 15, 2015 for $170,430,000.
(3) Annual figures for 2013 include the results of a corporate acquisition for the period of January 25, 2013 to December 31, 2013. For the year ended December 31,
2013, production includes 341 days for the corporate acquisition and 365 days for the original Bonterra assets.
(4) Represents a plan of arrangement, where Bonterra completed a corporate acquisition. The Company issued 10,711,405 common shares valued at $502,258,000
which included $10,000,000 of acquired cash.
(5) Funds flow is not a recognized measure under IFRS. For these purposes, the Company defines funds flow as funds provided by operations including proceeds from
sale of investments and investment income received excluding the effects of changes in non-cash working capital items and decommissioning
expenditures settled.
(6) BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 MCF: 1 bbl is based on an energy conversion method primarily applicable at the
burner tip and does not represent a value equivalency at the wellhead.
2
BONTERRA ANNUAL REPORT 2015
QUARTERLY HIGHLIGHTS
As at and for the periods ended ($ 000s except $ per share)
Q4
2015
Q3
Q2(1)
Q1
FINANCIAL
Revenue – realized oil and gas sales
Funds flow(2)
Per share – basic
Per share – diluted
Payout ratio
44,678
24,046
0.71
0.71
62%
52,160
28,754
0.87
0.87
52%
57,921
43,058
1.34
1.34
34%
42,480
22,090
0.69
0.69
87%
Cash flow from operations
27,808
36,024
17,960
26,079
Per share – basic
Per share – diluted
Payout ratio
Cash dividends per share
Earnings (loss) before income taxes
Net earnings (loss)
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
– bbl per day
– average price ($ per bbl)
NGLs
– bbl per day
– average price ($ per bbl)
Natural gas – mcf per day
– average price ($ per mcf)
Total barrels of oil equivalent (BOE) per day(5)
0.84
0.84
56%
0.45
(5,223)
(4,113)
(0.13)
(0.13)
8,384
1.09
1.09
41%
0.45
746
(321)
(0.01)
(0.01)
14,402
0.56
0.56
81%
0.45
8,676
(2,711)
(0.08)
0.81
0.81
74%
0.60
(2,217)
(1,935)
(0.06)
(0.08)
167,182(3)
(0.06)
38,960(4)
1,183,593
1,200,856
1,225,291
1,072,534
29,804
332,471
595,805
8,424
49.50
710
21.49
20,423
2.61
12,538
29,080
335,863
610,793
9,177
53.26
753
18.05
19,191
3.36
13,129
27,558
361,430
599,911
8,823
64.27
677
21.35
19,452
2.83
12,743
37,633
207,217
613,886
8,128
48.70
791
22.36
19,709
2.97
12,204
(1) Quarterly figures for Q2 2015 include the results of a purchase (the Acquisition) of primarily Pembina Cardium oil and gas assets (Pembina Assets) for the period of
April 15, 2015 to December 31, 2015. Production includes 76 days for the Pembina Assets and 91 days for the original Bonterra assets.
(2) 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 and decommissioning
expenditures settled.
(3) Includes $153,230,000 (less a deposit of $17,200,000) for the Acquisition that closed on April 15, 2015 and capital expenditures of $13,952,000.
(4) Includes a deposit of $17,200,000 for the Acquisition and capital expenditures of $21,760,000.
(5) 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.
BONTERRA ANNUAL REPORT 2015
3
MESSAGE TO SHAREHOLDERS
BONTERRA ENERGY CORP. (BONTERRA OR THE COMPANY) CONTINUED TO REALIZE
FINANCIAL AND OPERATIONAL SUCCESS THROUGH 2015 DESPITE AN EXTREMELY
CHALLENGING COMMODITY PRICE ENVIRONMENT. WHILE GLOBAL COMMODITY PRICES ARE
OUT OF THE COMPANY’S CONTROL, BONTERRA CHOSE TO FOCUS ON FACTORS THAT IT IS
ABLE TO MANAGE TO ENSURE FINANCIAL FLEXIBILITY, FUTURE GROWTH AND LONG-TERM
CORPORATE SUSTAINABILITY.
Bonterra focused on several areas in 2015, including:
• Cost Reductions: Bonterra has always maintained a
low cost structure, and was especially successful with
cost reduction efforts in 2015. The all-in corporate costs
of approximately Cdn$20.00 per BOE including royalties,
operating expense (including transportation costs),
administrative expense and interest on long-term debt is one
of the lowest in the industry. This reflects a reduction in per
BOE production costs by 14% and administrative costs by
32% from the same period one year ago. In 2016, Bonterra
will seek further reductions in capital for drilling, completions
and infrastructure costs, for operating costs and for general
and administrative expenses.
• Capital Efficiencies: Bonterra successfully reduced per
well capital costs by 27% in 2015, through a combination of
pad drilling from sites with existing infrastructure, general
service cost reductions, fewer drilling days per well and better
efficiencies in the field. New drilling and completions practices
were advanced as a result of the Company’s work on optimal
frac design and assessment of horizontal lateral lengths.
• Managing Financial Flexibility: Bonterra’s current net debt
is higher than previous years which is an area of concern for
the Company. It is presently at approximately 3.1 to 1.0
times net debt to funds flow on a four quarter trailing basis,
resulting from a strategic acquisition. The Company’s goal
is to reduce this ratio in the future to a range of 1.5 to 1.0
times when commodity prices have recovered or 2.5 to 1.0
times during periods when commodity prices remain low.
• Access to Infrastructure: The importance of consistent and
reliable infrastructure was demonstrated during 2015 as
Bonterra experienced production impacts caused by non-
operated facility and transportation issues. Bonterra’s firm
service commitments have increased from 30% to 90% in 2015
and greatly improved its access to markets going forward.
• Future Growth Potential: Bonterra has one of the largest
inventories of economic undrilled locations amongst its peer
group with an estimated 20 years of undrilled locations in
inventory. If commodity prices continue to be low and fewer
wells are drilled annually, this economic undrilled location
inventory increases to approximately 30 years, offering
substantial future growth potential.
• Conservative Business Approach: The Company continues
to be cautious and conservative regarding the determination
of future reserves bookings. With only approximately 30%
of its undrilled well locations included in the reserves
evaluation, Bonterra has positioned the Company well to
capture future upside.
• Balance Sheet Protection: Bonterra has a history of
protecting long-term shareholder returns and demonstrated
this again in 2015. In addition to cost reduction initiatives
4
BONTERRA ANNUAL REPORT 2015
PRODUCTION/RESERVES PER SHARE
0.16
0.14
0.12
0.10
0.08
0.06
0.04
0.02
0.00
2.13
2.28
2.47
2.50
2.78
0.119
0.124
0.147
0.150
0.139
2011
2012
2013
2014
2015
3.0
2.5
2.0
1.5
1.0
0.5
0.0
Production per Share
P+P Reserves per Share
“In 2015, Bonterra’s proved plus
probable reserves per share grew
11%, and its reserve life index
was approximately 20 years.”
in the current weak price environment, Bonterra also
reduced the monthly dividend to balance spending with
funds flow and to protect its balance sheet. This will
ensure the Company can positively respond should there
be a sustained improvement in commodity prices. With
increased funds flow, the Company will increase the
capital program, reduce debt, increase dividends or some
combination thereof. This will continue to be analyzed on a
month to month basis.
• Maximizing Asset Value: In 2015, Bonterra piloted its first
waterfloods in two areas in Carnwood with two horizontal
water injection wells. The waterfloods are still early-staged,
but the initial results are encouraging. Future waterflood
expansion may improve recoveries of the large amount of
remaining oil in place in the Pembina Cardium field, resulting
in greater long-term value creation for shareholders.
OUTLOOK
For 2016, Bonterra’s initial capital expenditures budget is set at
approximately $40 million but capital spending will be reviewed
by the Company on a monthly basis. With this level of capital,
Bonterra estimates 2016 production will average approximately
12,500 BOE per day. Further cost reductions and improved
capital efficiencies through pad drilling and new completions
technologies will be pursued. With a low corporate decline
rate, minimal capital is required to hold production volumes
flat and if needed, Bonterra can reduce capital further until
prices improve. The large inventory of economic drill locations
supports substantial production growth when commodity
prices are high while still generating positive returns through
periods of weak commodity prices.
Following its review of Alberta’s royalty structure, the Alberta
Provincial Government released its proposed Modernized
Royalty Framework (MRF) on January 29, 2016, which is
scheduled to take effect January 1, 2017. With limited details,
the future impact of the review is presently impossible to
assess. The Government and the resource
industry are
continuing to negotiate and further details are scheduled to be
released by the end of March 2016. Until full details of the MRF
are released, Bonterra cannot confirm what impact this will
have on the Company. As more information becomes available,
the Company will be able to better assess and provide details
for its shareholders.
The Company will continue pursuing its sustainable growth
strategy by minimizing the amount of debt and managing
its dividend in a responsible manner. Bonterra will continue
to focus on operational efficiencies, financial discipline,
and optimal returns for shareholders, independent of the
weaker commodity prices and provincial and federal political
uncertainty. The future for Bonterra remains positive over the
long term as the Company will continue to be conservatively
managed to effectively withstand future challenging commodity
price environments.
The Board of Directors wishes to thank the employees for their
contribution and Bonterra’s shareholders for their continued
support during these very difficult times.
GEORGE F. FINK
Chief Executive Officer and Chairman of the Board
BONTERRA ANNUAL REPORT 2015
5
OPERATIONS
BONTERRA IS FOCUSED ON THE SUSTAINABLE DEVELOPMENT OF ITS ASSET BASE THROUGH
A DISCIPLINED PACE OF DEVELOPMENT AND EFFICIENT OPERATING PRACTICES. THE COMPANY
HAS A HIGH-QUALITY LAND BASE CONCENTRATED IN THE LARGE PEMBINA CARDIUM OIL POOL
WITH YEARS OF DRILLING INVENTORY AND UPSIDE POTENTIAL. A LOW PRODUCTION DECLINE
RATE AND CONSERVATIVE FINANCIAL MANAGEMENT SUPPORT BONTERRA’S ATTRACTIVE
DIVIDEND-PLUS-GROWTH MODEL.
EFFICIENT
DRILLING ADVANCEMENTS
Bonterra drove down capital costs per well while improving
recoveries through pad drilling, increased well spacing density
and being a pioneer of a sliding sleeve completion technology
across its Cardium acreage. A significant portion of the cost
reductions are structural in nature, meaning Bonterra can
continue to realize savings when commodity prices improve.
Operating costs per BOE have also been reduced through a
combination of field optimization and reductions in service
company rates. Bonterra’s firm transportation arrangements
for natural gas increased to 90% commencing in late 2015
and provide more consistent access to markets and reduced
production disruptions.
SUSTAINABLE
Bonterra’s assets are concentrated in the Pembina Cardium pool
in central Alberta, one of Canada’s largest oil fields characterized
by low-risk drilling opportunities, stable production rates and high-
quality light oil. To date, less than 13% of the estimated 10.6 billion
barrels of oil in place has been produced, which offers significant
long-term development potential. The Company has a very
low production decline rate and its conservative 2015 reserves
booking does not fully reflect improvements in well performance
from enhanced completions. Bonterra’s low P+P Finding and
Development (F&D) costs(1) of $3.12 per BOE generated a strong
recycle ratio of 8.9 times. Bonterra’s booked reserves currently
represent only 30% of its internally estimated inventory of future
undrilled locations supporting long-term sustainability.
DISCIPLINED
Exercising conservative financial management and preserving
balance sheet strength remain key priorities in Bonterra’s disciplined
approach. With ongoing weakness in commodity prices, Bonterra
continues to assess its results monthly and set the monthly
dividend level based on the prior month’s actual funds flow. This
disciplined approach affords greater flexibility to adjust spending
allocated to capital, dividends and debt reduction and enhances
Bonterra’s ability to deliver attractive returns to shareholders.
Bonterra continues to seek ways to add incremental production,
including through the implementation of a waterflood program
in Carnwood, as well as increasing drilling density to expand our
inventory of future well locations. Bonterra has over 20 years of
drilling opportunities, not including any targets in the Belly River
or other deeper zones in the Pembina field, nor any potential from
our Saskatchewan or British Columbia lands. In addition, we
fully transitioned to cased-hole versus open-hole packers for our
completions in 2015 which allows for pinpointed frac placement.
As a result of the advances in completion technology coupled
with horizontal, multi-well pad drilling, our capital efficiencies
have improved.
R 14
R 13
R 12
R 11
R 10
R 2
R 1W 5
R 8
R 7
R 6
R 9
R 4
R 5
R 3
T 53
T 52
T 51
T 50
T 49
T 48
T 47
T 46
T 45
T 44
T 43
T 42
T 41
T 40
T 39
T 38
Bonterra Cardium Lands
T 53
T 52
T 51
T 50
T 49
T 48
T 47
T 46
T 45
T 44
T 43
T 42
T 41
T 40
T 39
T 38
R 14
R 13
R 12
R 11
R 10
R 9
R 8
R 7
R 6
R 5
R 4
R 3
R 2
R 1W 5
(1) Including change in future development capital.
6
BONTERRA ANNUAL REPORT 2015
770+
Bonterra has a strong position
in the Pembina Cardium
with net identified
low-risk drilling locations
to support long-term
production growth
CORPORATE
DECLINE RATE
18%
Enhanced completion
techniques with increased
frac stages and sliding sleeve
technology improves
capital efficiencies
12,500
boe/d
2016e production
CAPITAL
EFFICIENCIES
$13,300
per boe/d
In 2015, Bonterra piloted its first waterflood in Carnwood with a
positive production response. The waterflood can be expanded field-wide
over time to increase the ultimate oil recovery from the pool.
BONTERRA ANNUAL REPORT 2015
7
STATISTICAL REVIEW
SUMMARY OF GROSS OIL AND GAS RESERVES AS OF DECEMBER 31, 2015
PROVED
Developed Producing
Developed Non-producing
Undeveloped
TOTAL PROVED
PROBABLE
TOTAL PROVED + PROBABLE(1) (2) (3)
Light &
Medium
Crude Oil
Associated &
Non-Associated
Gas
Natural Gas
Liquids
Oil equivalent(4)
Future
Development
Capital
(MBbl)
(MMcf)
(MBbl)
(MBOE)
(000s)
26,276
1,293
19,467
47,036
12,522
59,558
57,900
7,685
45,587
111,172
34,957
146,128
2,693
239
2,186
5,118
1,590
6,708
38,619
2,813
29,251
70,683
19,938
90,621
$
$
$
$
$
$
-
2,219
495,571
497,792
20,753
518,544
(1) Reserves have been presented on gross basis which are the Company’s total working interest share before the deduction of any royalties and without including any
royalty interests of the Company.
(2) Totals may not add due to rounding.
(3) Based on Sproule’s December 31, 2015 escalated price deck.
(4) Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil.
RECONCILIATION OF COMPANY GROSS RESERVES BY PRINCIPAL PRODUCT TYPE AS OF DECEMBER 31, 2015(1) (2)
Light & Medium Crude Oil
Proved +
Probable
Proved
(MBbl)
(MBbl)
Associated &
Non-Associated Gas
Proved +
Probable
Natural Gas Liquids
Proved +
Probable
Proved
(MMcf)
(MBbl)
(MBbl)
Oil Equivalent
Proved
(MBOE)
Proved +
Probable
(MBOE)
Proved
(MMcf)
Opening Balance,
December 31, 2014
Extensions & Improved
Recovery(2)
Technical Revisions
Discoveries
Acquisitions
Dispositions(4)
Economic Factors
Production
CLOSING BALANCE,
DECEMBER 31, 2015
40,529
51,719
108,128
138,887
4,245
5,381
62,795
80,248
1,480
215
-
1,864
(1,366)
-
8,665
11,186
(119)
(592)
(150)
(553)
(3,142)
(3,142)
3,171
3,989
-
9,077
(176)
(5,870)
(7,146)
4,012
1,341
-
11,988
(220)
(2,733)
(7,146)
123
640
-
565
(6)
(182)
(266)
156
763
-
749
(8)
(68)
(266)
2,132
1,520
-
2,688
(379)
-
10,743
13,934
(154)
(1,752)
(4,599)
(194)
(1,077)
(4,599)
47,036
59,558
111,172
146,128
5,118
6,708
70,684
90,621
(1) Gross Reserves means the Company’s working interest reserves before calculation of royalties, and before consideration of the Company’s royalty interests.
(2) Increases to Extensions & Improved Recovery include infill drilling.
(3) Totals may not add due to rounding.
(4) Includes volumes associated with Farm outs.
8
BONTERRA ANNUAL REPORT 2015
SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEMBER 31, 2015
($M)
Reserves Category
PROVED
Developed Producing
Developed Non-producing
Undeveloped
TOTAL PROVED
PROBABLE
TOTAL PROVED + PROBABLE(1) (2) (3)
Net Present Value Before Income Taxes Discounted at (% per Year)
0%
5%
10%
15%
1,444,628
64,757
815,905
2,325,289
921,885
3,247,175
960,825
45,010
472,671
1,478,506
487,963
1,966,469
713,773
33,355
295,647
1,042,775
321,798
1,364,573
567,804
25,984
192,317
786,105
238,564
1,024,669
(1) Evaluated by Sproule as at December 31, 2015. Net present value of future net revenue does not represent fair value of the reserves.
(2) Net present values equals net present value before income taxes based on Sproule’s forecast prices and costs as of December 31, 2015. There is no assurance that
the forecast price and cost assumptions will be attained and variances could be material.
(3) Includes abandonment and reclamation costs as defined in NI 51-101.
FINDING, DEVELOPMENT & ACQUISITION (FD&A) AND FINDING & DEVELOPMENT (F&D) COSTS
Proved Reserve Net Additions
Proved + Probable Reserve Net Additions
2015
2014
2013
3 Yr Avg(4)
2015
2014
2013
3 Yr Avg(4)
FD&A COSTS PER BOE(1) (2) (3)
Including FDC
Excluding FDC
F&D COSTS PER BOE(1) (2) (3)
Including FDC
Excluding FDC
$
$
$
$
11.52 $
18.90 $
24.80 $
20.02
15.50 $
11.57 $
23.63 $
18.48
4.76 $
18.89 $
21.38 $
18.57
33.26 $
11.53 $
17.10 $
14.99
$
$
$
$
11.60 $
22.67 $
21.06 $
18.95
15.29 $
15.54 $
20.12 $
18.13
3.12 $
22.71 $
18.63 $
19.92
56.32 $
15.53 $
14.66 $
17.37
(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 and F&D 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 + Probable reserves on a weighted
average basis.
COMMODITY PRICES USED IN THE ABOVE CALCULATIONS OF RESERVES ARE AS FOLLOWS:
Edmonton
Par Price
Natural Gas
AECO-C Spot
Butanes
Edmonton
Pentanes
Edmonton
Operating Cost
Inflation Rate
Exchange
Rate
($Cdn per bbl)
($Cdn per mmbtu)
($Cdn per bbl)
($Cdn per bbl)
(% per Yr)
($US/$Cdn)
FORECAST
2016
2017
2018
2019
2020
2021
55.20
69.00
78.43
89.41
91.71
93.08
2.25
2.95
3.42
3.91
4.20
4.28
39.09
51.43
58.46
66.64
68.35
69.38
59.10
73.88
83.98
95.73
98.19
99.66
0.0
0.0
1.5
1.5
1.5
1.5
0.750
0.800
0.830
0.850
0.850
0.850
BONTERRA ANNUAL REPORT 2015
9
PRODUCTION
Alberta
Saskatchewan
British Columbia
LAND HOLDINGS
Alberta
Saskatchewan
British Columbia
OILS & NGLS
(BBL PER DAY)
2015
NATURAL GAS
(MCF PER DAY)
TOTAL
(BOE PER DAY)
9,244
120
10
9,374
19,013
12,413
184
498
150
93
19,694
12,656
2015
2014
GROSS ACRES
NET ACRES
Gross Acres
296,684
8,891
62,045
367,620
179,503
6,200
22,639
208,342
245,263
9,576
62,045
316,884
Net Acres
150,835
6,509
22,639
179,983
PETROLEUM AND NATURAL GAS EXPENDITURES
The following table summarizes petroleum and natural gas capital expenditures incurred by Bonterra on acquisitions, land, and
exploration and development costs for the years ended December 31:
($ 000s)
Land
Acquisitions
Dispositions
Exploration and development costs
Net petroleum and natural gas capital expenditures
DRILLING HISTORY
The following tables summarize Bonterra’s gross and net drilling activity and success:
2015
479
170,430
-
58,019
228,928
2014
402
-
(1,152)
155,262
154,512
Crude oil
Natural gas
Total
Success rate
Crude oil
Natural gas
Total
Success rate
2015
DEVELOPMENT
EXPLORATORY
TOTAL
GROSS
26.0
-
26.0
100%
NET
17.5
-
17.5
100%
GROSS
NET
GROSS
-
-
-
-
-
-
-
-
26.0
-
26.0
100%
Development
Gross
65.0
-
65.0
100%
Net
47.5
-
47.5
100%
2014
Exploratory
Gross
Net
-
-
-
-
-
-
-
-
Total
Gross
65.0
-
65.0
100%
NET
17.5
-
17.5
100%
Net
47.5
-
47.5
100%
10
BONTERRA ANNUAL REPORT 2015
MANAGEMENT’S DISCUSSION AND ANALYSIS
The following report dated March 17, 2016 is a review of the operations and current financial position for the year ended
December 31, 2015 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 as a percentage 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: “WTI” refers to West Texas Intermediate, a grade of light
sweet crude oil used as benchmark pricing in the United States; “MSW Stream Index” or “Edmonton Par” refers to the mixed sweet
blend that is the benchmark price for conventionally produced light sweet crude oil in Western Canada; “bbl” refers to barrel; “NGL”
refers to natural gas liquids; “MCF” refers to thousand cubic feet; “MMBTU” refers to million British Thermal Units; 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 2015
11
ANNUAL COMPARISONS
As at and for the year ended ($ 000s except $ per share)
FINANCIAL
Revenue – realized oil and gas sales
Cash flow from operations
Per share – basic
Per share – diluted
Payout ratio
Cash dividends per share
Net earnings (loss)
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
– average price ($ per barrel)
NGLs
– barrels per day
– average price ($ per barrel)
Natural gas – MCF per day
– average price ($ per MCF)
Total barrels of oil equivalent per day (BOE)
DECEMBER 31,
2015(1)
December 31,
2014
December 31,
2013(3)
197,239
107,871
3.30
3.30
59%
1.95
(9,080)
(0.28)
(0.28)
228,928(2)
1,183,593
29,804
332,471
595,805
8,641
54.08
733
20.80
19,694
2.94
12,656
339,694
222,353
6.97
6.94
51%
3.54
38,761
1.21
1.21
155,565
1,042,938
53,642
154,723
635,198
8,582
90.61
807
52.26
22,833
4.86
13,195
295,675
173,896
5.76
5.74
58%
3.33
62,758
2.08
2.07
621,485(4)
1,000,531
35,985
156,764
667,641
7,787
89.26
744
52.41
21,954
3.46
12,190
(1) Annual figures for 2015 include the results of a purchase (the Acquisition) of primarily Pembina Cardium oil and gas assets (Pembina Assets) for the period of April
15, 2015 to December 31, 2015. Production includes 260 days for the Pembina Assets and 365 days for the original Bonterra assets.
(2) Represents the Acquisition that closed April 15, 2015 for $170,430,000.
(3) Annual figures for 2013 include the results of an acquired corporation (the Corporation), for the period of January 25, 2013 to December 31, 2013. Production
includes 341 days for the Corporation and 365 days for the original Bonterra assets.
(4) Includes the acquisition of the Corporation, through a plan of arrangement that closed on January 25, 2013. The Company issued 10,711,405 common shares
valued at $502,258,000 which included $10,000,000 of acquired cash. Capital expenditures, net of dispositions were $119,227,000 excluding the acquisition.
12
BONTERRA ANNUAL REPORT 2015
QUARTERLY COMPARISONS
As at and for the periods ended ($ 000s except $ per share)
Q4
2015
Q3
Q2(1)
Q1
FINANCIAL
Revenue – oil and gas sales
Cash flow from operations
Per share – basic
Per share – diluted
Payout ratio
Cash dividends per share
Net earnings (loss)
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
44,678
27,808
0.84
0.84
54%
0.45
(4,113)
(0.13)
(0.13)
8,384
1,183,593
29,804
332,471
595,805
8,424
710
20,423
12,538
52,160
36,024
1.09
1.09
41%
0.45
(321)
(0.01)
(0.01)
14,402
1,200,856
29,080
335,863
610,793
9,177
753
19,191
13,129
57,921
17,960
0.56
0.56
81%
0.45
(2,711)
(0.08)
(0.08)
167,182(2)
42,480
26,079
0.81
0.81
74%
0.60
(1,935)
(0.06)
(0.06)
38,960(3)
1,225,291
1,072,534
27,558
361,430
599,911
8,823
677
19,452
12,743
37,633
207,217
613,886
8,128
791
19,709
12,204
(1) Quarterly figures for Q2 2015 include the results of the Pembina Assets, for the period of April 15, 2015 to June 30, 2015. Production includes 76 days for the
acquired Pembina Assets and 91 days for the original Bonterra assets.
(2) Includes $153,230,000 (less a deposit of $17,200,000) for the Acquisition that closed on April 15, 2015 and capital expenditures of $13,952,000.
(3) Includes a deposit of $17,200,000 for the Acquisition and capital expenditures of $21,760,000.
As at and for the periods ended ($ 000s except $ per share)
Q4
2014
Q3
Q2
Q1
FINANCIAL
Revenue – oil and gas sales
Cash flow from operations
Per share – basic
Per share – diluted
Payout ratio
Cash dividends per share
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
68,940
50,465
1.57
1.57
57%
0.90
(32,877)(4)
(1.04)
(1.03)
20,605
1,042,938
53,642
154,723
635,198
8,762
911
22,883
13,488
88,959
65,705
2.05
2.03
44%
0.90
20,983
0.65
0.65
41,205
1,080,801
55,047
140,339
697,337
8,874
818
21,981
13,355
99,274
57,089
1.79
1.78
49%
0.87
27,614
0.87
0.86
39,519
1,066,145
36,399
151,145
699,284
9,109
775
24,163
13,911
82,521
49,094
1.56
1.55
56%
0.87
23,041
0.73
0.73
54,236
1,043,822
62,488
143,103
678,224
7,567
721
22,307
12,006
(4) Net loss in the fourth quarter of 2014 is primarily due to an increase in deferred tax expense as a result of an agreement with Canada Revenue Agency.
BONTERRA ANNUAL REPORT 2015
13
BUSINESS ENVIRONMENT AND SENSITIVITIES
Bonterra’s financial results are significantly influenced by fluctuations in commodity prices, including price differentials and foreign
exchange. 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. The increases or decreases for Bonterra’s realized price for oil and natural gas for each of the eight quarters is
explained in detail in the following table.
Q4-2015
Q3-2015
Q2-2015
Q1-2015
Q4-2014
Q3-2014
Q2-2014
Q1-2014
Crude oil
WTI ($US per bbl)
WTI to MSW Stream Index
Differential ($US per bbl)(1)
Foreign exchange
$US to $Cdn
Bonterra average realized
oil price ($Cdn per bbl)
Natural gas
AECO ($Cdn per mcf)
Bonterra average realized gas
price ($Cdn per mcf)
42.18
46.43
57.94
48.63
73.15
97.17
102.99
98.68
(2.51)
(3.45)
(2.93)
(6.93)
(6.46)
(7.93)
(6.14)
(8.25)
1.3353
1.3094
1.2294
1.2411
1.1357
1.0893
1.0905
1.1035
49.50
53.26
64.27
48.70
71.37
92.73
102.36
96.53
2.45
2.61
2.89
3.36
2.64
2.83
2.74
2.97
3.58
3.92
4.00
4.54
4.67
4.85
5.69
6.16
(1) This differential accounts for the major difference between WTI and Bonterra’s average realized price (before quality adjustments and foreign exchange).
The overall volatility in Bonterra’s average realized commodity pricing can be impacted by numerous events, some of which are:
• Worldwide crude oil supply and demand imbalance;
• Geo-political events that affect worldwide crude oil production;
• The reduced value of the Canadian dollar compared to the US dollar continues to positively affect Bonterra’s realized prices;
• Whether there is sufficient or new take-away capacity to transport energy commodities;
• Weather dependence; the warm winter across North America has created a larger imbalance of the increased gas and distillate
(such as heating oil) production to demand; and
• Timing of plant and refinery turnarounds.
In January 2016, WTI decreased to just over $30 US per bbl and has dropped under $30 US per bbl in February primarily due to the
worldwide crude oil supply and demand imbalance partially driven by continued global production gains and high inventories that
are delaying the effect of any supply/demand rebalancing. It is difficult to predict future pricing, but the Company expects crude
oil prices to remain low for the remainder of 2016.
The following chart shows the Company’s sensitivity to key commodity price variables. The sensitivity calculations are performed
independently showing the effect of the change of one variable; with all other variables being held constant.
ANNUALIZED SENSITIVITY ANALYSIS ON CASH FLOW, AS ESTIMATED FOR 2016(1)
Impact on cash flow
Realized crude oil price ($ per bbl)
Realized natural gas price ($ per mcf)
$US to $Cdn exchange rate
Change ($)
1.00
0.10
0.01
$000s
2,931
681
1,344
$ per share(2)
0.09
0.02
0.04
(1) This analysis uses current royalty rates, annualized estimated average production of 12,500 BOE per day and no changes in working capital.
(2) Based on annualized basic weighted average shares outstanding of 33,143,435.
BUSINESS OVERVIEW, STRATEGY AND KEY PERFORMANCE DRIVERS
Bonterra is an oil and gas company that is primarily focused on the development of its Cardium land within the Pembina and
Willesden Green areas located in central Alberta. The Cardium reservoir is the largest conventional oil reservoir in western Canada
that features large original oil in place with very low recoveries. Horizontal drilling with multi stage fracking drastically improves
recoveries from areas developed with vertical drilling and extends the economic edge of the reservoir where vertical drilling is not
economic. Bonterra operates 89 percent of its production with an average land working interest of 76 percent. At December 31,
2015, Bonterra had a horizontal drilling inventory of approximately 773 net locations.
14
BONTERRA ANNUAL REPORT 2015
Even with the significant reduction in commodity prices in comparison to 2014, the Company has been able to generate
positive cash flow on an annual basis. Bonterra was able to reduce capital costs by 27 percent on a per well basis, production
costs by 14 percent on a per BOE basis and general and administrative costs by 32 percent from the same period a year ago.
The reductions were achieved through a combination of innovation, optimization, service cost reduction and a reduction of
overall compensation. In further response to the continued volatile pricing environment for commodities and to maintain cash
flow sustainability, the Company reduced the monthly dividend from $0.15 per share to $0.10 per share commencing with the
January 2016 dividend. Should commodity prices improve, the Company also has flexibility to manage capital costs related to
undrilled locations by allowing for accelerated development.
On April 15, 2015, the Company acquired certain oil and gas assets (the Pembina Assets) from a senior oil and gas producer
(the Acquisition). The Pembina Assets are Cardium focused in the Pembina Area of Alberta, with a production base that is
complementary to current Bonterra acreage, and which provides additional inventory of long-term drilling locations. Consideration
for the Pembina Assets was $170,430,000. If Bonterra had closed the Acquisition on January 1, 2015, the Pembina Assets would
have added approximately 1,700 BOE per day of production, oil and gas sales of approximately $29,098,000, royalty expenses
of approximately $971,000 and operating expenses of approximately $14,761,000 for the year ended December 31, 2015.
The combined production for the Company for the year would have been 13,147 BOE per day. The actual amounts recorded for the
Pembina Assets include oil and gas sales of $21,260,000, royalty expenses of $593,000 and operating expenses of $10,448,000
for the period from April 15, 2015 to December 31, 2015. The Pembina Assets are approximately 87 percent oil and NGL weighted
with a low decline rate of seven percent. These assets also include 136 net future potential drilling locations and supporting
infrastructure. For more information about the Acquisition, refer to Note 5 of the December 31, 2015 audited financial statements.
During 2015, Bonterra spent approximately $58,498,000 on its capital program and drilled 20 gross (16.7 net) operated wells
and completed and tied-in 24 gross (22.2 net) wells (of which 10 wells were drilled in 2014, but not completed until 2015). Of the
20 operated wells drilled 6 (4.5 net) were completed and tied-in in the first quarter of 2016. In addition, 6 (0.8 net) non-operated
wells were drilled and placed on production during 2015. The Company also added field compression to redirect gas production
in the Carnwood area to two of its wholly owned plants in the Keystone Area. In December 2015, the Company set its capital
expenditure budget for 2016 at approximately $40 million. With continued price erosion for oil in 2016, the Company continues to
review capital spending on a month by month basis.
The Company averaged production of 12,656 BOE per day for the full year of 2015, which was between the annual guidance of
12,600 to 12,900 BOE per day. During 2015 production was reduced by approximately 1,100 BOE per day from oil apportionments,
gas capacity restrictions and voluntarily shutting-in uneconomic production due to low commodity prices.
During 2015, the Company increased its natural gas firm service delivery with TransCanada Pipeline from under 7,000 mcf per day
to over 19,000 mcf per day. Considering approximately 90 percent of Bonterra’s current natural gas production is from solution
gas, this will reduce transportation curtailments associated with interruptible service, thereby decreasing the restrictions on
oil production. The Company has also reactivated some of its restricted production as a result of redirecting solution gas to
alternative gas plants. To further alleviate future potential gas capacity issues, in the fourth quarter of 2015, Bonterra took over
operatorship of a third gas plant in the Pembina Cardium area that it has ownership in. The ability to redirect gas to operated
facilities should further reduce a portion of the shut-in issues experienced during the 2015 year while lowering gas processing
costs. The Company is estimating that its average annual production for 2016 will be approximately 12,500 BOE per day, but it
will be continuously adjusting annual production targets according to changing commodity prices and capital spending program.
Bonterra’s successful operations are dependent upon several factors, including but not limited to, commodity prices, efficiently
managing capital spending, monthly dividends, 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.
BONTERRA ANNUAL REPORT 2015
15
DRILLING
DECEMBER 31,
2015
Three months ended
September 30,
2015
December 31,
2014
DECEMBER 31,
2015
December 31,
2014
Year ended
GROSS(1) NET(2)
Gross(1) Net(2)
Gross(1) Net(2) GROSS(1) NET(2)
Gross(1) Net(2)
Crude oil horizontal – operated
Crude oil horizontal – non-operated
Total
Success rate
3
3
6
1.5
0.4
1.9
100%
6
2
8
5.9
0.3
6.2
100%
10
-
10
9.9
-
9.9
100%
20
16.7
6
0.8
26
17.5
100%
43
22
65
42.6
4.9
47.5
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 2015, the Company placed 10 gross (9.9 net) wells on production that were drilled in the later part of 2014. In addition,
the Company drilled 20 gross (16.7 net) wells, of which 14 gross (12.3 net) were placed on production in 2015 with the remaining
six wells scheduled to be on production in the first quarter of 2016. As well, six gross (0.8 net) non-operated wells were drilled and
placed on production during the year.
PRODUCTION
Crude oil (barrels per day)
NGLs (barrels per day)
Natural gas (MCF per day)
Average BOE per day
DECEMBER 31,
2015
Three months ended
September 30,
2015
December 31,
2014
DECEMBER 31,
2015
December 31,
2014
Year ended
8,424
710
20,423
12,538
9,177
753
19,191
13,129
8,762
911
22,883
13,488
8,641
733
19,694
12,656
8,582
807
22,833
13,195
Production volumes during 2015 decreased to 12,656 BOE per day compared to 13,195 BOE per day in 2014. The decrease in
production is primarily due to a significant reduction in development capital spending as Bonterra drilled 17.5 net wells in 2015
versus 47.5 net wells in 2014. In addition to a reduction of capital spending caused by low commodity prices, the Company also
voluntarily shut-in approximately 510 BOE per day until commodity prices improve. A further 590 BOE per day of production was
also shut-in due to non-operated facility turnarounds, oil apportionments, gas capacity restrictions imposed by TransCanada
Pipelines and further restrictions for a downstream non-operated meter station expansion.
The decrease in production from a year ago was partially offset by an average of 1,700 BOE per day from the Pembina Assets,
since the acquisition date of April 15, 2015.
Quarter over quarter, production volumes decreased by 591 BOE per day primarily due to 700 BOE per day of production being
voluntarily shut-in due to low commodity prices and a further 320 BOE per day being shut in due to non-operated facility restrictions.
This was partially offset by six gross (3.4 net) new wells being placed on production in November of 2015.
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
Production costs
Field netback
General and administrative
Interest and other
Cash netback
DECEMBER 31,
2015
Three months ended
September 30,
2015
December 31,
2014
DECEMBER 31,
2015
December 31,
2014
Year ended
1,153,476
1,207,856
1,240,864
4,619,277
4,816,030
$
$
$
38.73
$
43.18
$
55.56
$
42.70
$
(2.55)
(11.81)
(3.06)
(12.06)
(5.87)
(12.50)
(2.89)
(11.95)
24.37
$
28.06
$
37.19
$
27.86
$
(1.63)
(2.98)
(1.59)
(2.63)
(1.83)
(1.16)
(1.56)
(2.60)
19.76
$
23.84
$
34.20
$
23.70
$
70.53
(7.91)
(13.89)
48.73
(2.22)
(1.12)
45.39
16
BONTERRA ANNUAL REPORT 2015
Cash netbacks have decreased in 2015 compared to 2014 primarily due to lower commodity prices and an increase in interest
expense from funding the Pembina Assets with debt, which was partially offset by lower royalties, production costs and general
and administration costs. Quarter over quarter cash netbacks decreased mainly due to lower crude oil and natural gas prices.
OIL AND GAS SALES
Revenue – oil and gas sales
($ 000s)
Average Realized Prices:
Crude oil ($ per barrel)
NGLs ($ per barrel)
Natural gas ($ per MCF)
Average ($ per BOE)
DECEMBER 31,
2015
Three months ended
September 30,
2015
December 31,
2014
DECEMBER 31,
2015
December 31,
2014
Year ended
44,678
52,160
68,940
197,239
339,694
49.50
21.49
2.61
38.73
53.26
18.05
3.36
43.18
71.37
37.49
3.92
55.56
54.08
20.80
2.94
42.70
90.61
52.26
4.86
70.53
Revenue from oil and gas sales decreased by $142,455,000 in 2015 or 42 percent compared to 2014. This decrease was primarily
due to a 39 percent decrease in commodity prices on a per BOE basis.
The quarter over quarter decrease in oil and gas sales of $7,482,000 or 14 percent was primarily due to decreased crude oil and
natural gas prices.
The Company’s product split on a revenue basis for 2015 is approximately 89 percent weighted towards crude oil and NGLs.
ROYALTIES
($ 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,
2015
Three months ended
September 30,
2015
December 31,
2014
DECEMBER 31,
2015
December 31,
2014
Year ended
1,901
1,039
2,940
4.3
2.3
6.6
2.55
2,398
1,301
3,699
4.6
2.5
7.1
3.06
5,021
2,259
7,280
7.3
3.3
10.6
5.87
8,007
5,354
13,361
4.1
2.7
6.8
2.89
23,779
14,331
38,110
7.0
4.2
11.2
7.91
Royalties paid by the Company consist of crown royalties paid to the Provinces of Alberta, Saskatchewan and British Columbia
and non-crown royalties. Royalties on a per BOE basis decreased by $5.02 per BOE for 2015 compared to 2014, primarily due to
lower commodity prices. On a percentage of revenue basis royalty rates decreased due to lower crown royalty rates as a result
of decreased commodity prices and less production from freehold properties, which are generally subject to higher royalty rates
compared to crown royalty rates.
Quarter over quarter royalties, on a per BOE basis, decreased primarily due to a decrease in crude oil and natural gas prices
realized in the fourth quarter.
In 2016, the provincial government of Alberta announced the key highlights of a proposed Modernized Royalty Framework (MRF)
that will be effective on January 1, 2017. These highlights include providing royalty incentives for the efficient development of
conventional crude oil, natural gas, and NGL resources, no changes to the royalty structure of wells drilled prior to 2017 for a
10 year period from the royalty program’s implementation date, the replacement of royalty credits or holidays on conventional
wells by a revenue minus cost framework with a post-revenue minus cost royalty rate based on commodity prices, the reduction
of royalty rates for mature wells, and a neutral internal rate of return for any given play compared to the current royalty framework.
Since the provincial government of Alberta has not yet released all of the details of the MRF, the Company cannot determine if the
MRF will have a material impact on Bonterra’s results of operations on a go forward basis.
BONTERRA ANNUAL REPORT 2015
17
Bonterra will evaluate the impact of the MRF on the Company’s expected results of operations and cash flows as more details
are released.
PRODUCTION COSTS
($ 000s except $ per BOE)
Production costs(1)
$ per BOE
DECEMBER 31,
2015
Three months ended
September 30,
2015
December 31,
2014
DECEMBER 31,
2015
December 31,
2014
Year ended
13,622
11.81
14,570
12.06
15,516
12.50
55,215
11.95
66,878
13.89
(1) Transportation costs are included in production costs.
Production costs on a per BOE basis for 2015 decreased 14 percent compared to 2014. Production costs on a BOE basis have
primarily decreased as a result of field optimizations leading to reduced well maintenance, more efficient produced water handling
and decreased chemical costs. Also production costs decreased due to a reduction in rates charged by service companies and
lower freehold mineral taxes due to lower commodity prices. These savings were partially offset by the production costs of
the Pembina Assets that currently have higher operating costs due to the low production from individual vertical wells and a
waterflood program. The higher costs per BOE in this area are expected to drop further as Bonterra gains efficiencies from reduced
trucking, waterflood support, lower labour costs and more importantly through horizontal development adding new production in
the area from its undrilled locations.
Quarter over quarter, production costs on a per BOE basis decreased primarily due to delaying well maintenance costs on marginal
wells in the fourth quarter because of reduced commodity prices, compared to facility maintenance and plant turnarounds that
generally occur in the third quarter.
OTHER INCOME
($ 000s)
Investment income
Administrative income
Gain on sale of properties
Realized gain on investments
DECEMBER 31,
2015
Three months ended
September 30,
2015
December 31,
2014
DECEMBER 31,
2015
December 31,
2014
Year ended
41
15
-
-
56
45
16
-
-
61
12
22
-
-
34
251
77
-
-
328
56
282
671
1,102
2,111
In January 2014, the Company sold a portion of its undeveloped land in the Willesden Green area for cash proceeds of $1,000,000.
At the time of disposition, the Company had a carrying value of $419,000 for exploration and evaluation expenditures, resulting in
a gain on sale of $581,000.
The market value of the investments held by the Company is $9,538,000 at December 31, 2015 (December 31, 2014 – $7,966,000).
The carrying value increased due to the $12,221,000 of investments purchased by the Company during 2015 which was partially
offset by a decrease in market value of $2,519,000 through other comprehensive loss and investments sold in the year for
proceeds of $8,130,000. This disposition resulted in a gain on sale of $1,191,000 which was recorded as an equity transfer
between accumulated other comprehensive income and retained earnings and not recorded in profit and loss. The accounting
treatment resulted from early adopting IFRS 9 “Financial Instruments” (see Financial Reporting Update).
The Company receives administrative income by way of management fees from a related party (see related party transactions).
GENERAL AND ADMINISTRATION (G&A) EXPENSE
($ 000s except $ per BOE)
Employee compensation expense
Office and administration expense
Total G&A expense
$ per BOE
DECEMBER 31,
2015
Three months ended
September 30,
2015
December 31,
2014
DECEMBER 31,
2015
December 31,
2014
Year ended
1,211
666
1,877
1.63
912
1,007
1,919
1.59
1,399
877
2,276
1.83
3,905
3,302
7,207
1.56
7,111
3,559
10,670
2.22
18
BONTERRA ANNUAL REPORT 2015
The decrease in employee compensation expense of $3,206,000 for 2015 compared to 2014 is primarily due to a decrease in
accrued bonuses that resulted from lower net earnings before income taxes. The Company has a bonus plan in which the bonus
pool consists of a range between 2.5 percent to 3.5 percent of earnings before income taxes. The Company firmly believes that
tying employee compensation (including the use of stock options) to the performance of the Company clearly aligns the interest
of the employees with that of the shareholders.
Office and administration expense for 2015 decreased compared to 2014 due to a decrease in office rent, professional fees
and a decrease in the allowance for doubtful accounts. The decrease quarter over quarter relates primarily to a decrease in the
allowance for doubtful accounts and continuous disclosure costs.
FINANCE COSTS
($ 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,
2015
Three months ended
September 30,
2015
December 31,
2014
DECEMBER 31,
2015
December 31,
2014
Year ended
3,244
252
3,496
3.03
514
4,010
2,948
291
3,239
2.68
504
3,743
1,220
251
1,471
1.19
388
1,859
10,390
1,931
12,321
2.67
1,878
14,199
4,282
1,461
5,743
1.19
1,361
7,104
Interest on long-term debt increased $6,108,000 in 2015 compared to 2014 as the Company increased the outstanding bank debt
by $170,000,000 to finance the Pembina Asset acquisition in the second quarter. The Company’s bank interest rate increased in
the second half of 2015 due to a higher net debt to cash flow ratio. Interest rates are determined by net debt to cash flow ratio on
a trailing quarterly basis.
Other interest relates to amounts paid to a related party (see related party transactions) and a $25,000,000 subordinated promissory
note from a private investor and a one-time interest charge of $694,000 paid to the vendor for the Pembina Asset acquisition for
the period January 1, 2015 to April 15, 2015. Subsequent to the year ended December 31, 2015, the Company repaid $10,000,000
of the subordinated promissory note.
A one percent increase (decrease) in the Canadian prime rate would decrease (increase) both annual net earnings and
comprehensive income by approximately $2,515,000.
SHARE-OPTION COMPENSATION
($ 000s)
DECEMBER 31,
2015
Three months ended
September 30,
2015
December 31,
2014
DECEMBER 31,
2015
December 31,
2014
Year ended
Share-option compensation
1,550
958
947
4,270
2,725
Share-option compensation is a statistically calculated value representing the estimated expense of issuing employee stock
options. The Company records a compensation expense over the vesting period based on the fair value of options granted to
employees, directors and consultants.
Share-option compensation increased by $1,545,000 from the same period a year ago due to less share-option compensation
being amortized in 2014 as fewer options were outstanding during the year. Also, the fair value of the 1,772,500 options granted
during the year (2014 – 1,769,000) increased from $2.82 per option to $3.68 per option due to an increase in volatility of the
Company’s share price used in valuing the options under the Black-Scholes option pricing model. Quarter over quarter share-
option compensation increased due to the Company granting 807,000 stock options in the fourth quarter.
Based on the outstanding options as of December 31, 2015, the Company has an unamortized expense of $4,644,000, of which
$4,153,000 will be recorded for 2016, $487,000 for 2017 and $4,000 for 2018. For more information about options issued and
outstanding, refer to Note 17 of the December 31, 2015 audited annual financial statements.
BONTERRA ANNUAL REPORT 2015
19
DEPLETION AND DEPRECIATION, EXPLORATION AND EVALUATION AND GOODWILL
($ 000s)
Depletion and depreciation
Exploration and evaluation
DECEMBER 31,
2015
Three months ended
September 30,
2015
December 31,
2014
DECEMBER 31,
2015
December 31,
2014
Year ended
25,775
183
26,586
-
26,975
-
101,150
183
106,697
28
Provision for depletion and depreciation decreased by $5,547,000 for 2015 compared to 2014. The decrease in depletion and
depreciation is primarily due to a decrease in production volumes and a lower decline rate associated with the acquired Pembina
Assets. The quarter over quarter decrease in the provision was primarily due to a decrease in production volumes and less capital
spent in the fourth quarter.
Exploration and evaluation expense related to expired leases.
There were no impairment provisions recorded for the years ended December 31, 2015 or 2014.
TAXES
Applying the statute income tax rate of 26.01 percent in effect for the 2015 year, the expected income tax provision would have
been $515,000 on net earnings before income taxes. The higher than expected income tax provision of $11,062,000 for the 2015
year is primarily due to the Alberta provincial tax rate increasing to 12 percent from 10 percent that came into effect July 1, 2015,
which increased the Company’s deferred tax liability by approximately $8,490,000, resulting in a net loss.
On November 14, 2013, the Company received a proposal letter from the Canada Revenue Agency (CRA) which stated its intention
to challenge the tax consequences of Bonterra’s reorganization from a trust to a Corporation, which occurred on November 18,
2008. On November 27, 2014, the Company reached an agreement with CRA (the Agreement) to adjust certain tax pools, resulting
in a $43,503,000 reduction in the Company’s deferred tax assets and investment tax credit receivable. The reduction was charged
to deferred tax expense in the statement of comprehensive income (loss). The large tax expense of $70,832,000 for the 2014
fiscal year is related to a reduction in the Company’s tax assets as a result of an agreement with CRA and an increase in earnings
before income taxes. The reduction in tax assets was charged to deferred tax expense in the statement of comprehensive income
(loss). In 2014, the Company utilized $6,645,000 of the federal investment tax credit receivable to reduce current taxes payable to
$3,860,000. No taxes are owing for the 2015 fiscal year.
For additional information regarding income taxes, see Note 16 of the December 31, 2015 annual audited financial statements.
NET EARNINGS (LOSS)
($ 000s except $ per share)
Net earnings (loss)
$ per share – basic
$ per share – diluted
DECEMBER 31,
2015
Three months ended
September 30,
2015
December 31,
2014
DECEMBER 31,
2015
December 31,
2014
Year ended
(4,113)
(0.13)
(0.13)
(321)
(0.01)
(0.01)
(32,877)
(1.04)
(1.03)
(9,080)
(0.28)
(0.28)
38,761
1.21
1.21
Net earnings in 2015 decreased by $47,841,000 compared to the same period in 2014. Decreased net earnings resulted primarily
from lower commodity prices, which was partially offset by a decrease in deferred income tax expense, royalties, production and
G&A costs. The Company had net earnings before income taxes of $1,982,000 in a low price commodity environment.
The quarter over quarter increase in net loss was mainly due to lower crude oil and natural gas prices.
OTHER COMPREHENSIVE INCOME (LOSS)
Other comprehensive loss for 2015 consists of an unrealized loss before tax on investments (including investment in a related
party) of $2,519,000 relating to a decrease in the investments’ fair value (December 31, 2014 – unrealized gain of $1,174,000).
Realized gains decrease accumulated other comprehensive income as these gains are transferred to retained earnings. Other
comprehensive income varies from net earnings by unrealized changes in the fair value of Bonterra’s holdings of investments
including the investment in related party, net of tax.
20
BONTERRA ANNUAL REPORT 2015
CASH FLOW FROM OPERATIONS
($ 000s except $ per share)
Cash flow from operations
$ per share – basic
$ per share – diluted
DECEMBER 31,
2015
Three months ended
September 30,
2015
December 31,
2014
DECEMBER 31,
2015
December 31,
2014
Year ended
27,808
0.84
0.84
36,024
1.09
1.09
50,465
1.57
1.57
107,871
222,353
3.30
3.30
6.97
6.94
In 2015, cash flow from operations decreased by $114,482,000 compared to the same period a year ago. This was primarily due
to a decrease in revenue from oil and gas sales, which were partially offset by a decrease in royalties, production and G&A costs.
The quarter over quarter decrease of $8,216,000 was primarily due to a decrease in oil and gas sales due to lower crude oil and
natural gas prices.
RELATED PARTY TRANSACTIONS
Bonterra holds 1,034,523 (December 31, 2014 – 1,034,523) common shares in Pine Cliff Energy Ltd (Pine Cliff) which represents
less than one percent ownership in Pine Cliff’s outstanding common shares. Pine Cliff’s common shares had a fair market value
as of December 31, 2015 of $962,000 (December 31, 2014 of $1,738,000). Pine Cliff paid a management fee to the Company of
$60,000 (December 31, 2014 – $60,000) plus the reimbursement of certain administrative expenses. Services provided by the
Company include executive services, oil and gas administration and office administration. All services performed are charged at
estimated fair value. As at December 31, 2015, the Company had an account receivable from Pine Cliff of $293,000 (December 31,
2014 – $316,000).
As at December 31, 2015, the Company’s CEO, Chairman of the Board and major shareholder loaned the Company $12,000,000
(December 31, 2014 – $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 for 2015 was $261,000 (December 31, 2014 – $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.
LIQUIDITY AND CAPITAL RESOURCES
NET DEBT TO CASH FLOW FROM OPERATIONS
Bonterra continues to focus on monitoring and managing its cash flow, capital expenditures and dividend payments. The
Company did not meet its annual guidance range of 1 to 1 times to 1.5 to 1 times net debt to a 12 month trailing cash flow
ratio and as of December 31, 2015 had a ratio of 3.4 to 1 times. The increase in net debt to cash flow is primarily due to the
Pembina Asset acquisition on April 15, 2015 and low commodity prices realized in 2015 compared to 2014. To manage its bank
debt, Bonterra significantly reduced planned capital expenditures for 2015 compared to 2014 and reduced the monthly dividend
payments by 50 percent beginning with the February 2015 payment. Beginning in January 2016, the Company further reduced the
monthly dividend by $0.05 to $0.10 per common share. In addition the Company raised equity by way of a private placement of
approximately $31 million. With the current oil commodity price environment the Company will be assessing its monthly dividend
and capital expenditures for 2016 on a month to month basis.
WORKING CAPITAL DEFICIENCY AND NET DEBT
($ 000s)
Working capital deficiency
Long-term bank debt
Net debt
DECEMBER 31,
2015
December 31,
2014
29,807
332,471
362,278
53,642
154,723
208,365
The Company has sufficient availability on its credit facility to repay both the related party loan and the subordinated promissory
note if required. The Company manages the working capital position during each quarter by monitoring capital spending and
dividends paid compared to cash flow from operations.
Net debt is a combination of long-term bank debt and working capital. Net debt increased compared to the 2014 year. This was
primarily attributable to decreased cash flow from lower field netbacks and the acquisition of the Pembina Assets, partially offset
BONTERRA ANNUAL REPORT 2015
21
by decreased capital spending and reducing the monthly dividend from $0.30 per share to $0.15 per share that commenced
with the February 2015 dividend. Beginning with the January 2016 dividend payment the Company further reduced the monthly
dividend to $0.10 per share due to further declines in commodity prices.
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 non-core assets and
investments. Included in the working capital deficiency at December 31, 2015 is $37 million of debt relating to the subordinated
promissory note and the amount due to related party. The Company has sufficient room on its credit facility to repay these loans
if required.
The Company has not currently entered into any financial derivative contracts.
CAPITAL EXPENDITURES
During the year ended December 31, 2015, the Company incurred development capital costs of $58,498,000 (December 31,
2014 – $155,566,000) net of proceeds on disposal of property, plant and equipment. The costs relate primarily to the drilling of
20 gross (16.7 net) Cardium operated horizontal wells, completing and tying-in 10 gross (9.9 net) Cardium operated wells that
were drilled in 2014, and upgrading facilities and gathering systems. The Company also incurred $170,430,000 in capital costs for
the Pembina Asset acquisition.
LONG-TERM DEBT
Long-term debt represents the outstanding draws from the Company’s credit facilities as described in the notes to the Company’s
audited annual financial statements. As of December 31, 2015, the Company has bank facilities consisting of a $375,000,000
(December 31, 2014 – $220,000,000) syndicated revolving credit facility and a $50,000,000 (December 31, 2014 – $30,000,000)
non-syndicated revolving credit facility. Amounts drawn under these credit facilities at December 31, 2015 totaled $332,471,000
(December 31, 2014 – $154,723,000). The interest rates on the outstanding debt as of December 31, 2015 were 4.95 percent and
4.38 percent on the Company’s Canadian prime rate loan and Banker’s Acceptances, respectively. The loan is revolving to April 29,
2016 with a maturity date of April 30, 2017 and is subject to annual review. The credit facilities have no fixed terms of repayment.
Advances drawn under the credit facilities are secured by a fixed and floating charge debenture over the assets of the Company.
In the event the credit facilities are not extended or renewed, amounts drawn under the facility would be due and payable on the
maturity date. The size of the committed credit facilities is based primarily on the value of the Company’s producing petroleum and
natural gas assets and related tangible assets as determined by the lenders. For more information see Note 14 of the December 31,
2015 audited annual financial statements.
SHAREHOLDERS’ EQUITY
The Company is authorized to issue an unlimited number of common shares without nominal or par value.
The Company is authorized to issue an unlimited number of Class “A” redeemable Preferred Shares and an unlimited
number of Class “B” Preferred Shares. There are currently no outstanding Class “A” redeemable Preferred Shares or Class “B”
Preferred Shares.
DECEMBER 31, 2015
December 31, 2014
Issued and fully paid – common shares
Balance, beginning of year
Share issuance, private placement
Share issue costs, net of tax
Issued pursuant to the Company's share option plan
Transfer from contributed surplus to share capital
Shares issued for oil and gas properties
NUMBER
32,169,623
973,812
-
-
AMOUNT
($ 000S)
728,934
31,162
(76)
-
-
-
Number
31,322,171
-
829,452
18,000
Balance, end of year
33,143,435
760,020
32,169,623
Amount
($ 000s)
685,898
-
-
37,911
4,021
1,104
728,934
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 3,314,344 (December 31, 2014 – 3,216,962) 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, see Note 17 of the December 31, 2015 audited annual
financial statements.
22
BONTERRA ANNUAL REPORT 2015
On July 8, 2015, the Company closed a private placement of 973,812 common shares to existing shareholders at a price of
$32.00 per share, for aggregate proceeds of approximately $31,162,000. The Company incurred share issue costs of
approximately $105,000 in respect of the offering.
COMMITMENTS
The Company has entered into firm service gas transportation agreements in which the Company guarantees certain minimum
volumes of natural gas will be shipped on various gas transportation systems. The terms of the various agreements expire in one
to nine years. The Company has office lease commitments for building and office equipment. The building and office equipment
leases have an average remaining life of 2.3 years. There are no restrictions placed upon the lessee by entering into these leases.
Future minimum payments for the firm service gas transportation agreements using current tariff rates and the non-cancellable
building and office equipment leases as at December 31, 2015 are as follows:
($ 000s)
Firm service commitments
Office lease commitments
Total
DIVIDEND POLICY
2016
1,165
941
2,106
2017
1,061
922
1,983
2018
910
308
1,218
2019
875
-
875
2020
Thereafter
791
-
791
2,793
-
2,793
Total
7,595
2,171
9,766
For the year ended December 31, 2015, Bonterra paid dividends of $63,607,000 ($1.95 per share) compared to $113,007,000
($3.54 per share) in 2014. Bonterra’s dividend policy is regularly monitored and is dependent upon production, commodity prices,
funds from operations, debt levels and capital expenditures. With its large inventory of undrilled locations, Bonterra continues to
be well positioned to provide its shareholders a combination of sustainable growth and meaningful dividend income.
Bonterra’s dividends to its shareholders are funded by cash flow from operating activities with the remaining cash flow directed
towards capital spending and, where applicable, the repayment of debt. To the extent that the excess cash flow from operations
after dividends is not sufficient to cover capital spending, the shortfall is funded by funds from the exercising of employee stock
options, the sale of investments and by drawdowns from Bonterra’s credit facilities. Bonterra intends to provide dividends to
shareholders that are sustainable to the Company considering its liquidity and its long-term operational strategy. In addition, since
the level of dividends is highly dependent upon cash flow generated from operations, which fluctuates significantly in relation to
changes in financial and operational performance, commodity prices, interest and exchange rates and many other factors, future
dividends cannot be assured. Bonterra’s payout ratio based on cash flow from operations was 59 percent for the year ended
December 31, 2015 (51 percent for the year ended December 31, 2014).
QUARTERLY FINANCIAL INFORMATION
For the periods ended ($ 000s except $ per share)
Revenue – oil and gas sales
Cash flow from operations
Net earnings (loss)
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
Q4
44,678
27,808
(4,113)
(0.13)
(0.13)
Q4
68,940
50,465
(32,877)
(1.04)
(1.03)
2015
Q3
52,160
36,024
(321)
(0.01)
(0.01)
2014
Q3
88,959
65,705
20,983
0.65
0.65
Q2
57,921
17,960
(2,711)
(0.08)
(0.08)
Q2
99,274
57,089
27,614
0.87
0.86
Q1
42,480
26,079
(1,935)
(0.06)
(0.06)
Q1
82,521
49,094
23,041
0.73
0.73
The fluctuations in the Company’s revenue and net earnings from quarter to quarter are primarily caused by variations in production
volumes, realized commodity pricing and the related impact on royalties and production costs. In 2015, net earnings and cash flow
are lower than prior periods due to a significant decrease in commodity prices, other than Q4 2014 net earnings which was lower
due to the Company’s tax agreement with the CRA.
BONTERRA ANNUAL REPORT 2015
23
CRITICAL ACCOUNTING ESTIMATES
There have been no changes to the Company’s critical accounting policies and estimates as of the period ended in the
financial statements.
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. The foregoing factors are not exhaustive.
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 therefrom. 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.
DISCLOSURE CONTROLS AND PROCEDURES
Disclosure controls and procedures (DC&P), as defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual
and Interim Filings, are designed to provide reasonable assurance that information required to be disclosed in the Company’s
annual filings, interim filings or other reports filed, or submitted by the Company under securities legislation is recorded, processed,
summarized and reported within the time periods specified under securities legislation and include controls and procedures
designed to ensure that information required to be disclosed is accumulated and communicated to management, including the
Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. The
Chief Executive Officer and Chief Financial Officer of Bonterra evaluated the effectiveness of the design and operation of the
Company’s DC&P. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that Bonterra’s
DC&P were effective at December 31, 2015.
INTERNAL CONTROLS OVER FINANCIAL REPORTING
Internal control over financial reporting (ICFR), as defined in National Instrument 52-109, includes those policies and
procedures that:
1. Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions
of Bonterra;
2. Are designed to provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles and that receipts and expenditures of Bonterra are
being made in accordance with authorizations of management and Directors of Bonterra; and
3. Are designed to provide reasonable assurance regarding prevention or timely detection of authorized acquisition, use, or
disposition of the Company’s assets that could have a material effect on the financial statements.
24
BONTERRA ANNUAL REPORT 2015
The CEO and CFO have designed, or caused to be designed under their supervision, ICFR as defined in National Instrument 52-109
of the Canadian Securities Administrators, in order to provide reasonable assurance regarding the reliability of financial reporting and
the preparation of financial statements for external purposes in accordance with IFRS. The control framework the Company used
to design its ICFR was in accordance with the Committee of Sponsoring Organizations of the Treadway Commission (COSO 2013).
The Company’s CEO and CFO have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company’s
internal controls over financial reporting at the financial period end of the Company and concluded that such internal controls over
financial reporting are effective.
In May 2013, the Committee of Sponsoring Organizations of the Treadway Commission (COSO) published an updated Internal
Control – Integrated Framework and related illustrative documents which supersedes the 1992 COSO Framework as of December 14,
2014. During the year, Bonterra has converted to the 2013 COSO framework.
It should be noted that while Bonterra’s CEO and CFO believe that the Company’s internal controls and procedures provide a
reasonable level of assurance and are effective; they do not expect that these controls will prevent all errors and fraud. A control
system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that its objectives are met.
FINANCIAL REPORTING UPDATE
As of January 1, 2015, the Company early adopted IFRS 9 in accordance with the transitional provisions of that standard. A brief
description of the new accounting policy and its impact on the Company’s financial statements are as follows:
IFRS 9 “Financial Instruments”
Effective January 1, 2015 the Company adopted IFRS 9 “Financial Instruments”. IFRS 9 replaces the sections of IAS 39 “Financial
Instruments: Recognition and Measurements” that relates to the classification and measurement of financial instruments and
hedge accounting.
IFRS 9 replaces the multiple classification and measurement models for financial assets with a new model that only has two
measurement categories; amortized cost and fair value through profit or loss or other comprehensive income. This determination
is made at initial recognition. As a result of adopting IFRS 9, the Company’s accounts receivables were reclassified from loans
and receivables at amortized cost to financial assets at amortized cost. For financial liabilities, the new standard retains most of
the IAS 39 requirements. The main change arises in cases where the Company chooses to designate a financial liability as fair
value through net earnings. In these situations, the portion of the fair value change related to the Company’s own credit risk is
recognized in other comprehensive income rather than net earnings. The Company has no financial liabilities that are measured
at fair value through net earnings.
The classification of the Company’s investments changed from available-for-sale to financial assets measured at fair value. On the
day an investment is acquired the Company can make an irrevocable election (on an instrument by instrument basis) to designate
investments in equity instruments as at fair value through other comprehensive income (FVTOCI), provided those investments
are not classified as held for trading. The Company’s investments will be measured at fair value, with gains or losses arising
from changes in fair value recognized in other comprehensive income (loss) and accumulated in the fair value instrument. The
cumulative gain or loss will not be reclassified to profit or loss on disposal of the investments. The Company has designated all of
its investments and its investment in a related party as FVTOCI on its initial adoption of IFRS 9.
FUTURE ACCOUNTING PRONOUNCEMENTS
In May 2014, the International Accounting Standards Board (IASB) issued IFRS 15 “Revenue from Contracts with Customers,”
which replaces IAS 18 “Revenue,” IAS 11 “Construction Contracts,” and related interpretations. This standard is required to be
adopted either retrospectively or using a modified transition approach for fiscal years beginning on or after January 1, 2018, with
earlier adoption permitted. The Company has not yet assessed the impact, if any, that the new standard will have on its financial
statements or whether to early adopt this new standard.
Additional information relating to the Company may be found on www.sedar.com or visit our website at www.bonterraenergy.com.
BONTERRA ANNUAL REPORT 2015
25
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 judgments and have been properly
reflected in the accompanying financial statements.
Management maintains a system of internal controls to provide reasonable assurance that the Company’s assets are
safeguarded and to facilitate the preparation of relevant and timely information.
Deloitte 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
March 17, 2016
ROBB D. THOMPSON
Chief Financial Officer
March 17, 2016
26
BONTERRA ANNUAL REPORT 2015
INDEPENDENT AUDITOR’S REPORT
TO THE SHAREHOLDERS OF BONTERRA ENERGY CORP.
We have audited the accompanying financial statements of Bonterra Energy Corp. (the “Company”), which comprise the statement
of financial position as at December 31, 2015 and 2014, and the statement of comprehensive income (loss), statement of cash
flow and statement of changes in equity for the years then ended, and a summary of significant accounting policies and other
explanatory information.
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, 2015 and 2014, and its financial performance and its cash flows for the years then ended in accordance with
International Financial Reporting Standards.
Chartered Professional Accountants, Chartered Accountants
March 17, 2016
Calgary, Canada
BONTERRA ANNUAL REPORT 2015
27
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
Goodwill
LIABILITIES
CURRENT
Accounts payable and accrued liabilities
Due to related party
Subordinated promissory note
Bank debt
Decommissioning liabilities
Deferred tax liability
COMMITMENTS AND SUBSEQUENT EVENTS
SHAREHOLDERS’ EQUITY
Share capital
Contributed surplus
Accumulated other comprehensive income
Retained earnings (deficit)
See accompanying notes to these financial statements.
On behalf of the board:
Note
DECEMBER 31,
2015
December 31,
2014
7
8
5, 9
16
10
11
12
13
14
15
16
21, 22
17
15,433
868
2,798
8,576
27,675
962
7,925
1,045,387
8,834
92,810
20,314
1,227
2,428
6,228
30,197
1,738
7,629
901,991
8,573
92,810
1,183,593
1,042,938
20,479
12,000
25,000
57,479
332,471
71,523
126,315
587,788
760,020
15,765
571
(180,551)
595,805
31,839
12,000
40,000
83,839
154,723
53,792
115,386
407,740
728,934
11,495
3,824
(109,055)
635,198
1,183,593
1,042,938
GEORGE F. FINK
Director
28
RODGER A. TOURIGNY
Director
BONTERRA ANNUAL REPORT 2015
STATEMENT OF COMPREHENSIVE INCOME (LOSS)
FOR THE YEARS ENDED DECEMBER 31
($ 000s, except $ per share)
REVENUE
Oil and gas sales, net of royalties
Other income
EXPENSES
Production
Office and administration
Employee compensation
Finance costs
Share-option compensation
Depletion and depreciation
Exploration and evaluation
EARNINGS BEFORE INCOME TAXES
TAXES (RECOVERY)
Current income tax (recovery)
Deferred income tax
NET EARNINGS (LOSS) FOR THE YEAR
OTHER COMPREHENSIVE INCOME (LOSS)
Unrealized gain (loss) on investments
Deferred taxes on unrealized (gain) loss on investments
Realized gain on investments transferred to net earnings
Deferred taxes on realized gain on investments transferred to net earnings
OTHER COMPREHENSIVE INCOME (LOSS) FOR THE YEAR
TOTAL COMPREHENSIVE INCOME (LOSS) FOR THE YEAR
NET EARNINGS (LOSS) PER SHARE – BASIC
NET EARNINGS (LOSS) PER SHARE – DILUTED
COMPREHENSIVE INCOME (LOSS) PER SHARE – BASIC
COMPREHENSIVE INCOME (LOSS) PER SHARE – DILUTED
See accompanying notes to these financial statements.
Note
2015
2014
18
19
6
17
9
8
16
16
17
17
17
17
183,878
328
184,206
55,215
3,302
3,905
14,199
4,270
101,150
183
182,224
1,982
(355)
11,417
11,062
(9,080)
(2,519)
296
-
-
(2,223)
(11,303)
(0.28)
(0.28)
(0.35)
(0.35)
301,584
2,111
303,695
66,878
3,559
7,111
7,104
2,725
106,697
28
194,102
109,593
10,505
60,327
70,832
38,761
1,174
(147)
(1,102)
138
63
38,824
1.21
1.21
1.22
1.21
BONTERRA ANNUAL REPORT 2015
29
STATEMENT OF CASH FLOW
FOR THE YEARS ENDED DECEMBER 31
($ 000s)
OPERATING ACTIVITIES
Net earnings (loss)
Items not affecting cash
Deferred income taxes
Share-option compensation
Depletion and depreciation
Exploration and evaluation
Unwinding of the discount on decommissioning liabilities
15
Gain on sale of properties
Gain on sale of investments
Investment income
Interest expense
Change in non-cash working capital accounts:
Accounts receivable
Crude oil inventory
Prepaid expenses
Investment tax credit receivable
Accounts payable and accrued liabilities
Decommissioning expenditures
Interest paid
CASH PROVIDED BY OPERATING ACTIVITIES
FINANCING ACTIVITIES
Increase (decrease) in bank debt
Subordinated promissory note
Issuance of common shares by private placement
Share issue costs
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 properties
Purchase of investments
Proceeds on sale of investments
Acquisition
Change in non-cash working capital accounts:
Accounts payable and accrued liabilities
Accounts receivable
CASH USED IN INVESTING ACTIVITIES
NET CHANGE IN CASH IN THE YEAR
Cash, beginning of year
CASH, END OF YEAR
See accompanying notes to these financial statements.
15
8
9
5
Note
2015
2014
(9,080)
38,761
11,417
4,270
101,150
183
1,878
-
-
(251)
12,321
4,419
300
(370)
(261)
(5,597)
(187)
(12,321)
107,871
177,748
(15,000)
31,162
(105)
-
(63,607)
130,198
251
(479)
60,327
2,725
106,697
28
1,361
(671)
(1,102)
(56)
5,743
8,411
(258)
(786)
6,646
1,922
(1,652)
(5,743)
222,353
(2,041)
15,000
-
-
37,911
(113,007)
(62,137)
56
(402)
(58,019)
(155,262)
-
(12,221)
8,130
(170,430)
(5,763)
462
1,152
(1,527)
1,539
-
(4,344)
(1,428)
(238,069)
(160,216)
-
-
-
-
-
-
30
BONTERRA ANNUAL REPORT 2015
STATEMENT OF CHANGES IN EQUITY
FOR THE YEARS ENDED
($ 000s, except number of shares outstanding)
Number
of shares
outstanding
(Note 17)
Share
capital
(Note 17)
JANUARY 1, 2014
31,322,171
685,898
Share-option compensation
Share issuance
Exercise of options
Transfer to share capital on
exercise of options
Comprehensive income
Dividends
18,000
1,104
829,452
37,911
4,021
(4,021)
DECEMBER 31, 2014
32,169,623
728,934
Share-option compensation
11,495
4,270
Share issuance, private placement
973,812
31,162
Share issue costs, net of tax
Comprehensive loss
Transfer of realized gain on
investments
Deferred taxes on realized gain on
investments
Dividends
(76)
Accumulated
other
comprehensive
income(2)
3,761
Retained
earnings
(deficit)
(34,809)
Contributed
surplus(1)
12,791
2,725
Total
shareholders’
equity
667,641
2,725
1,104
37,911
-
38,824
(113,007)
635,198
4,270
31,162
(76)
63
3,824
38,761
(113,007)
(109,055)
(2,223)
(9,080)
(11,303)
(1,191)
1,191
-
161
(63,607)
161
(63,607)
595,805
DECEMBER 31, 2015
33,143,435
760,020
15,765
571
(180,551)
(1) Contributed surplus includes all amounts related to share-based payments.
(2) Accumulated other comprehensive income comprises of unrealized gains and losses on investments measured at fair value.
See accompanying notes to these financial statements.
BONTERRA ANNUAL REPORT 2015
31
NOTES TO THE FINANCIAL STATEMENTS
As at and for the years ended December 31, 2015, and 2014.
1. NATURE OF BUSINESS AND SEGMENT INFORMATION
Bonterra Energy Corp. (Bonterra or the Company) is a public company listed on the Toronto Stock Exchange (the TSX)
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).
The financial statements were authorized for issue by the Company’s Board of Directors on March 17, 2016.
B) 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.
C) FUNCTIONAL AND PRESENTATION CURRENCY
The Company’s functional and presentation currency is the Canadian dollar.
Foreign currency denominated 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.
D) 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. See Note 4 for more information.
E) ADOPTED ACCOUNTING PRONOUNCEMENTS
As of January 1, 2015, the Company adopted the following new accounting pronouncement, in accordance with the transitional
provision of the standard. A brief description of the new accounting policy and its impact on the Company’s financial statements
is as follows:
IFRS 9 “Financial Instruments”
Effective January 1, 2015 the Company adopted IFRS 9 “Financial Instruments”. IFRS 9 replaces the sections of IAS 39 “Financial
Instruments: Recognition and Measurements” that relates to the classification and measurement of financial instruments and
hedge accounting.
IFRS 9 replaces the multiple classification and measurement models for financial assets with a new model that only has two
measurement categories; amortized cost and fair value through profit or loss or other comprehensive income (loss). This
determination is made at initial recognition. As a result of adopting IFRS 9, the Company’s accounts receivables were reclassified
from loans and receivables at amortized cost to financial assets at amortized cost. For financial liabilities, the new standard
32
BONTERRA ANNUAL REPORT 2015
retains most of the IAS 39 requirements. The main change arises in cases where the Company chooses to designate a financial
liability as fair value through net earnings. In these situations, the portion of the fair value change related to the Company’s own
credit risk is recognized in other comprehensive income (loss) rather than net earnings. The Company has no financial liabilities
that are measured at fair value through net earnings.
The classification of the Company’s investments changed from available-for-sale to financial assets measured at fair value. On
the day an investment is acquired the Company can make an irrevocable election (on an instrument by instrument basis) to
designate investments in equity instruments as at fair value through other comprehensive income (FVTOCI), provided those
investments are not classified as held for trading. The Company’s investments will be measured at FVTOCI, with gains or losses
arising from changes in fair value recognized in other comprehensive income and accumulated in the fair value instrument. The
cumulative gain or loss will not be reclassified to profit or loss on disposal of the investments. The Company has designated all of
its investments and its investment in a related party as FVTOCI on its initial adoption of IFRS 9.
F) FUTURE ACCOUNTING PRONOUNCEMENTS
In May 2014, the IASB issued IFRS 15 “Revenue from Contracts with Customers,” which replaces IAS 18 “Revenue,” IAS 11
“Construction Contracts,” and related interpretations. This standard is required to be adopted either retrospectively or using a
modified transition approach for fiscal years beginning on or after January 1, 2018, with earlier adoption permitted. The Company
has not yet assessed the impact, if any, that the new amended standard will have on its financial statements or whether to early
adopt this new requirement.
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 for 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 party
disclosure Notes 7 and 12).
B) JOINT ARRANGEMENTS
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 through contractual arrangements 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 its interest in assets that it owns, the liabilities and expenses that it incurs and its share of income earned by the
joint arrangement.
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. The Company’s investments are measured as fair
value through other comprehensive income (FVTOCI), with gains or losses arising from changes in fair value recognized in other
comprehensive income and accumulated in the fair value instrument. The cumulative gain or loss will not be reclassified to profit
or loss on disposal of the investments. 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.
E) EXPLORATION AND EVALUATION ASSETS
General exploration and 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
BONTERRA ANNUAL REPORT 2015
33
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 annually, upon transfer to PP&E assets or whenever indications of impairment exist to ensure they are
not at amounts above their recoverable amounts.
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 proved plus probable developed reserve life. Proved plus probable developed reserves are
determined annually by qualified independent reserve engineers. Changes in factors such as estimates of proved plus probable
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 in 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 (loss). Production facilities, furniture, fixtures
and other equipment are depreciated over the individual assets’ estimated economic lives, less estimated salvage value of the
assets at the end of their useful lives.
These assets are depreciated on a declining balance method as follows:
Production facilities
10 percent per year
Furniture, fixtures and other equipment
10 percent to 20 percent per year
G) BUSINESS COMBINATIONS AND GOODWILL
The purchase price used in a business combination is based on the fair value at the date of acquisition. The business combination
is accounted for based on the fair value of the assets acquired and liabilities assumed. All acquisition costs are expensed as
incurred. Contingent liabilities are recognized at fair value at the date of the acquisition, and subsequently re‐measured at each
reporting period until settled. The excess of cost over fair value of the net assets and liabilities acquired is recorded as goodwill.
H) 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 flow 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 flow discounted
at the original effective interest rate. 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.
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 fair value through other comprehensive income
(FVTOCI) is reversed through other comprehensive income instead of net earnings. For financial assets measured at amortized
cost, the reversal is recognized in net earnings.
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, PP&E and Goodwill) are grouped together into the smallest
group of assets that generates cash flows from continuing use that are largely independent of the cash flow of other assets or
34
BONTERRA ANNUAL REPORT 2015
groups of assets (the cash-generating unit or CGU). Goodwill is allocated to the CGU expected to benefit from the synergies of the
combination. 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). The Company has a core CGU composed of its Alberta properties and secondary CGUs for its British Columbia (BC)
and Saskatchewan properties.
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 (loss). 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.
In respect of assets other than goodwill, impairment losses recognized in prior periods are assessed at each reporting date for
any indications that the impairment loss has reversed. If the amount of the impairment loss reverses in a subsequent period and
the reversal 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 and recorded in the statement of comprehensive income
(loss). An impairment loss in respect of goodwill cannot be reversed.
I) 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 decommissioning liabilities, 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
liability 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 any remaining balance of actual costs is recorded in the statement of
comprehensive income (loss).
J) INCOME TAXES
Tax expense comprises current and deferred taxes. Tax is recognized in the statement of comprehensive income (loss) 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. 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 period end 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 or liability.
BONTERRA ANNUAL REPORT 2015
35
K) SHARE-OPTION COMPENSATION
The Company accounts for share-option compensation using the fair-value method of accounting for stock options granted
to directors, officers, employees and other service providers using the Black-Scholes option pricing model. Share-option
compensation is recognized through the statement of comprehensive income (loss) 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 (loss). 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.
Employees may elect to have the Company settle any or all options vested and exercisable using a cashless equity settlement.
In connection with any such exercise, an employee shall be entitled to receive, without any cash payment (other than the taxes
required to be paid in connection with the exercise), whole shares of the Company. The number of shares under option multiplied
by the difference of the fair value at the time of exercise less the option exercise price, divided by the fair value at the time of
exercise, determines the number of whole shares issued.
L) FINANCIAL INSTRUMENTS
The Company classifies its financial instruments into one of the following categories: financial assets at amortized cost, financial
liabilities at amortized costs; and fair value through profit or loss. All financial instruments are measured at fair value on initial
recognition. Measurement in subsequent periods is dependent on the classification of the respective financial instrument.
Fair value through profit or loss financial instrument are subsequently measured at fair value with changes in fair value
recognized in net earnings. All other categories of financial instrument are measured at amortized cost using the effective interest
rate method.
Cash, account receivables and certain other long-term assets are classified as financial assets at amortized cost since it is the
Company’s intention to hold these assets to maturity and the related cash flows are mainly payments of principle and interest.
The Company’s investments are measured at fair value through other comprehensive income (FVTOCI), with gains or losses
arising from changes in fair value recognized in other comprehensive income and accumulated in the fair value instrument.
The cumulative gain or loss will not be reclassified to profit or loss on disposal of the investments. Accounts payable, accrued
liabilities, and certain other long-term liabilities and long-term debt are classified as financial liabilities at amortized cost. Risk
management assets and liabilities are classified as fair value through profit or loss.
M) FAIR VALUE MEASUREMENT
Financial instruments consisting of accounts receivable, accounts payable and accrued liabilities, due to related party, 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 investments are transacted in active markets. Bonterra determines 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.
N) 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.
36
BONTERRA ANNUAL REPORT 2015
O) NET EARNINGS AND COMPREHENSIVE INCOME PER SHARE
Per share amounts are calculated by dividing the net earnings or comprehensive income (loss) 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. SIGNIFICANT ACCOUNTING ESTIMATES AND JUDGMENTS
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 (PP&E) and goodwill are aggregated into cash generating units (CGUs) based on their ability
to generate largely independent cash flows and are assessed for impairment. CGUs have been determined based on similar
geological structure, shared infrastructure, geographical proximity, commodity type, and similar market 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 PP&E. The determination of the Company’s CGUs is subject to
management’s judgment. The Company has a core CGU composed of its Alberta properties and secondary CGUs for its BC and
Saskatchewan properties.
The recoverable amount of E&E, PP&E, and goodwill is determined based on the fair value less costs of disposal using a discounted
cash flow model and is assessed at the CGU level. The period the Company used to project cash flows is approximately 50 years
or the CGU’s reserve life. Growth in cash flow from a single well would be determined based on the extent of total reserves
assigned, which is produced at declining rates over the estimated reserve life. The fair value measurement of the Company’s E&E,
PP&E, and goodwill is designated Level 3 on the fair value hierarchy.
For the year ended December 31, 2015, the Company performed an impairment test on all of its CGUs for any potential impairment
or related recovery. In making these evaluations, the Company uses the following information:
1) The net present value of the pre-tax cash flows from oil and gas reserves of each CGU based on reserves estimated by the
Company’s independent reserve evaluator; and
2) Key input estimates used in the determination of cash flows from oil and gas reserves include the following:
a) Reserves – Assumptions that are valid at the time of reserve estimation may change significantly when new information
becomes available. Changes in forward price estimates, production costs or recovery rates may change the economic status
of reserves and may ultimately result in reserves being restated.
b) Crude oil and natural gas prices – Forward price estimates of the crude oil and natural gas prices are used in the cash flow
model. Commodity prices used tend to be stable because short-term increases or decreases in prices are not considered
indicative of long-term price levels, but nonetheless subject to change and the change could be material.
c) Discount rate – The Company uses a pre-tax discount rate of 10 percent that reflects risks specific to the assets for which
the future cash flow estimates have not been adjusted. The discount rate was determined based on the Company’s
assessment of risk based on past experience. Changes in the general economic environment could result in material changes
to this estimate.
BONTERRA ANNUAL REPORT 2015
37
The following table from external sources outlines the forecast benchmark commodity prices used in the impairment calculation
as at December 31, 2015:
WTI Crude oil $US per Bbl(1)
AECO C-Spot $ per Mmbtu(1)
Exchange rate $US per $Cdn
2016
45.00
2.25
0.75
2017
2018
2019
60.00
70.00
80.00
2.95
0.80
3.42
0.83
3.91
0.85
2020
81.20
4.20
0.85
2021
82.42
4.28
0.85
2022
83.65
4.35
0.85
2023
84.91
4.43
0.85
2024
86.18
4.51
0.85
2025
87.48
4.59
0.85
2026(2)
88.79
4.67
0.85
(1) The forecast benchmark commodity prices listed above are adjusted for quality differentials, heat content, transportation and marketing costs and other factors
specific to the Company’s operations in performing the Company’s impairment tests.
(2) Forecast benchmark commodity prices are assumed to increase by 1.5% in each year after 2026 to the end of the reserve life.
With the current key assumptions listed above, the Company performed impairment tests for each CGU and concluded that no
reasonable change in the key assumptions, such as a five percent change in commodity prices or a one percent change in the
discount rate, would result in an impairment being recorded. For the years ended December 31, 2015 and 2014 no impairment
losses were recorded in the statement of comprehensive income (loss).
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.
RISK MANAGEMENT CONTRACT
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 net earnings as unrealized gains or losses on risk management contracts. Fair
values of financial instruments are based on third party futures quotes for commodities. Any realized gains or losses on risk
management contracts are recognized in net earnings in the period they occur.
SHARE-OPTION COMPENSATION
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 based on cost estimates which can vary in response to many
factors including timing of abandonment, inflation, changes in legal requirements, new restoration techniques and interest rates.
INCOME TAXES
The Company recognizes the net deferred tax benefit or expense related to deferred income tax assets or liabilities to the extent
that it is probable that the deductible temporary differences will reverse in the foreseeable future. Assessing the recoverability
of 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 disclosed in Note 3.
5. ACQUISITION
On April 15, 2015, the Company acquired Cardium focused oil and gas assets in the Pembina area of Alberta, including upper
zones (the Pembina Assets) that are complimentary to its existing Cardium oil and gas asset base. Cash consideration for these
assets was $170,430,000. The results of the Pembina Assets have been included in these financial statements since that date.
The Pembina Assets contributed oil and gas sales, net of royalties, of $20,667,000 and operating expenses of $10,448,000 for the
period from April 15, 2015 to December 31, 2015. If the acquisition had occurred on January 1, 2015, total oil and gas sales, net of
38
BONTERRA ANNUAL REPORT 2015
royalties, would have been approximately $28,127,000 and the total production costs would have been approximately $14,761,000
for the year ended December 31, 2015.
The acquisition has been accounted for using the acquisition method, and the purchase price was allocated to the assets acquired
and the liabilities assumed as follows:
Net assets acquired:
Property, plant and equipment
Decommissioning liabilities
Total
Consideration:
Cash
Total purchase price
6. FINANCE COSTS
($ 000s)
173,111
(2,681)
170,430
170,430
170,430
A breakdown of finance costs for the years ended:
($ 000s)
Interest expense on bank debt
Interest expense on amounts owing to related party
Interest expense on subordinated promissory note and other
Unwinding of the fair value of decommissioning liabilities
DECEMBER 31,
2015
December 31,
2014
10,390
261
1,670
1,878
14,199
4,283
285
1,175
1,361
7,104
7. INVESTMENT IN RELATED PARTY
The investment consists of 1,034,523 (December 31, 2014 – 1,034,523) common shares in Pine Cliff Energy Ltd. (Pine Cliff), a
company with some common directors and some common management with Bonterra. The investment in Pine Cliff represents
less than one percent ownership in the outstanding common shares of Pine Cliff and is recorded at fair value through other
comprehensive income. The common shares of Pine Cliff trade on the TSX under the symbol PNE.
In addition, Pine Cliff owns 204,633 (December 31, 2014 – 204,633) common shares in Bonterra.
8. EXPLORATION AND EVALUATION ASSETS
($ 000s)
COST AND CARRYING AMOUNT
Balance at January 1, 2014
Additions
Dispositions
Expiry of exploration and evaluation assets
BALANCE AT DECEMBER 31, 2014
Additions
Expiry of exploration and evaluation assets
BALANCE AT DECEMBER 31, 2015
7,674
402
(419)
(28)
7,629
479
(183)
7,925
In January 2014, the Company sold a portion of its undeveloped land in the Willesden Green area for cash proceeds of $1,000,000.
At the time of disposition, the Company had a carrying value of $419,000 for these exploration and evaluation expenditures,
resulting in a gain on sale of $581,000.
BONTERRA ANNUAL REPORT 2015
39
9. PROPERTY, PLANT AND EQUIPMENT
COST
($ 000s)
Balance at January 1, 2014
Additions
Adjustment to decommissioning liabilities(1)
Disposals
BALANCE AT DECEMBER 31, 2014
Additions
Acquisition
Adjustment to decommissioning liabilities(1)
BALANCE AT DECEMBER 31, 2015
OIL AND GAS
PROPERTIES
PRODUCTION
FACILITIES
FURNITURE,
FIXTURES
& OTHER
EQUIPMENT
TOTAL
PROPERTY,
PLANT &
EQUIPMENT
892,166
119,635
16,721
(2)
1,028,520
42,093
138,711
13,359
215,950
36,633
-
(62)
252,521
15,860
34,400
-
1,940
47
-
-
1,987
66
-
-
1,110,056
156,315
16,721
(64)
1,283,028
58,019
173,111
13,359
1,222,683
302,781
2,053
1,527,517
ACCUMULATED DEPLETION AND DEPRECIATION
($ 000s)
OIL AND GAS
PROPERTIES
PRODUCTION
FACILITIES
Balance at January 1, 2014
Depletion and depreciation
Disposal and other
BALANCE AT DECEMBER 31, 2014
Depletion and depreciation
Disposal and other
(217,522)
(88,001)
(219)
(305,742)
(84,800)
57
(55,278)
(18,588)
-
(73,866)
(16,250)
-
FURNITURE,
FIXTURES
& OTHER
EQUIPMENT
TOTAL
PROPERTY,
PLANT &
EQUIPMENT
(1,321)
(108)
-
(1,429)
(100)
-
(274,121)
(106,697)
(219)
(381,037)
(101,150)
57
BALANCE AT DECEMBER 31, 2015
(390,485)
(90,116)
(1,529)
(482,130)
CARRYING AMOUNTS AS AT:
($ 000s)
December 31, 2014
DECEMBER 31, 2015
722,778
832,198
178,655
212,665
558
524
901,991
1,045,387
(1) Adjustment to decommissioning liabilities is due to a decrease in the risk free rate and changes in estimated decommissioning costs (see Note 15).
10. GOODWILL
The amount recorded as goodwill has all been allocated to the primary CGU, Alberta, Canada. There was no impairment loss
recorded in the statement of comprehensive income (loss) for the years ended December 31, 2015 and 2014.
11. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
($ 000s)
Accounts payable
Accrued liabilities
DECEMBER 31,
2015
December 31,
2014
15,130
5,349
20,479
15,170
16,669
31,839
12. TRANSACTIONS WITH RELATED PARTIES
As at December 31, 2015, the Company’s CEO, Chairman of the Board and major shareholder has a loan with the Company of
$12,000,000 (December 31, 2014 – $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 2015 was $261,000 (December 31, 2014 – $285,000).
40
BONTERRA ANNUAL REPORT 2015
The Company received a management fee of $60,000 plus the reimbursement of certain administrative expenses for the year
ended December 31, 2015 (December 31, 2014 – $60,000) for management services and office administration from Pine Cliff.
This fee has been included in other income. As at December 31, 2015, the Company had an account receivable from Pine Cliff for
these management fees and the reimbursement of certain administration expense of $293,000 (December 31, 2014 – $316,000).
COMPENSATION FOR KEY MANAGEMENT PERSONNEL
($ 000s)
Compensation
Share-based payments
Total compensation
DECEMBER 31,
2015
December 31,
2014
1,407
1,595
3,002
2,272
1,120
3,392
Key management personnel are those persons, including all directors, having authority and responsibility for planning, directing
and controlling the activities of the Company.
13. SUBORDINATED PROMISSORY NOTE
As at December 31, 2015, Bonterra had $25,000,000 (December 31, 2014 – $40,000,000) owed on a subordinated note to a private
investor. The terms of the subordinated promissory note are that it bears interest at three percent and is repayable after thirty
days’ written notice by either party. Security consists of a floating demand debenture of $25,000,000 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 $974,000 (December 31, 2014 – $1,175,000).
On January 22, 2016, the Company repaid $10,000,000.
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.
14. BANK DEBT
As at December 31, 2015, the Company has bank facilities consisting of a $375,000,000 (December 31, 2014 – $220,000,000)
syndicated revolving credit facility and a $50,000,000 (December 31, 2014 – $30,000,000) non-syndicated revolving credit facility,
for total credit facilities of $425,000,000. Amounts drawn under the credit facilities at December 31, 2015 were $332,471,000
(December 31, 2014 – $154,723,000). Amounts borrowed under the credit facilities bear interest at a floating rate based on the
applicable Canadian prime rate 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 provided by operating activities. The
terms of the revolving credit facilities provided that the loan is revolving to April 29, 2016, with a maturity date of April 30, 2017
and is subject to annual review. The credit facilities have no fixed terms of repayment.
The available lending limits of the credit facilities are reviewed semi-annually on or before April 30 and October 31 each year based
on the lender’s interpretation of the Company’s reserves, future commodity prices and costs.
The amount available for borrowing under the credit facilities is reduced by outstanding letters of credit. Letters of credit totaling
$1,950,000 were issued as at December 31, 2015 (December 31, 2014 – $700,000). Security for credit facilities consists of various
and floating demand debentures totaling $750,000,000 (December 31, 2014 – $400,000,000) 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 covenants on the credit facilities:
• The Company cannot exceed $425,000,000 in consolidated debt (includes working capital but excludes amounts due to related
parties and the subordinated promissory note).
• Dividends paid in the current quarter shall not exceed 80 percent of the available cash flow for the preceding four fiscal quarters
divided by four, which is calculated as 51 percent for the current quarter ended December 31, 2015.
Available cash flow is defined to be cash provided by operating activities excluding the change in non-cash working capital and
decommissioning liabilities settled and including investment income received and all net proceeds of dispositions included in
cash used in investing activities. At December 31, 2015, the Company is in compliance with all covenants.
BONTERRA ANNUAL REPORT 2015
41
15. DECOMMISSIONING LIABILITIES
At December 31, 2015, the estimated total undiscounted amount required to settle the decommissioning liabilities was
$232,413,000 (December 31, 2014 – $177,441,000). The provision has been calculated assuming a 1.5 percent inflation rate
(December 31, 2014 – 1.5 percent inflation rate). These obligations will be settled at the end of the useful lives of the underlying
assets, which extend up to 50 years into the future. This amount has been discounted using a risk-free interest rate of 2.9 percent
(December 31, 2014 – 2.9 percent).
Changes to decommissioning liabilities were as follows:
($ 000s)
Decommissioning liabilities, January 1
Acquisition (Note 5)
Adjustment to decommissioning liabilities(1)
Liabilities settled during the year
Unwinding of the discount on decommissioning liabilities
Decommissioning liabilities, end of year
DECEMBER 31,
2015
December 31,
2014
53,792
2,681
13,359
(187)
1,878
71,523
37,362
-
16,721
(1,652)
1,361
53,792
(1) Adjustment to decommissioning liabilities is due to a change in the risk free rate and estimated decommissioning costs.
16. INCOME TAXES
($ 000s)
Deferred tax asset (liability) related to:
Investments
Exploration and evaluation assets and property, plant and equipment
Investment tax credits
Decommissioning liabilities
Corporate tax losses carried forward
Share issue costs
Corporate capital tax losses carried forward
Unrecorded benefit of capital tax losses carried forward
Deferred tax asset (liability)
DECEMBER 31,
2015
December 31,
2014
(110)
(566)
(148,961)
(126,199)
(2,385)
19,311
4,983
737
9,138
(9,028)
(3,808)
13,459
-
1,162
8,617
(8,051)
(126,315)
(115,386)
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:
Change in statutory tax rates(1)
Stock-option compensation
Realized gain on sale of investments
Effect of Agreement
Change in estimates and other
Income tax expense
DECEMBER 31,
2015
December 31,
2014
1,982
26.01%
515
8,490
1,110
161
-
786
11,062
109,593
25.02%
27,420
-
682
-
43,503
(773)
70,832
(1) Effective July 1, 2015 the combined federal and provincial income tax rate for Bonterra is approximately 27.00% due to the provincial tax rate for Alberta, Canada
increasing from 10% to 12%.
42
BONTERRA ANNUAL REPORT 2015
The Company has the following tax pools, which may be used to reduce taxable income in future years, limited to the applicable
rates of utilization:
($ 000s)
Undepreciated capital costs
Eligible capital expenditures
Share issue costs
Canadian oil and gas property expenditures
Canadian development expenditures
Canadian exploration expenditures
Income tax losses carried forward(1)
(1) Income tax losses carried forward expire in 2035.
Rate of
Utilization (%)
20-100
7
20
10
30
100
100
Amount
112,723
2,414
2,729
179,037
197,794
8,063
18,439
521,199
The Company has $8,834,000 (December 31, 2014 – $8,573,000) of investment tax credits that expire in the following years;
2021 – $1,824,000; 2022 – $1,735,000; 2023 – $1,097,000; 2024 – $1,241,000; 2025 – $1,323,000; 2026 – $1,105,000; 2027 –
$410,000; and 2035 – $99,000.
The Company has $67,691,000 (December 31, 2014 - $68,881,000) of capital losses carried forward which can only be claimed
against taxable capital gains.
On November 14, 2013, the Company received a proposal letter from the Canada Revenue Agency (CRA) which stated its intention
to challenge the tax consequences of Bonterra’s reorganization from a trust to a Corporation, which occurred on November 18,
2008. On November 27, 2014, the Company reached an agreement with CRA (the Agreement) to adjust certain tax pools, resulting
in a $43,503,000 reduction in the Company’s deferred tax assets and investment tax credit receivable. The reduction was charged
to deferred tax expense in the statement of comprehensive income (loss). Of the $10,505,000 current tax provision for 2014
fiscal year, $6,645,000 of the federal investment tax credit receivable was used to reduce current taxes payable to $3,860,000. No
current taxes are owing for the 2015 fiscal year.
17. SHAREHOLDERS’ EQUITY
AUTHORIZED
The Company is authorized to issue an unlimited number of common shares without nominal or par value.
DECEMBER 31, 2015
December 31, 2014
Issued and fully paid – common shares
Balance, beginning of year
Share issuance, private placement
Share issue costs, net of tax
Issued pursuant to the Company's share option plan
Transfer from contributed surplus to share capital
Shares issued for oil and gas properties
NUMBER
32,169,623
973,812
-
-
AMOUNT
($ 000s)
728,934
31,162
(76)
-
-
-
Number
31,322,171
-
829,452
18,000
Balance, end of year
33,143,435
760,020
32,169,623
Amount
($ 000s)
685,898
-
-
37,911
4,021
1,104
728,934
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.
On July 8, 2015, the Company closed a private placement of 973,812 common shares to existing shareholders at a price of $32.00
per share, for aggregate proceeds of approximately $31,162,000. The Company incurred issue costs of approximately $105,000
in respect of the offering.
BONTERRA ANNUAL REPORT 2015
43
The weighted average common shares used to calculate basic and diluted net earnings per share for the year ended December 31
is as follows:
Basic shares outstanding
Dilutive effect of share options(1)
Diluted shares outstanding
DECEMBER 31,
2015
December 31,
2014
32,641,855
31,921,623
-
114,022
32,641,855
32,035,645
(1) The Company did not include 2,955,500 share options (December 31, 2014 – 1,100,000) in the dilutive effect of share options calculation as these share options
were anti-dilutive.
For the year ended December 31, 2015, the Company declared and paid dividends of $63,607,000 ($1.95 per share) (December 31,
2014 – $113,007,000 ($3.54 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 3,314,344 (December 31, 2014 – 3,216,962) 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.
A summary of the status of the Company’s stock option plan as of December 31, 2015, and changes during the period ended on
those dates is presented below:
At January 1, 2014
Options granted
Options exercised
Options cancelled
Options forfeited
At December 31, 2014
Options granted
Options expired
AT DECEMBER 31, 2015
NUMBER
OF OPTIONS
WEIGHTED
AVERAGE
EXERCISE
PRICE
1,650,500
$
1,769,000
(904,000)(1)
(194,000)
(210,000)
2,111,500
$
1,772,500
(928,500)
2,955,500
$
48.31
56.48
47.09
49.09
55.01
54.94
28.15
50.46
40.28
(1) 93,000 options were exercised under the cashless option method, which resulted in 18,452 shares being issued in which the Company received no proceeds.
The following table summarizes information about options outstanding at December 31, 2015:
Options Outstanding
Options Exercisable
Number
outstanding at
December 31,
2015
807,000
965,500
1,183,000
2,955,500
Weighted-average
remaining
contractual life
Weighted-average
exercise price
1.7 years
$
1.8 years
0.8 years
1.4 years
$
20.46
34.57
58.46
40.28
Number
exercisable at
December 31,
2015
Weighted-average
exercise price
$
-
-
164,000
164,000
$
-
-
51.52
51.52
Range of exercise prices
$ 20.00 – $ 30.00
30.01 – 40.00
40.01 – 65.00
$ 20.00 – $ 65.00
44
BONTERRA ANNUAL REPORT 2015
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 2015, the Company granted 1,772,500 stock options
with an estimated fair value of $6,523,000 or $3.68 per option using the Black-Scholes option pricing model with the following
key assumptions:
Weighted-average risk free interest rate (%)(1)
Expected life (years)
Weighted-average volatility (%)(2)
Forfeiture rate (%)
Weighted average dividend yield (%)
DECEMBER 31,
2015
December 31,
2014
0.48
1.5
39.93
9.24
6.84
1.04
1.5
17.63
5.00
5.66
(1) Risk-free interest rate is based on the weighted average Government of Canada benchmark bond yields for one, two, and three year terms to match corresponding
vesting periods.
(2) The expected volatility is measured as the standard deviation of expected share price returns based on statistical analysis of historical weekly share prices for a
representative period.
18. OIL AND GAS SALES, NET OF ROYALTIES
($ 000s)
Oil and gas sales
Less:
Crown royalties
Freehold, gross overriding royalties and other
Oil and gas sales, net of royalties
19. OTHER INCOME
($ 000s)
Investment income
Administrative income
Gain on sale of properties
Realized gain on investments
Other income
DECEMBER 31,
2015
December 31,
2014
197,239
339,694
(8,007)
(5,354)
183,878
(23,779)
(14,331)
301,584
DECEMBER 31,
2015
December 31,
2014
251
77
-
-
328
56
282
671
1,102
2,111
20. 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 party
• 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
BONTERRA ANNUAL REPORT 2015
45
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.
The Company monitors capital on the basis of the ratio of net debt (total debt adjusted for working capital) to cash flow from
operating activities. This ratio is calculated using each quarter end net debt and divided by the preceding twelve months cash
flow. Management believes that a net debt level as high as one and a half year’s cash flow is still 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 did not meet its annual guidance with a net debt
to cash flow level of 3.4:1. The increase in net debt to cash flow ratio is primarily due to the acquisition of the Pembina Assets
(see acquisition Note 5) and low commodity prices realized in 2015. To manage its bank debt during a period of low commodity
prices the Company significantly reduced planned capital expenditures for the 2015 fiscal year and in February 2015 reduced the
monthly dividend by $0.15 per common share. In January of 2016 the Company reduced the monthly dividend by a further $0.05
to $0.10 per common share. In addition the Company raised approximately $31 million in equity by way of a private placement
(see shareholders’ equity Note 17).
Section (a) of this note provides the Company’s debt to cash flow from operations.
Section (b) addresses in more detail the key financial risk factors that arise from the Company’s activities including its policies for
managing these risks.
a) Net Debt Ratio
The net debt and cash flow amounts as of December 31, 2015 are as follows:
($ 000s)
Bank debt
Accounts payable and accrued liabilities
Due to related party
Subordinated promissory note
Current assets
Net debt
Cash flow from operations
Net debt to annual cash flow from operations
b) Risks and Mitigation
332,471
20,479
12,000
25,000
(27,675)
362,275
107,871
3.4
Market risk is the risk that the fair value or future cash flow of the Company’s financial instruments will fluctuate because of
changes in market prices. Components of market risk to which the Company is exposed are discussed below.
COMMODITY PRICE RISK
The Company’s principal operation is the production and sale of crude oil, natural gas and natural gas liquids. Fluctuations in
prices of these commodities directly impact the Company’s performance and ability to continue with its dividends.
The Company has used various risk management contracts to set price parameters for a portion of its production. Management,
in agreement with the Board of Directors, decided that at least in the near term, it will discontinue the use of commodity price
agreements. The Company will assume full risk in respect of commodity prices.
INTEREST RATE RISK
Interest rate risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument will
fluctuate due to changes in market interest rates. Interest rate risk arises from interest bearing financial assets and liabilities that
the Company uses. The principal exposure of the Company is on its borrowings which have a variable interest rate which gives
rise to a cash flow interest rate risk.
46
BONTERRA ANNUAL REPORT 2015
The Company’s debt facilities consist of a $375,000,000 syndicated revolving operating line, $50,000,000 non-syndicated
operating line, $12,000,000 due to a related party and a $25,000,000 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 $2,515,000.
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.
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 US 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 $15,433,000 accounts receivable balance at December 31, 2015 (December 31, 2014 – $20,314,000) over 83 percent
(2014 – 80 percent) relates to product sales with national and international oil and gas companies.
The Company assesses quarterly if there has been any impairment of the financial assets of the Company. During the year ended
December 31, 2015, there was no material impairment provision required on any of the financial assets of the Company. The
Company does have a credit risk exposure as the majority of the Company’s accounts receivable are with counterparties having
similar characteristics. However, payments from the Company’s largest accounts receivable counterparties have consistently
been received within 30 days and the sales agreements with these parties are cancellable with 30 days’ notice if payments are
not received.
At December 31, 2015, approximately $1,077,000 or seven percent of the Company’s total accounts receivable are aged over
90 days and considered past due (December 31, 2014 – $2,948,000 or 14.5 percent). 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, 2015 is $365,000 (December 31, 2014 – $308,000) with the expense being included
in general and administrative expenses. There were no material accounts written off during the period.
The maximum exposure to credit risk is represented by the carrying amounts of accounts receivable. There are no material
financial assets that the Company considers past due.
BONTERRA ANNUAL REPORT 2015
47
LIQUIDITY RISK
Liquidity risk includes the risk that, as a result of the Company’s operational liquidity requirements:
• The Company will not have sufficient funds to settle a transaction on the due date;
• The Company will not have sufficient funds to continue with its dividends;
• The Company will be forced to sell assets at a value which is less than what they are worth; or
• The Company may be unable to settle or recover a financial asset at all.
To help reduce these risks the Company maintains bank facilities determined by a portfolio of high-quality, long reserve life oil and
gas assets.
The Company has the following maturity schedule for its financial liabilities and commitments:
($ 000s)
Accounts payable and accrued liabilities
Due to related party
Subordinated promissory note
Bank debt
Firm service commitments
Office lease commitments
Total
21. COMMITMENTS
Recognized
on Financial
Statements
Yes – Liability
Yes – Liability
Yes – Liability
Yes – Liability
No
No
Less than
1 year
Over 1 year
to 9 years
20,479
12,000
25,000
-
-
-
-
332,471
1,165
941
59,585
6,430
1,230
340,131
The Company has entered into firm service gas transportation agreements in which the Company guarantees certain minimum
volumes of natural gas will be shipped on various gas transportation systems. The terms of the various agreements expire in one
to nine years. The Company has office lease commitments for building and office equipment. The building and office equipment
leases have an average remaining life of 2.3 years. There are no restrictions placed upon the lessee by entering into these leases.
Future minimum payments for the firm service gas transportation agreements using current tariff rates and the non-cancellable
building and office equipment leases as at December 31, 2015 are as follows:
($ 000s)
Firm service commitments
Office lease commitments
Total
2016
1,165
941
2,106
2017
1,061
922
1,983
2018
910
308
1,218
2019
875
-
875
2020
Thereafter
791
2,793
-
-
791
2,793
Total
7,595
2,171
9,766
22. SUBSEQUENT EVENTS
i) DIVIDENDS
Subsequent to December 31, 2015, the Company declared the following dividends:
Date declared
January 4, 2016
February 1, 2016
March 1, 2016
Record date
$ per share
Date payable
January 15, 2016
February 16, 2016
March 15, 2016
0.10
0.10
0.10
January 29, 2016
February 29, 2016
March 31, 2016
48
BONTERRA ANNUAL REPORT 2015
CORPORATE INFORMATION
BOARD OF DIRECTORS
G. F. Fink – Chairman
G. J. Drummond
R. M. Jarock
C. R. Jonsson
R. A. Tourigny
OFFICERS
G. F. Fink, CEO and Chairman of the Board
R. D. Thompson, CFO and Corporate Secretary
A. Neumann, Chief Operating Officer
B. A. Curtis, Vice President, Business Development
REGISTRAR AND TRANSFER AGENT
Computershare Trust Company of Canada, Calgary, Alberta
AUDITORS
Deloitte LLP, Calgary, Alberta
SOLICITORS
Borden Ladner Gervais LLP, Calgary, Alberta
BANKERS
CIBC, Calgary, Alberta
National Bank of Canada, Calgary, Alberta
TD Securities, Calgary, Alberta
J.P. Morgan, Calgary, Alberta
Alberta Treasury Branch, Calgary, Alberta
HEAD OFFICE
901, 1015 – 4th Street SW
Calgary, Alberta T2R 1J4
Telephone: 403.262.5307
Fax: 403.265.7488
Email: info@bonterraenergy.com
WEBSITE
www.bonterraenergy.com
BONTERRA ANNUAL REPORT 2015
49
BONTERRA ENERGY CORP.
901, 1015 - 4th Street SW
Calgary, Alberta, T2R 1J4
TELEPHONE
FAX
403.262.5307
403.265.7488
info@bonterraenergy.com
www.bonterraenergy.com
50
BONTERRA ANNUAL REPORT 2015