Highlights
Financial
($ thousands, except per share)
Production revenues
Funds from operations(1)
Per share(1) (2)
Dividends declared(3)
Per share
Net income
Per share(4)
Adjusted net income(5)
Per share(4)
Total assets
Long-term debt, net of working capital
Long-term debt, net of adjusted working capital(6)
Shareholders’ equity
Capital expenditures:
Exploration and development
Acquisitions, net of dispositions
ANNUAL REPORT
2013
Three months ended
December 31,
2013
2012
%
Change
Years ended
December 31,
2012
2013
%
Change
245,466
223,021
124,354
0.62
110,015
0.57
38,904
0.21
6,667
0.03
23,702
0.12
63,481
0.36
14,442
0.07
16,535
0.09
10%
13%
9%
(39%)
(42%)
(54%)
(57%)
43%
33%
964,312
832,491
16%
477,578
2.42
152,968
0.84
49,505
0.25
75,297
0.38
378,667
2.16
224,801
1.44
64,202
0.37
58,049
0.33
26%
12%
(32%)
(42%)
(23%)
(32%)
30%
15%
4,235,626
4,062,852
4%
1,155,764
963,678
20%
1,124,198
963,500
17%
2,270,015
2,285,889
(1%)
111,596
4,815
76,937
118,837
45%
(96%)
443,829
20,530
402,090
(10,956)
10%
287%
Weighted average outstanding equivalent shares: (thousands)
Basic
199,254
Diluted
201,756
(4)
192,638
194,322
3%
4%
197,296
199,340
175,581
176,747
12%
13%
Operating
(boe conversion – 6:1 basis)
Production:
Natural gas (mmcf/day)
Natural gas liquids (bbls/day)
Oil (bbls/day)(7)
Total oil equivalent (boe/day)
Product prices:(8)
Natural gas ($/mcf)
Natural gas liquids ($/bbl)
Oil ($/bbl)(7)
Operating expenses ($/boe)
General and administrative expenses ($/boe)
Cash costs ($/boe)(9)
Operating netback ($/boe)(10)
287
15,103
12,208
75,072
3.54
49.35
72.73
8.77
1.21
12.91
20.82
269
14,563
12,395
71,842
3.22
42.60
75.73
8.69
1.22
12.67
19.12
7%
4%
(2%)
4%
10%
16%
(4%)
1%
(1%)
2%
9%
278
15,093
12,039
73,406
3.35
47.61
79.32
8.93
1.15
13.00
20.54
253
14,074
12,997
69,250
2.60
45.19
77.30
9.07
1.10
10%
7%
(7%)
6%
29%
5%
3%
(2%)
5%
13.26
(2%)
17.70
16%
1
Highlights (cont’d)
Drilling (gross wells):
Natural gas
Oil
Average success rate
Land:
Undeveloped (net acres)
Total (net acres)
Reserves: (11)
Proved:
Natural gas (bcf)
Oil and natural gas liquids (mbbls)
Total oil equivalent (mboe)
Proved plus probable:
Natural gas (bcf)
Oil and natural gas liquids (mbbls)
Total oil equivalent (mboe)
% Proved producing
% Proved
% Probable
Net present value of future cash flow before income taxes ($ millions):
0% discount rate
5% discount rate
10% discount rate
15% discount rate
Reserve life index (years): (12)
Total proved
Total proved plus probable
Reserves (boe per thousand shares - basic):
Total proved
Total proved plus probable
Finding and development expenditures – proved plus probable ($/boe):
Including changes in future development expenditures
Excluding changes in future development expenditures
Finding, development and acquisition expenditures – proved plus probable ($/boe):
Including changes in future development expenditures
Excluding changes in future development expenditures
Recycle ratio – proved plus probable: (13)
Including changes in future development expenditures
Excluding changes in future development expenditures
Years ended December 31,
2013
128
58
68
98%
2012
115
47
67
99%
%
Change
11%
23%
1%
(1%)
1,281,191
2,891,947
1,253,141
2,832,701
2%
2%
3%
3%
3%
7%
7%
7%
(1%)
(3%)
3%
8%
10%
12%
13%
(5%)
(2%)
-
4%
(18%)
3%
(1%)
25%
19%
(8%)
950.4
97,822
256,216
1,472.0
153,195
398,529
39%
64%
36%
9,726
6,310
4,608
3,608
9.1
13.2
1,282
1,994
11.95
11.56
11.03
8.75
1.9
2.3
921.0
94,914
248,409
1,372.3
143,505
372,220
40%
67%
33%
9,005
5,742
4,126
3,183
9.6
13.5
1,283
1,924
14.66
11.23
11.16
6.98
1.6
2.5
NOTES:
(1) Management uses funds from operations to analyze operating performance, dividend coverage and leverage. Funds from operations as presented does not have any standardized meaning prescribed by
IFRS and therefore it may not be comparable with the calculations of similar measures for other entities. Funds from operations as presented is not intended to represent operating cash flow or operating
profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net income or other measures of financial performance calculated in accordance with IFRS. All
references to funds from operations throughout this report are based on cash flow from operating activities before changes in non-cash working capital, decommissioning expenditures and interest
expense. Funds from operations per share is calculated based on the weighted average number of shares outstanding consistent with the calculation of net income per share.
(2) Basic funds from operations per share calculations include exchangeable shares which are convertible into common shares on certain terms and conditions.
(3) Dividends declared includes both cash dividends and common shares issued pursuant to Bonavista's dividend reinvestment plan (DRIP) and Bonavista's stock dividend program (SDP). For the three
months ended December 31, 2013 approximately 1.2 million common shares were issued under the DRIP and SDP with an approximate value of $14.2 million. For the year ended December 31, 2013,
approximately 4.6 million common shares were issued under the DRIP and SDP with an approximate value of $59.2 million.
(4) Basic net income per share calculations include exchangeable shares which are convertible into common shares on certain terms and conditions.
(5) Amounts have been adjusted to exclude unrealized gains and losses on financial instrument commodity contracts.
(6) Amounts have been adjusted to exclude associated assets or liabilities from financial instrument commodity contracts and decommissioning liabilities.
(7) Oil includes light, medium and heavy oil.
(8) Product prices include realized gains and losses on financial instrument commodity contracts.
(9) Cash costs equal the total of operating, transportation, general and administrative, and financing expenses.
(10) Operating netback equals production revenues including realized gains and losses on financial instrument commodity contracts, less royalties, operating and transportation expenses, calculated on a boe
basis.
(11) Working interest reserves are gross reserves prior to deduction of royalties and without including any of Bonavista’s royalty interests.
(12) Calculated based on the amount for the relevant reserve category divided by the 2014 production forecast prepared by the independent reserve evaluator (GLJ).
(13) Recycle ratio is calculated using operating netback per boe divided by finding, development and acquisition expenditures per boe.
2
Share Trading Statistics
($ per share, except volume)
High
Low
Close
Average Daily Volume - Shares
MESSAGE TO SHAREHOLDERS
December 31,
2013
September 30,
2013
June 30,
2013
March 31,
2013
Three months ended
14.04
11.25
13.92
1,000,966
14.37
12.70
12.93
620,864
16.77
13.33
13.65
428,813
15.18
12.25
14.94
676,012
In 2013, Bonavista successfully executed on its commitment to maximize shareholder value demonstrated by a solid
year of performance as we validated the quality of our asset base and the capabilities of our team. As a key component
of our business plan, we demonstrated a 26% increase in our funds from operations over 2012, representing growth of
12% on a per share basis.
Improved natural gas prices and our focus on enhancing our operating and capital efficiencies were the primary sources
for this increase in funds from operations. This was evidenced by steadily lowering our cost of adding production to
approximately $21,000 per boe per day during the fourth quarter of 2013 from $32,500 per boe per day during the fourth
quarter of 2012, on a trailing 12 month basis. Additionally, our ability to improve our finding and development costs by
18% to $11.95 per boe (including changes in future development expenditures) and our finding, development and
acquisition costs to $11.03 per boe (including changes in future development expenditures) are a testament to this focus
on efficiency gains. Lastly, we achieved a two percent improvement in operating and cash costs and when included with
a seven percent increase in realized product prices, resulted in a year-over-year improvement in our recycle ratio to 1.9:1
from 1.6:1 in 2012.
These achievements were realized by focusing our attention in our West Central and Deep Basin core areas where we
have the opportunity and expertise to drive enhancements in our performance and execution. Our strategy has led to an
increased concentration of land, production and reserves in these multi-zone, prolific areas of the Western Canadian
Sedimentary Basin. As a result, a group of non-core assets which cannot compete for investment within these core
areas were rationalized for approximately $110.9 million as part of our concentration strategy.
Our business plan to maximize shareholder value is based upon a balanced approach of generating income and growth.
In 2013, we experienced a six percent increase in our production volumes while our dividend program delivered an
annualized yield of approximately six percent, collectively exceeding our total return goal. Our growth strategy is
centered on achieving total returns in excess of 10% at fixed commodity prices of $3.50 per gj for natural gas at AECO
and Cdn$95.00 per bbl WTI equivalent over the next five years. The continued success of this business plan will lie in
our ability to remain focused on continued improvements in both operating and capital efficiencies and our ability to
manage risk and safeguard our funds from operations through our hedging strategy.
The successful implementation of our business plan has led to multiple achievements during 2013, some of which are
outlined below.
Operational and Financial Accomplishments for 2013 include:
• Achieved a record average annual production rate of 73,406 boe per day, representing a 6% increase over last
year and record quarterly production of 75,072 boe per day in the fourth quarter. Bonavista is currently
producing approximately 74,000 boe per day, net of recent dispositions of approximately 2,500 boe per day in
the first quarter of 2014 for proceeds of $103 million;
Improved our 2013 operating costs on a per boe basis by 2% to $8.93 per boe from $9.07 per boe as compared
to 2012. Operating costs for the three months ended December 31, 2013 were $8.77 per boe;
•
• Executed an effective capital expenditure program, investing $443.8 million in exploration and development
activities drilling 128 wells with an overall success rate of 98%. In the fourth quarter, Bonavista spent
approximately $111.6 million on exploration and development, drilling 27 wells with an overall success rate of
100%;
• Production revenues were 16% higher at $964.3 million in 2013 when compared to 2012. For the fourth quarter,
production revenues were $245.5 million representing a 10% increase from the fourth quarter of 2012;
• Realized funds from operations of $477.6 million in 2013 representing a 26% increase from 2012. Funds from
operations during the fourth quarter were $124.4 million, a 13% improvement from the same period in 2012;
3
• Managed our exposure to commodity price fluctuations for 2014 resulting in approximately 66% of our forecasted
net natural gas revenues hedged at an average floor price of $3.40 per gj at AECO and 70% of our net oil and
liquids revenues hedged at an average floor price of Cdn$89.35 per bbl WTI. Additionally, in 2015 we have
hedged approximately 50% of net natural gas revenues at an average floor price of $3.60 per gj at AECO and
30% of our net oil and liquids revenues at an average floor price of Cdn$90.00 per bbl WTI;
• Delivered cumulative dividends of over $2.6 billion or $27.03 per common share since we introduced an income
component to our shareholder return in July 2003; and
• Elected to reduce the commitment amount under our bank credit facility to $600 million from $1.0 billion. The
$400 million reduction in the commitment results in annual savings of approximately $1.7 million in standby fees
or $0.06 per boe on our cash costs. With the reduction, we still have committed bank credit availability of
approximately $367.8 million. The weighted average interest rate under the bank facility was 3.1% for the year
ended December 31, 2013.
2013 Reserves Highlights
• Replaced 2013 annual production by 198%, adding 53.1 mmboe of proved plus probable reserves, bringing total
year end 2013 reserves to 398.5 mmboe representing a 7% increase over 2012, equivalent to a 4% per share
increase;
• Generated a solid reserve life index of 9.1 years on a proved basis and 13.2 years on a proved plus probable
basis;
• Reduced finding and development costs (excluding acquisitions and divestitures) by 18% to $11.95 per boe on a
proved plus probable basis (including changes in future development capital) which reflects the improvement in
capital efficiencies achieved in 2013 with our exploration and development program;
• Achieved 2013 finding, development and acquisition costs, including changes in future development
expenditures, of $14.60 per boe on a proved basis ($13.44 per boe excluding changes in future development
expenditures) and $11.03 per boe on a proved plus probable basis ($8.75 per boe excluding changes in future
development expenditures);
• Three year average finding, development and acquisition costs, including changes in future development
expenditures are $15.31 per boe on a proved basis ($10.93 per boe excluding changes in future development
expenditures) and $12.07 per boe on a proved plus probable basis ($9.37 per boe excluding changes in future
development expenditures);
• Generated an attractive proved plus probable operating netback recycle ratio of 1.9:1 based on 2013 operating
•
netbacks and 2.2:1 based on forecasted 2014 operating netbacks; and
Increased proved plus probable future development capital by 9% to $1.5 billion, representing the future growth
and development potential in our asset portfolio. Future development capital as a ratio of forecasted 2014
capital expenditures and cash flow are 3.1:1 and 2.5:1 times respectively.
2013 Acquisition and Divestiture Highlights
• Completed 30 property transactions in 2013, resulting in net expenditures of $20.5 million;
• Completed acquisitions of $131.4 million adding production of 3,670 boe per day at closing and 2,430 boe per
day on average for the year and proved plus probable reserves of 20.5 mmboe;
• Divested of $110.9 million of non-core assets comprising 1,290 boe per day of production at closing and 745 boe
per day on average for the year and 5.8 mmboe of proved plus probable reserves; and
• Closed a strategic acquisition during the fourth quarter in the Deep Basin area of $29 million, adding production
of approximately 725 boe per day and over 26 Bluesky locations. Since closing, optimization and drilling
investment of $9.7 million has resulted in production growing to approximately 2,100 boe per day.
4
2013 Core Area Highlights
West Central Alberta Core Area
Hoadley Glauconite Liquids Rich Natural Gas:
Bonavista drilled 12 horizontal Glauconite wells during the fourth quarter for a total of 42 wells in 2013. Our activity
during the year was focused primarily on optimizing capital efficiencies. We achieved this through maximizing facility and
infrastructure utilization while reducing the development cost of this substantial resource through initiatives like our
extended reach horizontal well program. Based upon our first three extended reach horizontal wells, we experienced an
average cost reduction of 13% per well when compared to the cost of equivalent reservoir access from two wells. As we
refine this extended reach technology, we expect the use of this development technique to improve capital efficiencies
throughout the entire Glauconite trend.
Our Glauconite horizontal well program in 2013 exceeded our expectations with average first month production rates of
500 boe per day. Production from the Hoadley Glauconite play in 2013 was 16,860 boe per day representing a 13%
increase from the prior year. We have been successful with our cost structure achieving an overall reduction in costs of
four percent when compared to 2012. Bonavista’s Hoadley development program generates an internal rate of return of
50% and a recycle ratio of 3.8:1 at an AECO price of $3.50 per gj. These compelling economics rank it amongst the top
natural gas plays in North America. Given these attractive economics, the predictability of well performance and our
continued success in optimizing capital efficiencies, we have increased our 2014 activity by 57%, with plans to spend
$141 million drilling approximately 66 wells. This level of development will result in a record year of activity for Bonavista
within the Hoadley Glauconite trend.
To support this increase in activity, Bonavista has recently partnered with an area midstream operator, in the building of
two 28 kilometer pipelines which will provide an incremental 130 mmcf per day of gathering capacity from the Hoadley
Glauconite play to the Rimbey processing facility. The two pipelines include a 12 inch line to gather natural gas and a six
inch line to gather natural gas liquids. This project is scheduled to be commissioned in the third quarter of 2014.
Additionally, during the first quarter of 2015, we expect the commissioning of the Rimbey deep cut facility which will
positively impact our economics as a result of increased natural gas liquids recoveries.
Bonavista continues to be an industry leader in the Hoadley Glauconite play having drilled a total of 186 horizontal wells
since 2008. Our land acquisition program and down spacing initiatives have resulted in a current drilling inventory in
excess of 400 horizontal locations. With more than 75% of the original natural gas in place remaining in the reservoir, a
stable inventory contemplating four wells per section, and the predictability and repeatability of the reservoir, the
Glauconite will remain the anchor development project for Bonavista in 2014.
Cardium Light Oil:
Bonavista drilled two horizontal Cardium wells in the fourth quarter bringing total 2013 activity to 27 wells. The 2013
program involved the development of emerging areas of our land base such as Lochend and Strachan to confirm our
understanding of reservoir capabilities. Despite this commitment to emerging areas in 2013, our continued focus on
improving capital efficiencies has resulted in cost reductions on average of approximately $200,000 per well when
compared to 2012.
The Willesden Green area has been a focus area over the past 18 months. With numerous wells on production for a full
year we are confident in our completion approach of utilizing slick water fracture treatments to generate a 10% to 15%
improvement in well performance. Our 2014 development plans involve drilling five wells and initiating a water flood
pilot.
At Lochend, we drilled one well in the fourth quarter and seven wells in total for the year. Despite being constrained by
facility limitations, initial well performance has been strong with first month production averaging over 300 boe per day.
As a result of this well performance, we invested approximately $9 million in the construction of a 29 kilometer, eight inch
pipeline from Lochend to a deep cut facility at Harmattan during the fourth quarter. This pipeline addition will not only
add to our extensive operated infrastructure, it will create an unrestricted flow path for our current producing wells and
will adequately accommodate our planned activity for 2014 at Lochend.
Our 2014 capital expenditure plan is primarily focused on development in Willesden Green and Lochend, totaling
approximately $53 million and drilling 20 wells. We have remained prudently active in the Cardium over the past five
years drilling a total of 113 horizontal wells to date, while maintaining a healthy inventory of horizontal locations,
representing a profitable, multi-year development opportunity.
5
Ellerslie Liquids Rich Natural Gas:
During the fourth quarter, Bonavista drilled one horizontal Ellerslie oil well at Garrington, which had an initial 30-day rate
of 350 boe per day, which includes 170 bbls per day of oil production. We expect this well to perform similar to our offset
well that has demonstrated stable production performance at an average 190 bbls per day of oil over the first eight
months. The significant presence of oil in the Ellerslie at Garrington creates an attractive netback of $40 per boe
resulting in individual well payouts of approximately one year.
In the second half of 2013, we drilled our first liquids rich natural gas Ellerslie horizontal well at Westerose which has
demonstrated an initial 90-day production rate of 840 boe per day. With a well cost of $2.7 million, the economic
performance of this well has encouraged our investment in a three dimensional seismic program to determine the extent
of the Ellerslie reservoir.
Similarly at Caroline, we drilled an Ellerslie liquids rich natural gas horizontal well in the second half of 2013. Despite
having many operational challenges with the well, we successfully completed four stages (originally designed for 12)
resulting in a stable rate of 525 boe per day over its first five months of production.
We are exceedingly pleased with our development results in the Ellerslie formation throughout 2013. Hence, our 2014
plan contemplates a drilling program of 12 wells with an associated budget of approximately $44 million, representing a
two-fold increase in activity over 2013. We will focus on the opportunities with lower operational risk at Garrington and
Westerose where we anticipate an increase in execution success. As we become more intimate with the reservoir, we
anticipate well performance that continues to meet or exceed our expectations. With a meaningful oil and natural gas
liquids yields of approximately 100 bbls per mmcf on average, economic performance will continue to strengthen as we
refine our operational approach. As an active operator in the Ellerslie over the past decade, our strategy had been to
continue to strengthen our land position as we delineated the resource opportunity with vertical well development. Over
the past 24 months we have acquired valuable horizontal operational experience in the play which has enhanced and
accelerated the value of this play within our organization. Since 2010, we have grown our inventory of horizontal
locations in excess of 200 locations and have assembled an extensive land base of 135 prospective sections. With
netbacks currently averaging $30 per boe and decline rates approximating 50% in the first year of production, our 2013
activity has certainly exceeded our economic expectations. Consequently, we see the Ellerslie becoming a cornerstone
of our development program in the near future.
Deep Basin Core Area
Bonavista had an active drilling program in the fourth quarter participating in 10 horizontal wells bringing our total 2013
drilling activity to 21 horizontal wells in our Deep Basin core area. We have been tremendously pleased with the overall
results and look forward to continued success.
Current production in the Deep Basin core area is approximately 16,500 boe per day and has grown 22% from a year
ago. Our capital plan for 2014 involves spending $102 million, drilling 29 wells and infrastructure spending of $34 million.
Our expansion in this core area is expected to result in capital efficiency improvements as larger drilling programs take
place. Over the past four years, we have assembled a position of approximately 238,000 net acres with over 200 future
horizontal locations. Bonavista currently operates natural gas processing capacity of approximately 230 mmcf per day
and we continue to invest in additional infrastructure in 2014. We see the Deep Basin core area providing both near-
term and mid-term growth especially as we transition from the building phase to commercial development with many of
our plays. We remain committed to our Deep Basin area and are confident about its growth profile.
Wilrich Natural Gas:
We have experienced tremendous success with the Wilrich formation in 2013. Building on an important asset acquisition
of 5,000 boe per day of production and 79,000 net acres of land in 2012, we exited 2013 acquiring access to an
additional 26,000 acres of land and have added 2,800 boe per day of production through our exploration and
development program.
The majority of this land acquisition throughout 2013 has taken place in the Ansell area of the Deep Basin. Early in
2013, we gained access to 20,000 acres of Wilrich land at Ansell and have since drilled and completed two horizontal
wells on this acreage. The results of these two wells have exceeded our expectations at restricted 90-day production
rates averaging 900 boe per day per well. The first well has been on production for 10 months and has cumulatively
produced 1.2 bcf of raw natural gas in that period of time. Currently, with access to over 44 sections of land at Ansell
and the potential of multiple prospective zones, we have planned an $84 million capital budget for this area for 2014. We
have committed to drilling 12 wells, five of which will be drilled in the first quarter of 2014. The first two have been drilled
and completed using one drilling pad and have resulted in a combined rate of 34 mmcf per day after a 50 hour flow test.
We have also committed to an infrastructure project in the first quarter of 2014, consisting of a 10 inch, 100 mmcf per day
pipeline and a 30 mmcf per day compressor station. The pipeline and compressor station are expected to be
commissioned by April 2014. The economic performance of our Wilrich play in Ansell is compelling at a natural gas price
6
of $3.50 per gj at AECO. Single-well economics portray a recycle ratio of 3.5:1 with a 10 month payout. The impact of a
stronger natural gas price, coupled with the success of our 2013 drilling program speaks well to the future development
of this play.
At Marlboro, Bonavista holds approximately 28,000 net acres of Wilrich land. Our 2013 drilling program involved six
gross horizontal wells (4.8 net) drilled into the Wilrich formation with these wells currently producing at a combined net
rate of 1,700 boe per day. The Wilrich at Marlboro provides Bonavista with an additional 35 horizontal drilling locations.
Although the natural gas from the Wilrich formation at Marlboro tends to have less associated natural gas liquids,
economics remain robust due to the prolific production performance with payouts under two years and rates of return in
excess of 35% at a natural gas price of $3.50 per gj at AECO.
Bluesky Liquids Rich Natural Gas:
In the fourth quarter, Bonavista participated in five horizontal Bluesky wells consisting of two operated and three non-
operated, totaling nine wells for 2013. Our latest Pine Creek horizontal well drilled in the fourth quarter is our highest rate
Bluesky result to date, producing at an average 30-day raw natural gas rate of 8.6 mmcf per day and 35 bbls per mmcf of
liquids, of which 50% is condensate. We remained active during the fourth quarter by adding to our Bluesky position in
Pine Creek with the acquisition of approximately 725 boe per day of Bluesky production and access to approximately
12,000 net acres of Bluesky rights where we have identified an additional 25 horizontal locations. On a rate of return
perspective, the individual well economics of the Bluesky are the best of our liquids rich natural gas plays.
Additional Emerging Opportunities
The Blueberry Montney play remains an important part of our long-term development plans. Industry activity in the
Montney formation remains strong on all fronts with recent industry acquisition metrics of approximately $4,000 per acre,
solidifying our interpretation of the value of our land base. Through focused efforts on efficiencies, we reduced our
drilling, completion and tie-in costs to $6.3 million representing a 25% reduction from the average of the previous wells
drilled into the formation. As our industry remains focused on exporting Canadian natural gas from the west coast, the
Blueberry Montney field will continue to play an important role as a potential supply, as it is uniquely positioned to
participate in LNG export economics. Meanwhile, Bonavista will continue to improve its understanding of the technology
required to optimize the recovery of the Montney liquids rich resource at our Blueberry field. As such, we have planned
to drill two wells in Blueberry during 2014.
In addition, Bonavista drilled and completed a Falher horizontal well in the West Central Alberta core area during the
third quarter which has resulted in an initial 90-day production rate of approximately 600 boe per day including 60 bbls
per mmcf of natural gas liquids. With the success of this well, we plan on additional reservoir delineation by drilling five
horizontal wells in 2014.
Strengths of Bonavista Energy Corporation
Throughout our history, from an initial restructuring in 1997 to create a high growth junior exploration company, through
the energy trust phase between July 2003 and December 2010, and since January 2011 as a dividend paying
corporation, Bonavista has remained committed to the same operating philosophies despite the endless volatility and
uncertainly inherent in a commodity business like the energy sector. We have consistently improved the quality of our
projects and have maintained a high level of investment activity on our asset base. This has resulted in an increase in
corporate production by approximately 110% since converting to an energy trust in July 2003 and a further 10% since
converting back to a corporation three years ago. These results stem from the expertise of our people and their
entrepreneurial approach to consistently generating profitable development projects in an unpredictable commodity price
environment within the Western Canadian Sedimentary Basin. Our experienced technical teams have a solid
understanding of our assets as they exercise the discipline and commitment required to deliver long-term value to our
shareholders. We actively participate in undeveloped land purchases, producing property acquisitions and farm-in
opportunities, which have all enhanced the quality of our extensive drilling inventory. These activities have led to low cost
reserve additions and a predictable production base that continues to grow at a steady pace. Our production is currently
approximately 65% natural gas weighted and is geographically focused in multi-zone regions primarily in Alberta. The
predictable production performance and low cost structure of our asset base ensures favourable operating netbacks in
most operating environments. Furthermore, our assets are predominantly operated by Bonavista, providing control over
the pace of operations and direct influence over our operating and capital cost efficiencies.
Our team brings a successful track record of executing low to medium risk development programs, while incorporating
acquisitions and sound financial management. Our Board of Directors and management team possess extensive
experience in the oil and natural gas business. They have successfully guided our organization through many different
economic cycles utilizing a proven strategy consisting of disciplined cost controls and prudent financial management.
Directors, management and employees also own approximately 13% of the equity of Bonavista, aligning our interests
with external shareholders.
7
Outlook
With the recent strengthening in natural gas prices due to cold weather across much of North America, we remain
cautiously optimistic as we move into 2014. We do however remain aware of the robust natural gas production capability
on this continent. This capability has been powered by prolific resource discoveries, associated natural gas production
from oil and liquids drilling and continued improvements in the techniques used to exploit these resources. Given this
backdrop, Bonavista will maintain a disciplined approach to commodity hedging and continue to take advantage of the
recent increases in natural gas prices to secure future funds from operations. Operationally, we will continue to focus on
being one of the most efficient producers within our peer group and continue to pursue low cost, repeatable opportunities
throughout our concentrated portfolio of assets. These strategies coupled with our on-going asset concentration
program will support our commitment to maximize shareholder returns through a balance of income and growth.
To support this strategy and in light of the successful first quarter dispositions, Bonavista has a budgeted capital program
of between $460 and $500 million in 2014. This includes spending between $560 and $600 million on exploration and
development activities, offset by approximately $100 million of dispositions and does not contemplate further acquisitions
at this time. The exploration and development program is expected to result in approximately 150 wells drilled and an
average daily production forecast for the year of between 76,000 and 78,000 boe per day. Using the mid-point of our
production estimate, Bonavista will deliver approximately five percent production growth in 2014 in spite of the non-core
dispositions. With current commodity prices and hedges in place, we expect to exit 2014 with a debt to funds from
operations ratio of approximately 1.8:1 and an all in payout ratio of 106%.
Bonavista wishes to announce that Mr. Harry Knutson is retiring from the Board of Directors of the Company effective
today. Mr. Knutson has served on the Board of Directors since 1997 and has provided valuable guidance, expertise and
oversight since then. We would like to thank him for his 17 years of service to Bonavista and wish him all the best in the
future.
Bonavista previously announced the addition of Ms. Sue Lee as a member of the Board of Directors in November 2013
and is currently conducting a search for an additional director, which we expect to communicate at our next annual
general meeting in May.
We thank our employees and directors for their commitment and dedication to our strategy throughout the year and our
shareholders for their trust and support. We firmly believe that we have the right people and assets required to execute
our five year strategy with efficiency and precision. Our employees are the foundation of our continued success.
On behalf of the Board of Directors
Keith A. MacPhail
Executive Chairman
February 27, 2014
Calgary, Alberta
Jason E. Skehar
President and Chief Executive Officer
8
MANAGEMENT’S DISCUSSION AND ANALYSIS
Management’s discussion and analysis (“MD&A”) of the financial condition and results of operations should be read in
conjunction with Bonavista Energy Corporation’s (“Bonavista” or the “Corporation”) audited consolidated financial
statements for the year ended December 31, 2013. The following MD&A of the financial condition and results of
operations was prepared at, and is dated February 27, 2014.
Basis of Presentation - The financial data presented below has been prepared in accordance with International Financial Reporting
Standards ("IFRS").
For the purpose of calculating unit costs, natural gas is converted to a barrel of oil equivalent (“boe”) using six thousand cubic feet of
natural gas equal to one barrel of oil unless otherwise stated. A boe may be misleading, particularly if used in isolation. A boe conversion
of 6 Mcf to one barrel is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a
value equivalency at the wellhead.
Forward-Looking Statements – Certain information set forth in this document, including management’s assessment of Bonavista’s
future plans and operations, contains forward-looking statements including: (i) forecasted capital expenditures and plans; (ii) exploration,
drilling and development plans; (iii) prospects and drilling inventory and locations; (iv) anticipated production rates; (v) anticipated
operating and service costs; (vi) Bonavista’s financial strength; (vii) incremental development opportunities; (viii) total shareholder return;
(ix) asset acquisition and disposition plans; (x) growth prospects; (xi) sources of funding, which are provided to allow investors to better
understand Bonavista’s business. By their nature, forward-looking statements are subject to numerous risks and uncertainties; some of
which are beyond Bonavista’s control, including the impact of general economic conditions, industry conditions, volatility of commodity
prices, currency fluctuations, imprecision of reserve estimates, environmental risks, changes in environmental tax and royalty legislation,
competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility and ability
to access sufficient capital from internal and external sources. Readers are cautioned that the assumptions used in the preparation of
such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance
should not be placed on forward-looking statements. Bonavista’s actual results, performance or achievement could differ materially from
those expressed in, or implied by, these forward-looking statements or if any of them do so, what benefits that Bonavista will derive there
from. Bonavista disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new
information, future events or otherwise, except as required by law.
Non-IFRS Measurements - Within Management’s discussion and analysis, references are made to terms commonly used in the oil and
natural gas industry. Management uses "funds from operations" and the "ratio of debt to funds from operations" to analyze operating
performance and leverage. Funds from operations as presented does not have any standardized meaning prescribed by IFRS and
therefore it may not be comparable with the calculation of similar measures for other entities. Funds from operations as presented is not
intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from
operating activities, net income or other measures of financial performance calculated in accordance with IFRS. All references to funds
from operations throughout this report are based on cash flow from operating activities before changes in non-cash working capital,
decommissioning expenditures and interest expense. Basic funds from operations per share is calculated based on the weighted average
number of common shares outstanding in accordance with International Financial Reporting Standards. Operating netbacks equal
production revenues and realized gains and losses on financial instrument commodity contracts, less royalties, operating and
transportation expenses calculated on a boe basis. Total boe is calculated by multiplying the daily production by the number of days in the
period. Management uses these terms to analyze operating performance and leverage.
Operations - Bonavista's exploration and development program for the year ended December 31, 2013 led to the drilling
of 128 wells within its core regions and a success rate of 98%. This program resulted in 58 liquids rich natural gas wells
and 68 oil wells. Bonavista's exploration and development program for the three months ended December 31, 2013, led
to the drilling of 27 wells within Bonavista’s core region and a success rate of 100%. The program resulted in 18 liquids
rich natural gas wells and 9 oil wells. Profitability continues to guide the exploration and development program which
remains flexible to changes in commodity price, development risk and economic success. Aligned with Bonavista’s
expectations, fourth quarter exploration and development programs have delivered solid rates of return and have
reinforced management’s confidence in the deliverability and repeatability of Bonavista’s extensive drilling inventory.
Reserves - Reserve estimates have been calculated in compliance with the National Instrument 51-101 Standards of
Disclosure (“NI 51-101”). Of the net present value of the Corporation's reserves, 87% were evaluated by independent
third-party engineers, GLJ Petroleum Consultants Ltd. ("GLJ") in their report dated February 20, 2014. The balance of
approximately 13% of proved plus probable net present value reserves were evaluated internally and reviewed by GLJ.
The reserve estimates contained in the following tables represent Bonavista’s gross reserves as at December 31, 2013
and are defined under NI 51-101, as the Corporation’s interest before deduction of royalties and without including any of
the Corporation’s royalty interests.
9
Natural Gas
(mmcf)
Reserves:(1)(4)
Proved:
Proved producing
Proved non-producing
Proved undeveloped
Total proved
Probable
Total proved plus probable
Proved reserve life index (years)(3)
Proved plus probable reserve life index (years)(3)
575,880
19,319
355,169
950,368
521,634
1,472,002
Light and
Medium Oil
(mbbls)
Heavy Oil
(mbbls)
Natural Gas
Liquids
(mbbls)
Total
Reserves(2)
(mboe)
21,450
720
4,914
27,085
11,733
38,818
3,153
431
266
3,851
2,109
5,959
34,250
984
31,652
66,886
41,532
108,418
154,833
5,356
96,028
256,216
142,313
398,529
9.1
13.2
(1)
(2)
(3)
(4)
Bonavista’s gross reserves are based on the GLJ reserve report dated February 20, 2014, GLJ reserve estimates based on forecast prices and costs as of January 1, 2014.
Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.
Calculated based on the amount for the relevant reserve category divided by the 2014 production forecast prepared by GLJ.
Amounts may not add due to rounding.
Reserve Reconciliation:(1)
Balance, December 31, 2012
Extensions and improved recovery
Technical revisions
Acquisitions
Dispositions
Economic factors
Production
Balance, December 31, 2013
Amounts may not add due to rounding.
(1)
Proved
(mboe)
248,409
22,749
3,240
13,437
(4,750)
(112)
(26,755)
256,216
Probable
(mboe)
123,811
19,198
(6,382)
7,027
(1,059)
(283)
-
142,313
Proved
plus
Probable
(mboe)
372,220
41,946
(3,142)
20,464
(5,809)
(396)
(26,755)
398,529
Bonavista’s 2013 year-end proved reserves totaled 256.2 mmboe, a 3% increase compared to the 248.4 mmboe at
year-end 2012. Furthermore, Bonavista’s proved plus probable reserves increased by 7% to 398.5 mmboe when
compared to the 372.2 mmboe at year-end 2012.
10
The following tables highlight Bonavista’s proved plus probable reserves, proved plus probable finding and development
("F&D") expenditures, proved plus probable finding, development and acquisition ("FD&A") expenditures and the
associated recycle ratios:
Proved plus probable reserves (mboe):(1)
Opening balance
Discoveries and extensions
Acquisitions and dispositions
Revisions and economic factors
Production
Closing balance
Operating netback ($/boe)(2)
Operating netback ($/boe) three-year average(2)
Finding and development expenditures:
Total F&D expenditures (excluding changes in future
development expenditures) ($millions)
Proved plus probable F&D costs ($/boe)(3)
F&D recycle ratio(4)
Proved plus probable F&D three-year costs ($/boe)(3)
F&D recycle ratio three-year average(4)
Total F&D expenditures (including changes in future
development expenditures) ($millions)
Proved plus probable F&D costs ($/boe)(3)
F&D recycle ratio(4)
Proved plus probable F&D three-year costs ($/boe)(3)
F&D recycle ratio three-year average(4)
Finding, development and acquisition expenditures:
Total FD&A expenditures (excluding changes in future
development expenditures) ($millions)
Proved plus probable FD&A costs ($/boe)(3)
FD&A recycle ratio(4)
Proved plus probable FD&A three-year costs ($/boe)(3)
FD&A recycle ratio three-year average(4)
2013
2012
2011
372,220
41,946
14,655
(3,537)
(26,755)
398,529
20.54
20.92
341,390
36,645
20,266
(844)
(25,236)
372,220
17.70
22.03
310,749
33,667
22,402
(365)
(25,063)
341,390
24.53
24.05
443.8
11.56
1.8
12.09
1.7
458.8
11.95
1.7
13.62
1.5
464.4
8.75
2.3
9.37
2.2
402.1
11.23
1.6
11.30
1.9
524.7
14.66
1.2
13.89
1.6
391.1
6.98
2.5
9.02
2.4
453.6
13.62
1.8
11.35
2.1
480.5
14.43
1.7
13.32
1.8
617.1
11.08
2.2
9.15
2.6
Total FD&A expenditures (including changes in future
development expenditures) ($millions)
Proved plus probable FD&A costs ($/boe)(3)
FD&A recycle ratio(4)
Proved plus probable FD&A three-year costs ($/boe)(3)
FD&A recycle ratio three-year average(4)
(1)
(2) Operating netback is calculated using production revenues including realized gains and losses on financial instruments commodity contracts less royalties, transportation and operating costs
585.1
11.03
1.9
12.07
1.7
778.7
13.98
1.8
12.86
1.9
625.8
11.16
1.6
12.82
1.7
Amounts may not add due to rounding.
calculated on a per barrel of oil equivalent basis.
(3)
(4)
Both F&D and FD&A costs take into account reserve revisions during the year on a per barrel of oil equivalent basis (6:1).
Recycle ratio is defined as operating netback per barrel of oil equivalent divided by either F&D or FD&A costs on a per barrel of oil equivalent.
Bonavista demonstrated significant improvements in its recycle ratio delivering a ratio of 1.9:1 for proved plus probable
reserves and 1.7:1 for proved reserves including revisions and changes in future development expenditures; excluding
changes in future development expenditures, the proved plus probable recycle ratio improved to 2.3:1 and the proved
recycle ratio remained at 1.8:1. Additional reserves disclosure tables, as required under NI 51-101, are contained in
Bonavista’s Annual Information Form that will be filed on SEDAR.
11
Financial and operating highlights - The following is a summary of key financial and operating results for the
respective periods noted:
($ thousands, except per boe and share amounts where noted)
Three months ended
December 31,
2013
2012
Years ended
December 31,
2013
2012
Product prices:
Natural gas ($/mcf)
Natural gas liquids ($/bbl)
Oil ($/bbl)
Production:
Natural gas (mmcf/d)
Natural gas liquids (bbls/d)
Oil (bbls/d)
Total production (boe/d)
Production revenues
per boe
Royalties
per boe
% of production revenues
Operating expenses
per boe
Transportation expenses
per boe
General and administrative expenses
per boe
Share-based compensation
per boe
Depreciation, depletion and amortization
per boe
Net finance costs
per boe
Deferred income taxes
per boe
Net income
per boe
per share – basic
Dividends declared
per share
Funds from operations
per boe
per share – basic
3.54
49.35
72.73
287
15,103
12,208
75,072
245,466
35.54
30,099
4.36
12.3%
60,601
8.77
9,206
1.33
8,361
1.21
5,777
0.84
90,844
13.15
36,964
5.35
1,215
0.18
6,667
0.97
0.03
38,904
0.21
124,354
18.00
0.62
3.22
42.60
75.73
269
14,563
12,395
71,842
223,021
33.74
29,650
4.49
13.3%
57,464
8.69
9,732
1.47
8,049
1.22
5,845
0.88
90,282
13.66
18,284
2.77
7,822
1.18
14,442
2.19
0.07
63,481
0.36
110,015
16.65
0.57
3.35
47.61
79.32
278
15,093
12,039
73,406
964,312
35.99
124,489
4.65
12.9%
239,196
8.93
36,595
1.37
30,802
1.15
23,868
0.89
349,285
13.04
94,709
3.53
24,043
0.90
49,505
1.85
0.25
152,968
0.84
477,578
17.82
2.42
2.60
45.19
77.30
253
14,074
12,997
69,250
832,491
32.85
124,300
4.90
14.9%
229,847
9.07
38,367
1.51
27,927
1.10
19,450
0.77
331,023
13.06
41,611
1.64
26,292
1.04
64,202
2.53
0.37
224,801
1.44
378,667
14.94
2.16
12
Production - For the year ended December 31, 2013, total production increased by 6% to 73,406 boe per day when
compared to 69,250 boe per day for the same period a year ago. This increase in volumes is due to a highly productive
exploration and development program coupled with the successful execution of Bonavista’s acquisition and divestiture
strategy. Natural gas production increased by 10% to 278 mmcf per day for the year ended December 31, 2013
compared to 253 mmcf per day for the same period a year ago. Natural gas liquids production increased by 7% to
15,093 bbls per day in 2013 from 14,074 bbls per day for the same period in 2012, due in large part to Bonavista’s
continued emphasis on drilling liquids rich natural gas wells. Oil production decreased by 7% to 12,039 bbls per day in
2013 from 12,997 bbls per day for the same period in 2012, due to a number of oil weighted property dispositions in late
2012 and throughout 2013.
For the fourth quarter of 2013, total production increased by 4% to 75,072 boe per day when compared to
71,842 boe per day for the same period a year ago. Natural gas production increased by 7% to 287 mmcf per day in the
fourth quarter of 2013 compared to 269 mmcf per day for the same period a year ago. Natural gas liquids production
increased by 4% to 15,103 bbls per day in the fourth quarter of 2013 compared to 14,563 bbls per day for the same
period in 2012. Oil production decreased by 2% to 12,208 bbls per day in the fourth quarter of 2013 from 12,395 bbls
per day for the same period in 2012. Throughout the fourth quarter of 2013 Bonavista experienced a reduction in natural
gas processing efficiency, at two of the major midstream facilities that handle our volumes, resulting in an unexpected
loss of approximately 200 bbls per day of natural gas liquids production for the quarter.
The following table highlights Bonavista's production by product for the three months and years ended December 31:
Natural gas (mmcf/day)
Natural gas liquids (bbls/day)
Oil (bbls/day)
Total oil equivalent (boe/day)
Three months ended
December 31,
Years ended
December 31,
2013
287
15,103
12,208
75,072
2012
269
14,563
12,395
71,842
2013
278
15,093
12,039
73,406
2012
253
14,074
12,997
69,250
Bonavista’s current production is approximately 74,000 boe per day, net of dispositions of approximately 2,500 boe per
day, completed in the first quarter of 2014. The Corporation’s current production consists of 65% natural gas, 21%
natural gas liquids and 14% oil.
Production revenues - Production revenues for the year ended December 31, 2013 increased by 16% to $964.3 million
when compared to $832.5 million for the same prior year period, due to a 6% increase in production volumes and a 10%
increase in revenues per boe. For the year ended December 31, 2013, natural gas prices increased by 29% to
$3.35 per mcf, when compared to $2.60 per mcf realized in the same period in 2012. Natural gas liquids prices increased
by 5% to $47.61 per bbl for the year ended December 31, 2013 from $45.19 per bbl for the same period in 2012. For the
year ended December 31, 2013, oil pricing increased by 3% to $79.32 per bbl, compared to $77.30 per bbl for the same
period a year ago.
Production revenues for the fourth quarter of 2013 increased by 10% to $245.5 million when compared to $223.0 million
for the same period a year ago, due to a 4% increase in production volumes and a 5% increase in revenues per boe. For
the three months ended December 31, 2013, natural gas prices increased by 10% to $3.54 per mcf, when compared to
$3.22 per mcf realized in the same period in 2012. Natural gas liquids pricing increased by 16% to $49.35 per bbl for the
three months ended December 31, 2013 from $42.60 per bbl for the same period in 2012. For the three months ended
December 31, 2013, oil pricing decreased by 4% to $72.73 per bbl, compared to $75.73 per bbl for the same period a
year ago.
13
The following table highlights Bonavista's realized commodity pricing for the three months and year ended December 31:
Natural gas ($/mcf):
Production revenues
Realized gains (losses) on financial
instrument commodity contracts
Natural gas liquids ($/bbl):
Production revenues
Oil ($/bbl):
Production revenues
Realized gains (losses) on financial
instrument commodity contracts
Total ($/boe):
Production revenues
Realized gains (losses) on financial
instrument commodity contracts
Three months ended
December 31,
2013
2012
Years ended
December 31,
2013
2012
$ 3.50
$
3.28
$
3.35
$
0.04
3.54
49.35
49.35
75.21
(2.48)
72.73
35.54
(0.26)
(0.06)
3.22
42.60
42.60
74.25
1.48
75.73
33.74
0.03
-
3.35
47.61
47.61
82.51
(3.19)
79.32
35.99
(0.51)
$ 35.28
$
33.77
$
35.48
$
2.52
0.08
2.60
45.19
45.19
76.93
0.37
77.30
32.85
0.34
33.19
Risk management activities - As part of Bonavista’s financial management strategy, the Corporation has adopted a
disciplined commodity price risk management program. The purpose of this program is to stabilize funds from operations
against volatile commodity prices and to protect acquisition economics. Bonavista’s Board of Directors has approved a
commodity price risk management limit of 70% for 2014 budgeted revenues, net of royalties and 60% thereafter,
provided that no more than 80% of forecasted revenues, net of royalties, from any one product may be hedged, or in the
case of electricity, 60% of Bonavista’s forecasted net consumption. The term of any commodity hedge executed will be
limited to no more than three calendar years subsequent to the current calendar year in which an executed hedge is
made. We primarily use swaps and costless collars which limits Bonavista’s exposure to volatility in commodity prices,
while in the case of costless collars allows for participation in commodity price increases.
For the year ended December 31, 2013, the risk management program on financial instrument commodity contracts
resulted in a loss of $48.1 million, consisting of a realized loss of $13.7 million and an unrealized loss of $34.4 million.
The realized loss of $13.7 million consisted of a $350,000 gain on natural gas commodity contracts and a $14.0 million
loss on oil commodity contracts. For the same period in 2012, the risk management program on financial instrument
commodity contracts resulted in a gain of $16.8 million, consisting of a realized gain of $8.6 million and an unrealized
gain of $8.2 million. The realized gain of $8.6 million consisted of a $6.8 million gain on natural gas commodity contracts
and a $1.8 gain on oil commodity contracts.
For the fourth quarter of 2013, the risk management program on financial instrument commodity contracts resulted in a
loss of $24.5 million, consisting of a realized loss of $1.8 million and an unrealized loss of $22.7 million. The realized
loss of $1.8 million was the result of a loss of $2.8 million on oil commodity contracts, offset by a gain of $1.0 million on
natural gas commodity contracts. For the same period in 2012, the risk management program on financial instrument
commodity contracts resulted in a loss of $2.6 million, consisting of a realized gain of $204,000 and an unrealized loss of
$2.8 million. The realized gain of $204,000 was the result of a gain of $1.7 million on oil commodity contracts, offset by a
loss of $1.5 million on natural gas commodity contracts.
Commodity price risk is the risk that future cash flows will fluctuate as a result of changes in commodity prices.
Commodity prices for oil and natural gas are impacted not only by global economic events that dictate the levels of
supply and demand, but also by the relationship between the Canadian and United States dollar.
14
i)
Financial instrument commodity contracts:
As at December 31, 2013, Bonavista entered into the following costless collars to sell oil and natural gas as follows:
Volume
Average Price
Term
5,000
40,000
15,000
15,000
10,000
20,000
8,000
3,500
500
gjs/d
gjs/d
gjs/d
gjs/d
gjs/d
gjs/d
bbls/d
bbls/d
bbls/d
CDN $3.50 - CDN $4.00 - AECO
CDN $2.93 - CDN $3.73 - AECO
CDN $3.33 - CDN $4.09 - AECO
CDN $3.38 - CDN $3.95 - AECO
CDN $2.85 - CDN $3.50 - AECO
CDN $3.53 - CDN $4.02 - AECO
CDN $89.78 - CDN $98.65 - WTI
CDN $88.36 - CDN $98.09 - WTI
CDN $87.50 - CDN $97.50 - WTI
January 1, 2014 - March 31, 2014
January 1, 2014 - December 31, 2014
January 1, 2014 - December 31, 2014
January 1, 2014 - December 31, 2015
April 1, 2014 - October 31, 2014
January 1, 2015 - December 31, 2015
January 1, 2014 - December 31, 2014
January 1, 2014 - December 31, 2015
January 1, 2015 - December 31, 2015
Subsequent to December 31, 2013, Bonavista entered into the following costless collars to sell oil and natural gas as
follows:
Volume
10,000
5,000
25,000
Average Price
Term
gjs/d
gjs/d
gjs/d
CDN $3.50 - CDN $3.75 - AECO
CDN $3.50 - CDN $4.00 - AECO
CDN $3.50 - CDN $3.87 - AECO
April 1, 2014 - October 31, 2014
November 1, 2014 - March 31, 2015
January 1, 2015 - December 31, 2015
As at December 31, 2013, Bonavista entered into the following contracts to manage its overall commodity exposure:
Volume
55,000
10,000
5,000
5,000
40,000
5,000
5,000
25,000
15,825
26,375
35,000
5,000
500
gjs/d
gjs/d
gjs/d
gjs/d
gjs/d
gjs/d
gjs/d
gjs/d
gjs/d
gjs/d
gjs/d
gjs/d
bbls/d
Price
CDN $3.45
CDN $3.52
CDN $3.35
CDN $3.48
CDN $3.63
CDN $3.49
CDN $3.71
CDN $3.53
US $3.62
US $3.80
US $(0.48)
US $(0.48)
US 50%
Contract
Term
January 1, 2014 - December 31, 2014
Swap - AECO
January 1, 2014 - December 31, 2015
Swap - AECO
Swap - AECO
January 1, 2014 - March 31, 2014
Swap - AECO
April 1, 2014 - October 31, 2014
Swap - AECO
April 1, 2014 - December 31, 2014
Swap - AECO
April 1, 2014 - March 31, 2015
Swap - AECO
November 1, 2014 - March 31, 2015
Swap - AECO
January 1, 2015 - December 31, 2015
April 1, 2014 - October 31, 2014
Swap - NYMEX
Swap - NYMEX
April 1, 2014 - December 31 2014
Swap - NYMEX Basis April 1, 2014 - December 31, 2014
Swap - NYMEX Basis November 1, 2014 - December 31, 2014
Swap - CNWY/WTI
April 1, 2014 - March 31, 2015
Subsequent to December 31, 2013, Bonavista entered into the following contracts to manage its overall commodity
exposure:
Volume
10,000
75,000
1,000
gjs/d
gjs/d
bbls/d
Price
CDN $3.90
CDN $3.73
US 51%
Contract
Term
Swap - AECO
Swap - AECO
Swap - CNWY/WTI
April 1, 2014 - October 31, 2014
January 1, 2015 - December 31, 2015
April 1, 2014 - March 31, 2015
As at December 31, 2013, Bonavista also entered into the following contracts to purchase electricity:
Volume
Mwh
6
2 Mwh
Price
CDN $50.88
CDN $52.00
Contract
Swap - AESO
Swap - AESO
Term
January 1, 2014 - December 31, 2015
January 1, 2016 - December 31, 2016
15
Financial instrument commodity contracts are recorded on the consolidated statements of financial position at fair
value at each reporting period with the change in fair value being recognized as an unrealized gain or loss on the
consolidated statements of income and comprehensive income. As at December 31, 2013, the fair market value
recorded on the consolidated statement of financial position for these financial instrument commodity contracts was a
net liability of $34.9 million (2012 - $504,000). These financial instrument commodity contracts had the following
gains and losses reflected in the consolidated statements of income and comprehensive income:
Realized gains (losses) on financial
instrument commodity contracts
Unrealized gains (losses) on financial
instrument commodity contracts
Three months ended
December 31,
Years ended
December 31,
2013
2012
2013
2012
$
(1,769)
$
204
$(13,652)
$
8,851
(22,742)
$ (24,511)
$
(2,793)
(2,589)
(34,426)
8,210
$(48,078)
$ 16,791
A $0.10 change in the price per thousand cubic feet of natural gas - AECO would have an impact of approximately
$6.8 million on net income for those financial instrument commodity contracts that were in place as at
December 31, 2013 (2012 - $3.5 million). A $1.00 change in the price per barrel of oil - WTI would have an impact of
approximately $3.5 million on net income for those financial instrument commodity contracts that were in place as at
December 31, 2013 (2012 - $1.6 million).
Royalties - Royalties for the year ended December 31, 2013 were consistent at $124.5 million as compared to $124.3
million for the year ended December 31, 2012, while production volumes increased by 6% over the same period.
Royalties as a percentage of revenues for 2013 decreased to 12.9% compared to 14.9% in the same period in 2012.
The decrease in royalties as a percentage of revenues is largely the result of natural gas revenues, which attract a lower
royalty rate, comprising a larger percentage of the overall total revenues.
For the three months ended December 31, 2013, royalties increased slightly to $30.1 million from $29.7 million for the
same period a year ago. Royalties as a percentage of revenues for the fourth quarter of 2013 decreased to 12.3% when
compared to 13.3% for the same period in 2012 due to the reasons stated above.
The following table highlights Bonavista's royalties by product for the three months and year ended December 31:
Natural gas ($/mcf):
Royalties
% of revenues
Natural gas liquids ($/bbl):
Royalties
% of revenues
Oil ($/bbl):
Royalties
% of revenues
Total ($/boe):
Royalties
% of revenues
Three months ended
December 31,
2013
2012
0.19
5.5%
9.51
19.3%
10.55
14.0%
4.36
12.3%
0.20
6.1%
9.43
22.1%
10.57
14.2%
4.49
13.3%
Years ended
December 31,
2013
0.19
5.7%
9.78
20.5%
11.63
14.1%
4.65
12.9%
2012
0.17
6.6%
10.00
22.1%
12.06
15.7%
4.90
14.9%
Operating expenses - Operating expenses for the year ended December 31, 2013 increased by 4% to $239.2 million
compared to $229.8 million for the same period in 2012 and on a per boe basis decreased by 2% to $8.93 per boe, from
$9.07 per boe for the same period in 2012. On a per boe basis, operating costs decreased by 2% year over year as a
result of a 6% increase in production volumes, disciplined cost control, the realization of cost efficiencies within
Bonavista’s core areas and the disposition of higher cost non-core assets.
For the three months ended December 31, 2013 operating expenses increased by 5% to $60.6 million compared to
$57.5 million for the same period a year ago. On a per boe basis operating expenses were relatively unchanged at
$8.77 per boe and $8.69 per boe for the three months ended December 31, 2013 and 2012, respectively. Absolute
operating expenses increased during the three months ended December 31, 2013 when compared to the same period in
2012, largely as a result of increases in fluid hauling costs associated with Bonavista’s new oil volumes, increased road
maintenance due to significant snowfall, as well as an increase in costs for field staff to support growth in production
16
volumes. These increases were partially offset by a reduction in average fourth quarter utility rates and lower third-party
processing fees.
The following table highlights Bonavista's operating expenses by product for the three months and year ended
December 31:
Natural gas ($/mcf)
Natural gas liquids ($/bbl)
Oil ($/bbl)
Total ($/boe)
Three months ended
December 31,
Years ended
December 31,
$
2013
1.18
10.71
13.08
$
$
8.77
$
2012
1.15
10.94
12.57
8.69
$
$
2013
1.20
10.93
12.96
8.93
2012
1.23
10.90
12.59
9.07
$
$
Transportation expenses - For the year ended December 31, 2013, transportation expenses decreased by 5% to
$36.6 million compared to $38.4 million for the same period in 2012. For the year ended December 31, 2013,
transportation costs on a per boe basis have decreased 9% to $1.37 per boe from $1.51 per boe in the same period in
2012. The decrease in absolute and per boe transportation expenses for the year ended December 31, 2013 when
compared to the same 2012 period, is the result of changes in the terms of natural gas liquids contracts effective
April 1, 2013. The decrease in natural gas liquids transportation expenses was partially offset by an increase in average
oil transportation rates resulting from pipeline capacity constraints causing Bonavista to use alternative means of
transportation to move production volumes to market.
For the three months ended December 31, 2013, transportation expenses decreased by 5% to $9.2 million compared to
$9.7 million for the same period in 2012. For the three months ended December 31, 2013, transportation costs on a per
boe basis decreased by 10% to $1.33 per boe, compared to $1.47 per boe in the same period in 2012. The decrease in
absolute transportation expenses and on a per boe basis for the three months ended December 31, 2013, is due to
similar reasons as stated above.
The following table highlights Bonavista’s transportation costs by product for the three months and years ended
December 31:
Natural gas ($/mcf)
Natural gas liquids ($/bbl)
Oil ($/bbl)
Total ($/boe)
Three months ended
December 31,
Years ended
December 31,
2013
0.26
0.15
1.99
1.33
$
$
2012
0.26
0.89
1.91
1.47
$
$
$
$
2013
0.25
0.34
2.07
1.37
2012
0.26
0.87
1.99
1.51
$
$
General and administrative expenses - General and administrative expenses, after overhead recoveries, increased by
10% to $30.8 million for the year ended December 31, 2013 from $27.9 million in the same period in 2012 and increased
by 4% to $8.4 million for the three months ended December 31, 2013 from $8.0 million in the same period in 2012. On a
per boe basis, general and administrative expenses increased by 5% to $1.15 per boe for the year ended
December 31, 2013 from $1.10 per boe in the same period in 2012 and decreased by 1% for the three months ended
December 31, 2013 to $1.21 per boe from $1.22 per boe in the same period in 2012. The increase in general and
administrative expenses in the fourth quarter and year ended December 31, 2013, when compared to the same periods
in 2012 is largely due to higher staffing levels required to manage Bonavista’s growing business. Even with the recent
increases in general and administrative expenses, Bonavista’s current rate of general and administrative expenses on a
per boe basis remains competitive in its sector.
In relation to the stock option and common share rights incentive plans and restricted share award and restricted
common share incentive plans, Bonavista recorded a share-based compensation charge of $5.8 million and $23.9 million
for the three months and year ended December 31, 2013, respectively, compared to $5.8 million and $19.5 million for the
same periods in 2012.
Depletion, depreciation and amortization expenses - Depletion, depreciation and amortization expenses increased by
6% to $349.3 million for the year ended December 31, 2013 from $331.0 million for the same period in 2012. The
increase in depletion, depreciation and amortization expenses year over year is related to a 6% increase in production
volumes offset by slightly lower costs related to finding, developing and acquiring reserves. For the three months ended
December 31, 2013, depreciation, depletion and amortization expenses increased slightly to $90.8 million from
$90.3 million for the same period in 2012 largely due to a 4% increase in production volumes offset by an overall
decrease in costs related to finding, developing and acquiring reserves. On a per boe basis for the year ended
December 31, 2013, the average charge remained relatively unchanged at $13.04 per boe compared to $13.06 per boe
17
for the same period in 2012 and for the three months ended December 31, 2013, the average charge decreased by 4% to
$13.15 per boe from $13.66 per boe for the same period a year ago.
Net financing costs - Net financing costs increased 128% to $94.7 million for the year ended December 31, 2013 from
$41.6 million for the same period in 2012, mainly due to foreign exchange losses associated with the revaluation of
Bonavista’s US denominated senior unsecured notes. For the year ended December 31, 2013, net financing costs
increased 115% to $3.53 per boe from $1.64 per boe for the same period in 2012. Net financing costs, excluding non-
cash amounts, increased 3% to $42.0 million for the year ended December 31, 2013, as compared to $40.9 for the year
ended December 31, 2012. For the three months ended December 31, 2013, net financing costs, excluding non-cash
amounts, on a per boe basis decreased 2% to $1.57 per boe compared to $1.61 per boe in the same period in 2012.
For the three months ended December 31, 2013, net financing costs increased 102% to $37.0 million from $18.3 million
for the same period in 2012, due to similar reasons as stated above. For the three months ended December 31, 2013,
net financing costs on a per boe basis increased 93% to $5.35 per boe compared to $2.77 per boe for the same period in
2012. Net financing costs, excluding non-cash amounts, increased 17% to $11.1 million for the three months ended
December 31, 2013, as compared to $9.5 million for the three months ended December 31, 2012 due to higher average
debt outstanding. For the three months ended December 31, 2013, net financing costs, excluding non-cash amounts, on
a per boe basis increased 11% to $1.60 per boe compared to $1.44 per boe in the same period in 2012 for the same
reasons as described above.
As part of the financial management program, Bonavista mitigates its currency risk associated with its repayment of its
US senior unsecured notes by utilizing foreign exchange forward contracts. In the third quarter of 2011, Bonavista
entered into the following foreign exchange forward contracts to manage its currency risk associated with its repayment of
its US senior unsecured notes:
Forward date
November 2, 2017
November 2, 2020
November 2, 2022
Contract
US purchased forward
US purchased forward
US purchased forward
Notional US$
$30,000,000
$53,300,000
$16,500,000
CDN$/US$
0.995
0.995
0.995
As at December 31, 2013, the fair market value recorded on the consolidated statement of financial position for those
financial instrument contracts was a long-term asset of $8.0 million (2012 – $4.3 million). A $0.01 change in CDN$/US$
exchange rate would have an impact of approximately $709,000 on net income for those foreign exchange forward
contracts in place as at December 31, 2013 (2012 - $655,000).
Deferred income taxes - The provision for deferred income taxes for the year ended December 31, 2013, was
$24.0 million compared to $26.3 million during the same period in 2012. For the three months ended December 31, 2013
the deferred income tax provision was $1.2 million compared to a provision of $7.8 million during the same period in
2012. The deferred income tax provision for the year ended December 31, 2013 is higher than the provision calculated
using the current statutory rate. This is mainly due to the income tax treatment of foreign currency translation losses on
long-term debt and non-deductible share-based compensation, offset by the income tax treatment of the disposition of a
capital asset. Bonavista made no cash payments or tax installments for the three months and year ended December 31,
2013 or for the comparative periods in 2012.
Funds from operations, net income and comprehensive income - For the year ended December 31, 2013, Bonavista
experienced a 26% increase in funds from operations to $477.6 million ($2.42 per share, basic) from $378.7 million
($2.16 per share, basic) for the same period in 2012, mainly due to a 10% increase in product prices, cash cost
reductions of 2% and a 6% increase in production volumes. For the three months ended December 31, 2013, Bonavista
experienced a 13% increase in funds from operations to $124.4 million ($0.62 per share, basic) from $110.0 million
($0.57 per share, basic) for the same period in 2012, due to higher product prices and a 4% increase in production
volumes. Net income and comprehensive income for the year ended December 31, 2013, decreased 23% to
$49.5 million ($0.25 per share, basic) from $64.2 million ($0.37 per share, basic) for the same period in 2012, due largely
to foreign exchange losses on the revaluation of Bonavista’s US denominated senior unsecured notes. Net income and
comprehensive income for the three months ended December 31, 2013, was $6.7 million ($0.03 per share, basic)
compared to $14.4 million ($0.07 per share, basic) for the same period in 2012, largely due to the same reasons
described above.
18
The following table is a reconciliation of a non-IFRS measure, funds from operations, to its nearest measure prescribed
by IFRS:
Calculation of funds from operations:
(thousands)
Cash flow from operating activities
Interest expense
Decommissioning expenditures
Changes in non-cash working capital
Three months ended
December 31,
Years ended
December 31,
2013
2012
2013
2012
$ 115,021
(11,076)
10,539
9,870
$
102,886
(9,487)
11,410
5,206
$ 486,605
(42,000)
30,143
2,830
$ 407,481
(40,878)
25,530
(13,466)
Funds from operations
$ 124,354
$
110,015
$ 477,578
$ 378,667
Capital expenditures - Net capital expenditures for the year ended December 31, 2013 were $470.5 million, consisting
of $443.8 million spent on exploration and development activities, $131.4 million spent on property acquisitions, property
dispositions of $110.9 million and head office expenditures of $6.2 million. For the same period in 2012, net capital
expenditures were $394.4 million, consisting of $402.1 million spent on exploration and development activities,
$169.9 million spent on acquisitions, property dispositions of $180.8 million and head office expenditures of $3.3 million.
Net capital expenditures for the three months ended December 31, 2013 were $118.5 million, consisting of $111.6 million
spent on exploration and development activities, $45.1 million spent on property acquisitions, property dispositions of
$40.3 million and head office expenditures of $2.1 million. For the same period in 2012, net capital expenditures were
$196.5 million, consisting of $76.9 million spent on exploration and development activities, $164.8 million spent on
property acquisitions, property dispositions of $45.9 million and head office expenditures of $704,000.
The following table outlines capital expenditures by category for the three months and years ended December 31:
(thousands)
Land acquisitions
Geological and geophysical
Drilling and completion
Production equipment and facilities
Exploration and development
expenditures
Cash used for business and property
acquisitions
Cash received on dispositions
Head office expenditures
Three months ended
December 31,
2013
$ 11,952
1,544
72,412
25,688
$
2012
2,099
1,921
56,842
16,075
Years ended
December 31,
2013
2012
$
24,825
13,780
308,354
96,870
$
14,520
13,557
295,406
78,607
$ 111,596
$
76,937
$ 443,829
$
402,090
32,231
(27,416)
2,066
164,757
(45,920)
704
118,559
(98,029)
6,183
169,891
(180,848)
3,307
Net capital expenditures
$ 118,477
$
196,478
$ 470,542
$
394,440
Liquidity and capital resources – As at December 31, 2013 Bonavista’s long-term debt, including working capital,
(excluding associated assets and liabilities from financial instrument commodity contracts and decommissioning liabilities)
was $1.1 billion with a debt to fourth quarter annualized funds from operations ratio of 2.1:1. Bonavista’s long-term debt
consists of both bank debt and senior unsecured notes.
As at December 31, 2013 Bonavista’s bank debt, including working capital, was $307.3 million with a weighted average
interest rate of 3.1% (2012 – 3.1%) and a current maturity date of September 10, 2016. As at December 31, 2013
Bonavista had approximately $367.8 million of unused borrowing capacity on its $600 million bank credit facility.
Bonavista’s senior unsecured notes totaled $816.9 million as at December 31, 2013 which consisted of US$705 million
(CDN$746.9 million) and CDN$70 million with a fixed weighted average interest rate of 4.1% (2012-4.2%). The
maturity dates on the senior unsecured notes range from November 2, 2015 to May 23, 2025 with approximately
CDN$618 million due between 2020 and 2025 with interest rates ranging from 3.68% and 4.47%. This long-term, low
cost debt is mainly US dollar denominated of which, US$100 million has been hedged using foreign exchange contracts.
In addition to using foreign exchange contracts to hedge against the US denominated debt exposure, Bonavista’s
revenue stream is naturally hedged as North American crude oil and natural gas benchmark prices are denominated in
US dollars.
On April 12, 2013, Bonavista agreed to increase its existing master shelf agreement from US $125 million to
US $150 million allowing the Corporation to draw an additional US $100 million in notes at a rate equal to the related US
treasury rate corresponding to the term of the notes plus an appropriate credit risk adjustment at the time of issuance.
On April 25, 2013, the Corporation drew down US $100 million on the master shelf agreement with a coupon rate of
19
3.80% and a maturity date of April 25, 2025. Under the terms of the master shelf agreement, Bonavista has provided
similar significant covenants that exist under the bank credit facility.
On May 23, 2013, Bonavista issued the following senior unsecured notes by way of private placement. Under the terms
of the senior unsecured notes, Bonavista has provided similar significant covenants that exist under the bank credit
facility.
The terms and coupon rates of the notes issued by private placement are summarized below:
Issued Date
May 23, 2013
May 23, 2013
May 23, 2013
Principal
US $85 million
CDN $20 million
US $20 million
Coupon Rate
3.68%
4.09%
3.78%
Maturity Date
May 23, 2023
May 23, 2023
May 23, 2025
Bonavista is in compliance with all of the covenants under both its bank credit facilities and its senior unsecured notes.
For 2014, Bonavista plans to invest between $460 and $500 million on its capital program within its core regions, which is
comprised of an exploration and development program between $560 and $600 million and dispositions of approximately
$100 million. Bonavista intends on financing this capital program with a combination of funds from operations, its
dividend reinvestment and stock dividend plans and to the extent required its existing bank credit facility. Bonavista
remains committed to the fundamental principle of maintaining financial flexibility and the prudent use of debt.
Shareholders’ equity - As at December 31, 2013, Bonavista had 199.9 million equivalent common shares
outstanding. This includes 10.7 million exchangeable shares, which are exchangeable into 12.9 million common
shares. The exchange ratio in effect at December 31, 2013 for exchangeable shares was 1.20836:1. As at
February 27, 2014, Bonavista had 201.1 million equivalent common shares outstanding. This includes 10.4 million
exchangeable shares, which are exchangeable into 12.7 million common shares. The exchange ratio in effect at
February 27, 2014 for exchangeable shares was 1.22019:1. In addition, Bonavista has 7.8 million stock option and
common share incentive rights outstanding as at February 27, 2014, with an average exercise price of $19.63 per
common share.
Dividends - For the year ended December 31, 2013, Bonavista declared dividends of $153.0 million ($0.84 per share)
compared to $224.8 million ($1.44 per share) in the same period in 2012. For the three months ended
December 31, 2013, Bonavista declared dividends of $38.9 million ($0.21 per share) compared to $63.5 million
($0.36 per share) in the same period in 2012.
Bonavista announces its dividend policy on a quarterly basis and confirms its dividend payment on a monthly basis.
Dividends are approved by the Board of Directors and are dependent upon the commodity price environment, production
levels, and the amount of capital expenditures to be financed from funds from operations. As such, on January 9, 2013,
Bonavista announced a reduction in the monthly dividend from $0.12 per share to $0.07 per share. Although numerous
initiatives had been employed throughout 2012 to preserve the prior dividend, the forward commodity prices did not allow
for these activities to continue under Bonavista’s growth plus dividend business model. The long-term goal of
Bonavista’s business model remains intact with a commitment to generate an attractive return to shareholders through a
sustainable balance between dividends and corporate growth. Distributing between 25% and 35% of funds from
operations will allow the Corporation to withhold sufficient funds to finance capital expenditures required to modestly
grow the production base over the long-term, assuming current strip pricing is realized.
20
Annual financial information - The following table highlights selected annual financial information for each of the three
years ended December 31, 2013, 2012 and 2011:
Years ended December 31,
2013
2012
2011
(thousands, except per share amounts)
Consolidated Statement of Income and Comprehensive
Income Information:
Production revenues, net of royalties
Funds from operations
Per share – basic
Per share – diluted
Net income
Per share – basic
Per share – diluted
Consolidated Statement of Financial Position
Information:
Net capital expenditures
Total assets
Working capital deficiency
Long-term debt
Shareholders’ equity
Dividends declared
$ 839,823
477,578
2.42
2.40
49,505
0.25
0.25
$ 708,191
378,667
2.16
2.14
64,202
0.37
0.36
$ 882,672
553,303
3.44
3.42
137,184
0.85
0.85
$ 470,542
4,235,626
(109,587)
1,046,177
2,270,015
152,968
$ 394,440
4,062,852
(74,607)
889,071
2,285,889
224,801
$ 617,071
3,924,160
(51,110)
1,080,605
2,001,802
200,032
Quarterly financial information - The following table highlights Bonavista’s performance for the eight quarterly periods
ending on March 31, 2012 to December 31, 2013:
Production revenues
Net income (loss)
Basic
Diluted
December 31 September 30
June 30
245,466
6,667
0.03
0.03
246,413
22,950
0.12
0.11
244,940
23,107
0.12
0.12
March 31
227,493
(3,219)
(0.02)
(0.02)
December 31 September 30
188,610
2,484
0.01
0.01
223,021
14,442
0.07
0.07
June 30
March 31
193,826
3,553
0.02
0.02
227,034
43,723
0.26
0.26
2013
2012
Production revenues over the past eight quarters have fluctuated largely due to the volatility of commodity prices and
changes in production volumes. Net income in the past eight quarters has fluctuated from a deficit of $3.2 million in the
first quarter of 2013 to a high of $43.7 million in the first quarter of 2012. These fluctuations are primarily influenced by
production volumes; commodity prices; realized and unrealized gains and losses on financial instrument commodity
contracts; gains and losses on foreign exchange; and future income tax recoveries associated with the reduction in
corporate income tax rates.
Disclosure controls and procedures - Disclosure controls and procedures have been designed to ensure that
information to be disclosed by Bonavista is accumulated and communicated to management, as appropriate, to allow
timely decisions regarding required disclosures. The Chief Executive Officer and Chief Financial Officer have concluded,
as of the end of the period covered by the interim and year end filings, that Bonavista’s disclosure controls and
procedures are appropriately designed and operating effectively to provide reasonable assurance that material
information relating to the issuer is made known to them by others within the Corporation.
Internal control over financial reporting - Internal control over financial reporting is a process designed to provide
reasonable assurance that all assets are safeguarded, transactions are appropriately authorized and to facilitate the
preparation of relevant, reliable and timely information. A control system, no matter how well conceived or operated, can
provide only reasonable, not absolute, assurance that the objective of the control system is met. Management has
reporting as defined by
assessed
National Instrument 52-109, Certification of Disclosure in Issuers’ Annual and Interim Filings. Management’s
assessment was based on the framework in Internal Control – Integrated Framework (1992) issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Management has concluded that their internal control over
financial reporting was effective as of December 31, 2013. There were no changes made to Bonavista’s internal controls
over financial reporting during the year ended December 31, 2013.
the effectiveness of Bonavista’s
internal control over
financial
21
Changes in accounting policies – On January 1, 2013, Bonavista adopted the following new standards and
amendments which became effective for annual periods on or after January 1, 2013:
•
•
•
•
IFRS 10, “Consolidated Financial Statements,” supersedes IAS 27 “Consolidated and Separate Financial
Statements” and SIC-12 “Consolidation – Special Purpose Entities”. This standard provides a single model to be
applied in control analysis for all investees including special purpose entities. The adoption of this standard had
no impact on the amounts recorded in Bonavista’s financial statements.
IFRS 11, “Joint Arrangements,” whereby joint arrangements are classified as either joint operations or joint
ventures, each with their own accounting treatment. All joint arrangements are required to be reassessed on
transition to IFRS 11 to determine their type to apply the appropriate accounting. The adoption of this standard
had no impact on the amounts recorded in Bonavista’s financial statements.
IFRS 12, “Disclosure of Interest in Other Entities,” combines the disclosure requirements for entities that have
interest in subsidiaries, joint arrangements, and associates as well as unconsolidated structured entities. The
adoption of this standard had no impact on Bonavista’s financial statements.
IFRS 13, “Fair Value Measurement,” establishes a framework for measuring fair value and sets out disclosure
requirements for fair value measurements. This standard defines fair value as the price that would be received
to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the
measurement date. The standard also requires additional annual fair value disclosures, as well as additional
interim disclosures. The adoption of this standard had no material impact on Bonavista’s financial statements.
• Amendments to IAS 32, “Financial Instruments: Presentation” clarify the requirements for offsetting financial
assets with financial liabilities. Amendments to IFRS 7, "Financial Instruments: Disclosures," develop common
disclosure requirements for financial assets and financial liabilities that are offset in the financial statements, or
that are subject to enforceable master netting arrangements or similar agreements. The adoption of these
amendments has no impact on Bonavista's financial statements.
Future accounting policies – In May 2013, the IASB issued amendments to IAS 36, “Impairment of Assets” which will
restrict the requirements to disclose the recoverable amount of an asset or CGU to periods in which an impairment loss
has been recognized or reverses. The amendment also expands and clarifies the disclosure requirements applicable
when an impairment loss has been recognized or reversed in the period. The amendments apply retrospectively for
annual periods beginning on or after January 1, 2014. Bonavista plans to adopt the amendments in its financial
statements for the annual period beginning on January 1, 2014. The adoption will impact Bonavista’s disclosures in the
notes to the financial statements in periods when an impairment loss or impairment reversal is recognized.
In May 2013, the IASB issued IFRIC 21, “Levies” which provides guidance on accounting for levies in accordance with
the requirements of IAS 37, “Provisions, Contingent Liabilities and Contingent Assets”. The interpretation clarifies that an
entity is to recognize a liability for a levy when the activity that triggers payment, as identified by the relevant legislation,
occurs. The interpretation also clarifies that a levy liability is to be accrued progressively only if the activity that triggers
payment occurs over a period of time, in accordance with the relevant legislation. IFRIC 21 is effective for annual period
commencing on or after January 1, 2014 and is to be applied retrospectively. Bonavista intends to adopt IFRIC 21 in its
financial statements for the annual periods beginning on January 1, 2014. Bonavista is currently assessing but has not
yet determined the impact of the adoption of the amendments.
In November 2013, the IASB issued amendments to the recognition, presentation and disclosure to pension accounting
under IAS 19, “Employee Benefits”. The amendments apply retrospectively for annual periods beginning on or after July
1, 2014. Bonavista intends to adopt these amendments in its financial statements for the annual period beginning on
January 1, 2014, no impact to the financial statements is expected.
In November 2009 the IASB issued IFRS 9, “Financial Instruments” as the first step in its project to replace IAS 39
“Financial Instruments: Recognition and Measurement”. IFRS 9 introduced new requirements for classifying and
measuring financial assets. On October 28, 2010, the IASB reissued IFRS 9, incorporating new requirements on
accounting for financial liabilities. The new standard eliminates the existing multiple classification and measurement
categories under IAS 39 of held-to-maturity, available-for-sale and loans receivable and replaces them with a single
model that has only two classification categories: amortized cost and fair value.
22
In November 2013, the IASB issued a new general hedge accounting standard which forms part of IFRS 9. While hedge
accounting remains optional under IFRS 9, the new general hedge accounting statement was designed to more closely
align hedge accounting with the risk management activities of an entity. The new standard does not fundamentally
change the types of hedging relationships or the requirements to measure and recognize ineffectiveness, however, it
does provide for more hedging strategies to qualify for hedge accounting and introduces more judgment into the
assessment of hedge effectiveness. In July of 2013, the IASB deferred the mandatory effective date of IFRS 9, which
previously had been effective for annual periods beginning on or after January 1, 2015. The IASB has yet to determine
the mandatory effective date; early adoption of the new standard is still permitted. The extent of the impact of the
adoption of IFRS 9 on Bonavista’s financial statements has not yet been determined.
In December 2013, the IASB issued narrow-scope amendments to a total of nine standards as part of its annual
improvement process. The improvement process is designed to make non-urgent but necessary amendments to IFRS.
Some of the amendments made to the existing standards included; clarifying the definition of “vesting conditions” in
IFRS 2, “Share-based payment”; defining the classification and measurement of contingent consideration; scope
exclusion for the formation of joint arrangements in IFRS 3, “Business Combinations”; and modifying the definition of a
“related party” in IAS 24, “Related Party Disclosures”. Bonavista intends to adopt these amendments in its financial
statement for the annual period beginning on January 1, 2014. The adoption of these amendments is not expected to
have a material impact on the financial statements.
Significant accounting judgments and estimates - The consolidated financial statements have been prepared in
accordance with IFRS. A summary of the significant accounting policies are presented in note 2 of the Notes to the
Consolidated Financial Statements. The timely preparation of Bonavista’s financial statements requires management to
make certain judgments, estimates and assumptions. These estimates and judgments are subject to changes and actual
results could differ from those estimated. Significant judgments and estimates made by management in the preparation
of the financial statements are outlined below.
• Determination of a Cash Generating Unit (“CGU”) - The determination of Bonavista’s CGUs is subject to
management’s judgment. In determining Bonavista’s CGUs management assessed what constituted
independent cash flows and how to aggregate the respective assets. The asset composition of each CGU can
directly impact the assessment of the recoverability of those assets included within each CGU.
•
Impairment testing - Bonavista assesses its property, plant and equipment for impairment when events or
circumstances indicate that the carrying amount of its assets may not be recoverable. If any indication of
impairment exists, Bonavista performs an impairment test on the CGU, which is the lowest level at which there
are identifiable cash flows. The carrying amount of each CGU is compared to its recoverable amount which is
defined as the greater of its fair value less cost to sell and value in use.
As at December 31, 2013 Bonavista evaluated each of its CGUs for indicators of impairment. In performing this
evaluation, management used the net present values for each CGU. Key estimates used in the determination of
these cash flows include: quantities of reserves and future production; future commodity pricing; development
costs; operating costs; royalty obligations and discount rates. Any changes in these estimates may have an
impact on the recoverable amount of the CGU. For the year ended December 31, 2013 the following benchmark
reference prices were used by Bonavista’s independent reserve evaluator and adjusted for commodity
differentials specific to the Corporation.
Year
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
Remainder (1)
(1)
WTI Oil
(US$/bbl)
97.50
97.50
97.50
97.50
97.50
97.50
98.54
100.51
102.52
104.57
2.0%
AECO Gas
(CDN$/mmbtu)
4.03
4.26
4.50
4.74
4.97
5.21
5.33
5.44
5.55
5.66
2.0%
CDN$/US$
Exchange Rates
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
Percentage change represents the change in each year after 2023 to the end of the reserve life.
For the years ended December 31, 2013 and December 31, 2012 no impairment was recognized. In addition,
the recoverable amount of the CGU to which Bonavista’s goodwill is allocated continues to support the carrying
amount of the goodwill.
• Proved plus probable oil and natural gas reserves - Reserve estimates are based on engineering data, estimated
future prices, expected future rates of production and the timing of future capital expenditures, all of which are
subject to interpretation and uncertainty. Bonavista expects that over time its reserve estimates will be revised
23
either upward or downward depending upon the factors as stated above. These reserve estimates can have a
significant impact on net income, as it is a key component in the calculation of depletion, depreciation and
amortization, and also for the determination of potential asset impairments.
• Depreciation, depletion and amortization - Property, plant and equipment is measured at cost less accumulated
depreciation, depletion and amortization. Bonavista’s oil and natural gas properties are depleted using the unit-
of-production method over proved plus probable reserves for each CGU. The unit-of-production method takes
into account capital expenditures incurred to date along with future development capital required to develop both
proved plus probable reserves.
• Decommissioning liabilities - The provision for decommissioning liabilities is based on estimates of costs and
planned remediation projects. Actual costs may differ from those estimated due to changes in governing
environment laws and regulations, technological changes, and market conditions.
• Financial Instrument contracts - The estimated fair value of financial instrument commodity contracts are subject
to changes in forward looking commodity prices, interest rate curves, volatility curves and counterparty non-
performance risk. The estimated fair values of the Corporation’s financial instrument contracts are subject to
changes in foreign exchange rates.
24
Management’s Report
The Consolidated Financial Statements of Bonavista Energy Corporation and related financial information were prepared
by, and are the responsibility of Management. The Consolidated Financial Statements have been prepared in
accordance with International Financial Reporting Standards. The Consolidated Financial Statements and related
financial information reflect amounts which must of necessity be based upon informed estimates and judgments of
Management with appropriate consideration to materiality. The Corporation has developed and maintains systems of
controls, policies and procedures in order to provide reasonable assurance that assets are properly safeguarded, and
that the financial records and systems are appropriately designed and maintained, and provide relevant, timely and
reliable financial information to Management.
The Consolidated Financial Statements have been audited by KPMG LLP, the external auditors, in accordance with
auditing standards generally accepted in Canada on behalf of the shareholders.
The Board of Directors has established an Audit Committee. The Audit Committee reviews with Management and the
external auditors any significant financial reporting issues, the Consolidated Financial Statements, and any other matters
of relevance to the parties. The Audit Committee meets quarterly to review and approve the condensed consolidated
interim financial statements prior to their release, as well as annually to review the Corporation’s annual Consolidated
Financial Statements and Management’s Discussion and Analysis and to recommend their approval to the Board of
Directors.
The external auditors have unrestricted access to the Corporation, the Audit Committee and the Board of Directors.
Jason E. Skehar
President and Chief Executive Officer
Glenn A. Hamilton
Senior Vice President and Chief Financial Officer
February 27, 2014
Calgary, Alberta
25
INDEPENDENT AUDITORS’ REPORT
To the Shareholders of Bonavista Energy Corporation
We have audited the accompanying consolidated financial statements of Bonavista Energy Corporation, which comprise
the consolidated statements of financial position as at December 31, 2013 and December 31, 2012, the consolidated
statements of income and comprehensive income, changes in equity and cash flows for the years then ended, and
notes, comprising a summary of significant accounting policies and other explanatory information.
Management’s responsibility for the consolidated financial statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in
accordance with International Financial Reporting Standards, and for such internal control as management determines is
necessary to enable the preparation of consolidated financial statements that are free from material misstatement,
whether due to fraud or error.
Auditors’ responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We
conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that
we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the
consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated
financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material
misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments,
we consider internal control relevant to the entity’s preparation and fair presentation of the consolidated financial
statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of
expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the
appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as
well as evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our
audit opinion.
Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial
position of Bonavista Energy Corporation as at December 31, 2013 and December 31, 2012, and its consolidated
financial performance and its consolidated cash flows for the years then ended in accordance with International Financial
Reporting Standards.
Chartered Accountants
Calgary, Canada
February 27, 2014
26
BONAVISTA ENERGY CORPORATION
Consolidated Statements of Financial Position
(thousands)
Assets:
Current assets:
Accounts receivable
Prepaid expenses
Marketable securities
Other assets
Financial instrument commodity contracts
Financial instrument commodity contracts
Financial instrument contracts
Property, plant and equipment
Exploration and evaluation assets
Goodwill
Liabilities and Shareholders’ Equity:
Current liabilities:
December 31,
December 31,
Notes
2013
2012
$ 124,431
$ 102,500
7,322
2,645
13,786
419
148,603
346
8,023
11,089
2,768
12,191
8,608
137,156
1,224
4,293
3,845,344
3,691,572
222,085
11,225
217,382
11,225
$ 4,235,626
$ 4,062,852
(4)
(4)
(8)
(9)
(9)
Accounts payable and accrued liabilities
$ 213,118
$ 181,674
Decommissioning liabilities
Dividends payable
Financial instrument commodity contracts
Financial instrument commodity contracts
Long-term debt
Other long-term liabilities
Decommissioning liabilities
Deferred income taxes
Shareholders’ equity:
Shareholders’ capital
Exchangeable shares
Contributed surplus
Deficit
Commitments
(4)
(4)
(12)
(13)
(14)
(11)
(15)
9,313
13,087
31,985
267,503
3,710
1,046,177
13,853
397,174
237,194
-
21,303
8,786
211,763
1,550
889,071
13,650
447,753
213,176
2,228,210
2,059,305
307,468
61,247
(326,910)
405,183
44,848
(223,447)
2,270,015
2,285,889
$ 4,235,626
$ 4,062,852
See accompanying notes to the consolidated financial statements.
Approved on behalf of the Board of Directors of Bonavista Energy Corporation:
Ian S. Brown, Director
Michael M. Kanovsky, Director
27
BONAVISTA ENERGY CORPORATION
Consolidated Statements of Income and Comprehensive Income
Years ended December 31,
(thousands, except per share amounts)
Revenues:
Production
Royalties
Realized gains (losses) on financial instrument
commodity contracts
Unrealized gains (losses) on financial instrument
commodity contracts
(4)
(4)
Expenses:
Operating
Transportation
General and administrative
Share-based compensation
Gain on disposition of property, plant and equipment
Loss (gain) on disposition of exploration and evaluation assets
Notes
2013
2012
$ 964,312
$ 832,491
(124,489)
(124,300)
839,823
708,191
(13,652)
(34,426)
8,581
8,210
(48,078)
16,791
791,745
724,982
239,196
229,847
36,595
30,802
23,868
(38,115)
(18,143)
38,367
27,927
19,450
(59,675)
5,938
Depletion, depreciation and amortization
(8)
349,285
331,023
Income from operating activities
Finance costs
Finance income
Net finance costs
Income before taxes
Deferred income taxes
Net income and comprehensive income
Net income per share – basic
Net income per share – diluted
See accompanying notes to the consolidated financial statements.
623,488
592,877
168,257
98,439
132,105
53,350
(3,730)
(11,739)
94,709
41,611
73,548
24,043
90,494
26,292
$
49,505
$
64,202
$
$
0.25
$
0.37
0.25
$
0.36
(6)
(6)
(14)
(11)
(11)
28
BONAVISTA ENERGY CORPORATION
Consolidated Statements of Changes in Equity
For the years ended December 31,
Shareholders’
capital
Exchangeable
shares
Contributed
surplus
Total
shareholders’
equity
Deficit
(thousands)
Balance as at December 31, 2012
$ 2,059,305
$
405,183
$
44,848
$
(223,447)
$ 2,285,889
Net income
Issue costs, net of
future tax benefit
Issued for cash on exercise of
common share incentive rights
Exercise of common share
incentive rights
Conversion of restricted share
awards
Share-based compensation
expense
Share-based compensation
capitalized
Issued pursuant to the dividend
reinvestment and stock dividend
plans
Exchangeable shares exchanged
for common shares
Dividends declared
-
(74)
1,984
2,708
7,410
-
-
59,162
97,715
-
-
-
-
-
-
-
-
-
(97,715)
-
-
-
-
(2,708)
(7,410)
23,868
2,649
-
-
-
49,505
49,505
-
-
-
-
-
-
-
-
(74)
1,984
-
-
23,868
2,649
59,162
-
(152,968)
(152,968)
Balance as at December 31, 2013
$ 2,228,210
$
307,468
$
61,247
$
(326,910)
$ 2,270,015
Balance as at December 31, 2011
$ 1,446,804
$
585,754
$
32,092
$
(62,848)
$ 2,001,802
Net income
Issuance of equity, net of issue
costs
Issued for cash on exercise of
common share incentive rights
Exercise of common share
incentive rights
Conversion of restricted share
awards
Share-based compensation
expense
Share-based compensation
capitalized
Issued pursuant to the dividend
reinvestment and stock dividend
plans
Exchangeable shares exchanged
for common shares
Dividends declared
-
334,736
4,510
4,609
5,183
-
-
82,892
-
-
-
-
-
-
-
-
180,571
(180,571)
-
-
-
-
-
(4,609)
(5,183)
20,070
2,478
-
-
-
64,202
64,202
-
-
-
-
-
-
-
-
334,736
4,510
-
-
20,070
2,478
82,892
-
(224,801)
(224,801)
Balance as at December 31, 2012
$ 2,059,305
$
405,183
$
44,848
$
(223,447)
$ 2,285,889
See accompanying notes to the consolidated financial statements.
29
BONAVISTA ENERGY CORPORATION
Consolidated Statements of Cash Flows
Years ended December 31,
(thousands)
Cash provided by (used in):
Operating Activities:
Net income
Adjustments for:
Depletion, depreciation and amortization
Share-based compensation
Unrealized (gains) losses on financial instrument
commodity contracts
Gain on disposition of property, plant and
equipment
Loss (gain) on disposition of exploration and
evaluation assets
Net finance costs
Deferred income taxes
Decommissioning expenditures
Financing Activities:
Issuance of senior notes
Issuance of equity, net of issue costs
Proceeds on exercise of common share incentive rights
Dividends paid
Interest paid
Proceeds from long-term debt
Repayment of long-term debt
Investing Activities:
Business acquisitions
Exploration and development
Property and other business acquisitions
Property dispositions
Office equipment
Changes in non-cash working capital items
(7)
Changes in non-cash working capital items
(7)
Change in cash
Cash, beginning of year
Cash, end of year
See accompanying notes to the consolidated financial statements.
Notes
2013
2012
$
49,505
$
64,202
(8)
349,285
23,868
331,023
18,364
34,426
(8,210)
(38,115)
(59,675)
(18,143)
94,709
24,043
(30,143)
(2,830)
5,938
41,611
26,292
(25,530)
13,466
486,605
407,481
229,226
-
(99)
331,188
1,984
4,510
(102,022)
(137,898)
(40,793)
119,791
(40,907)
-
(235,970)
(182,329)
(27,883)
(25,436)
(10)
(102,284)
(155,266)
(443,829)
(402,090)
(16,275)
98,029
(6,183)
11,820
(14,626)
180,848
(3,307)
12,396
(458,722)
(382,045)
-
-
-
$
$
-
-
-
30
BONAVISTA ENERGY CORPORATION
Notes to the Consolidated Financial Statements
For the year ended December 31, 2013 and 2012
Structure of the Corporation and Basis of Presentation:
The principal undertakings of Bonavista Energy Corporation and its subsidiaries, (“Bonavista” or the “Corporation”), are to carry on
the business of acquiring, developing and holding interests in oil and natural gas properties and assets.
Bonavista's principal place of business is located at 1500, 525 - 8th Avenue SW, Calgary, Alberta, Canada T2P 1G1.
1. Basis of presentation:
a) Statement of compliance:
The consolidated financial statements (the "financial statements") have been prepared in accordance with International
Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board (IASB). A summary
of Bonavista's significant accounting policies under IFRS are presented in note 2. The consolidated financial statements
were authorized for issue by the Board of the Corporation on February 27, 2014.
b) Basis of measurement:
The consolidated financial statements have been prepared on the historical cost basis except for the following:
i)
derivative financial instruments are measured at fair value; and
ii)
liabilities for cash-settled share-based compensation are measured at fair market value.
c) Functional and presentation currency:
These consolidated financial statements are presented in Canadian dollars, which is the Corporation’s functional
currency.
d) Use of management’s judgments and estimates:
The preparation of the consolidated financial statements requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosures of contingencies, if any, as at the date of the
consolidated financial statements and the reported amounts of revenue and expenses during the period. Estimates are
subject to measurement uncertainty and changes in such estimates in future years could require a material change in the
consolidated financial statements. These underlying assumptions are based on historical experience and other factors
that management believes to be reasonable under the circumstances, and are subject to change as new events occur,
as more industry experience is acquired, as additional information is obtained and as the Corporation’s operating
environment changes.
Estimates and underlying assumptions are reviewed on an ongoing basis by management. Revisions to accounting
estimates are recognized in the period in which the estimates are revised and in any future periods affected. The key
sources of estimation uncertainty to the carrying amounts of assets and liabilities are discussed below:
i) Determination of a Cash Generating Unit (“CGU”):
The determination of Bonavista’s CGUs is subject to management’s judgment. In determining Bonavista’s CGUs
management assessed what constituted independent cash flows and how to aggregate the respective assets. The
asset composition of each CGU can directly impact the assessment of the recoverability of those assets included
within each CGU.
ii)
Impairment testing:
Bonavista assesses its property, plant and equipment for impairment when events or circumstances indicate that the
carrying amount of its assets may not be recoverable. If any indication of impairment exists, Bonavista performs an
impairment test on the CGU, which is the lowest level at which there are identifiable cash flows. The carrying amount
of each CGU is compared to its recoverable amount which is defined as the greater of its fair value less cost to sell
and value in use.
As at December 31, 2013 Bonavista evaluated each of its CGUs for indicators of impairment. In performing this
evaluation, management used the net present values for each CGU. Key estimates used in the determination of
these cash flows include: quantities of reserves and future production; future commodity pricing; development costs;
operating costs; royalty obligations; and discount rates. Any changes in these estimates may have an impact on the
recoverable amount of the CGU. For the year ended December 31, 2013 the following benchmark reference prices
were used by Bonavista’s independent reserve evaluator and adjusted for commodity differentials specific to the
Corporation.
31
Year
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
Remainder (1)
(1)
WTI Oil
(US$/bbl)
97.50
97.50
97.50
97.50
97.50
97.50
98.54
100.51
102.52
104.57
2.0%
AECO Gas
(CDN$/mmbtu)
4.03
4.26
4.50
4.74
4.97
5.21
5.33
5.44
5.55
5.66
2.0%
CDN$/US$
Exchange Rates
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
Percentage change represents the change in each year after 2023 to the end of the reserve life.
iii) Proved plus probable oil and natural gas reserves:
Reserve estimates are based on engineering data, estimated future prices, expected future rates of production and
the timing of future capital expenditures, all of which are subject to interpretation and uncertainty. Bonavista expects
that over time its reserve estimates will be revised either upward or downward depending upon the factors as stated
above. These reserve estimates can have a significant impact on net income, as it is a key component in the
calculation of depletion, depreciation and amortization, and also for the determination of potential asset impairments.
iv) Depreciation, depletion and amortization:
Property, plant and equipment is measured at cost less accumulated depreciation, depletion and amortization.
Bonavista’s oil and natural gas properties are depleted using the unit-of-production method over proved plus
probable reserves for each CGU. The unit-of-production method takes into account capital expenditures incurred to
date along with future development capital required to develop both proved plus probable reserves.
v) Decommissioning liability:
The provision for decommissioning liabilities is based on estimates of costs and planned remediation projects.
Actual costs may differ from those estimated due to changes in governing environment laws and regulations,
technological changes, and market conditions.
vi) Financial Instrument contracts:
The estimated fair value of financial instrument commodity contracts are subject to changes in forward looking
commodity prices, interest rate curves, volatility curves and counterparty non-performance risk. The estimated fair
values of the Corporation’s financial instrument contracts are subject to changes in foreign exchange rates.
2. Significant accounting policies:
The accounting policies set out below have been applied consistently to all periods presented in these consolidated financial
statements, and have been applied consistently by the Corporation and its subsidiaries.
a) Basis of consolidation:
The consolidated financial statements comprise the financial statements of the Corporation and its subsidiaries as at
December 31, 2013. Subsidiaries are consolidated from the date of acquisition, being the date on which the Corporation
obtains control, and continues to be consolidated until the date that control ceases. Control exists when the Corporation
has the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities. All
intercompany balances and transactions, and any unrealized income and expenses, arising from intercompany
transactions are eliminated in full.
32
Many of the Corporation's oil and natural gas activities involve jointly controlled assets. The consolidated financial
statements include the Corporation's share of these jointly controlled assets and a proportionate share of the relevant
revenue and related costs.
b) Foreign currency:
Monetary assets and liabilities denominated in foreign currencies are translated to Canadian dollars at the period end
exchange rate. Non-monetary assets and liabilities denominated in foreign currencies that are measured at fair value are
translated to the functional currency at the exchange rate at the date that the fair value was determined. Foreign currency
differences arising on translation are recognized in profit or loss.
c) Financial instruments:
i) Non-derivative financial assets:
The Corporation initially recognizes loans, receivables and deposits on the date that they are originated. All other
financial assets (including assets designated at fair value through profit or loss) are recognized initially on the date at
which the Corporation becomes a party to the contractual provisions of the instrument.
The Corporation derecognizes a financial asset when the contractual rights to the cash flows from the asset expire,
or it transfers the rights to receive the contractual cash flows on the financial asset in a transaction in which
substantially all the risks and rewards of ownership of the financial asset are transferred. Any interest in transferred
financial assets that is created or retained by the Corporation is recognized as a separate asset or liability.
Financial assets and liabilities are offset and the net amount is presented in the statement of consolidated financial
position when, and only when, the Corporation has a legal right to offset the amounts and intends either to settle on
a net basis or to realize the asset and settle the liability simultaneously.
The Corporation classifies non-derivative financial assets into the following categories: financial assets at fair value
through profit or loss, held-to-maturity financial assets, loans and receivables and available-for-sale financial assets.
Financial assets at fair value through profit or loss
A financial asset is classified at fair value through profit or loss if it is classified as held for trading or is designated as
such upon initial recognition. Financial assets are designated at fair value through profit or loss if the Corporation
manages such investments and makes purchase and sale decisions based on their fair value in accordance with the
Corporation’s documented risk management or investment strategy. Attributable transaction costs are recognized in
profit or loss as incurred. Financial assets at fair value through profit or loss are measured at fair value, and changes
therein are recognized in the consolidated statement of income.
Loans and receivables
Loans and receivables are financial assets with fixed or determinable payments that are not quoted in an active
market. Such assets are recognized initially at fair value plus any directly attributable transaction costs. Subsequent
to initial recognition, loans and receivables are measured at amortized cost using the effective interest method, less
any impairment losses.
Loans and receivables comprise of cash and cash equivalents, and trade and other receivables.
Cash and cash equivalents
Cash and cash equivalents comprise cash balances and call deposits with original maturities of three months or less.
ii) Non-derivative financial liabilities:
The Corporation initially recognizes debt securities issued and subordinated liabilities on the date that they are
originated. All other financial liabilities (including liabilities designated at fair value through profit or loss) are
recognized initially on the trade date at which the Corporation becomes a party to the contractual provisions of the
instrument.
The Corporation derecognizes a financial liability when its contractual obligations are discharged or cancelled or
expired.
The Corporation classifies non-derivative financial liabilities into the other financial liabilities category. Such financial
liabilities are recognized initially at fair value plus any directly attributable transaction costs. Subsequent to initial
recognition, these financial liabilities are measured at amortized cost using the effective interest method.
Other financial liabilities comprise loans and borrowings, bank overdrafts, and trade and other payables.
Bank overdrafts that are repayable on demand and form an integral part of the Corporation’s cash management are
included as a component of cash and cash equivalents for the purpose of the statement of cash flows.
iii) Derivative financial instruments:
The Corporation has entered into certain financial derivative contracts in order to manage the exposure to market
risks from fluctuations in commodity prices and foreign exchange rates. These instruments are not used for trading
or speculative purposes. The Corporation has not designated its financial derivative contracts as effective
accounting hedges, and thus not applied hedge accounting, even though the Corporation considers all commodity
contracts and foreign exchange contracts to be economic hedges. Derivatives are recognized initially at fair value
33
and any attributable transaction costs are recognized in profit or loss when incurred. Subsequent to initial
recognition, derivatives are measured at fair value, and changes therein are recognized immediately in profit or loss.
The Corporation has accounted for its forward physical delivery sales contracts, which were entered into and
continue to be held for the purpose of receipt or delivery, of non-financial items in accordance with its expected
purchase, sale or usage requirements as executory contracts. As such, these contracts are not considered to be
derivative financial instruments and have not been recorded at fair value on the balance sheet. Settlements on these
physical sales contracts are recognized in oil and natural gas revenues.
Embedded derivatives are separated from the host contract and accounted for separately if the economic
characteristics and risks of the host contract and the embedded derivative are not closely related, a separate
instrument with the same terms as the embedded derivative would meet the definition of a derivative, and the
combined instrument is not measured at fair value through profit or loss. Changes in the fair value of separable
embedded derivatives are recognized immediately in the consolidated statement of income.
Financial assets designated at fair value through profit or loss are comprised of interest rate swaps and forward
exchange contracts.
iv) Shareholders’ capital and Exchangeable shares:
Common shares and exchangeable shares are classified as equity. Incremental costs directly attributable to the
issue of common shares and share options are recognized as a deduction from equity, net of any tax effects.
d) Exploration and evaluation assets and property, plant and equipment:
i) Recognition and measurement:
Pre-licence costs are recognized in the consolidated statement of income as incurred.
Exploration and evaluation expenditures:
Exploration and evaluation (“E&E”) costs, including the costs of acquiring licences and directly attributable general
and administrative costs are initially capitalized as either tangible or intangible E&E assets according to the nature of
the assets acquired. The costs are accumulated in cost centres by well, field or exploration area pending
determination of technical feasibility and commercial viability.
E&E assets are assessed for impairment if: (a) sufficient data exists to determine technical feasibility and
commercial viability; and (b) facts and circumstances suggest that the carrying amount exceeds the recoverable
amount.
The technical feasibility and commercial viability of extracting a mineral resource is considered to be determinable
when total proved plus probable reserves are determined to exist. A review of each exploration licence or field is
carried out, at least annually, to ascertain whether proved plus probable reserves have been discovered. Upon
determination of total proved plus probable reserves, intangible E&E assets attributable to those reserves are
transferred from E&E assets to a separate category within tangible assets referred to as oil and natural gas
properties.
Development and production costs:
Items of property, plant and equipment, which include oil and natural gas development and production assets, are
measured at cost less accumulated depletion and depreciation and accumulated impairment losses. Development
and production assets are grouped into cash generating units for impairment testing.
Gains and losses on dispositions of property, plant and equipment, including oil and natural gas interests, are
determined by comparing the proceeds from disposal with the carrying amount of property, plant and equipment and
are recognized net within “gains (losses) on disposition of property, plant and equipment” in the consolidated
statement of income.
ii) Subsequent costs:
Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of
replacing parts of property, plant and equipment are recognized as oil and natural gas interests only when they
increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are
recognized in profit or loss as incurred. Such capitalized oil and natural gas interests generally represent costs
incurred in developing proved or proved plus probable reserves and bringing in or enhancing production from such
reserves, and are accumulated on a field or geotechnical area basis. The carrying amount of any replaced or sold
component is derecognized. The costs of the day-to-day servicing of property, plant and equipment are recognized
in the consolidated statement of income as incurred.
iii) Depletion, depreciation and amortization:
The net carrying amount of development or production assets is depleted using the unit-of-production method by
reference to the ratio of production in the year to the related proved plus probable reserves, taking into account
estimated future development costs necessary to bring those reserves into production. Future development costs
are estimated taking into account the level of development required to produce the reserves. These estimates are
reviewed by independent reserve engineers at least annually.
34
Proved plus probable reserves are estimated using independent reserve engineer reports and represent the
estimated quantities of oil, natural gas and natural gas liquids, which geological, geophysical and engineering data
demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which
are considered commercially producible. There should be a 50% statistical probability that the actual quantity of
recoverable reserves will be more than the amount estimated as proved plus probable and a 50% statistical
probability that it will be less. The equivalent statistical probabilities for the proven component of proved plus
probable reserves are 90% and 10%, respectively.
Such reserves may be considered commercially producible if management has the intention of developing and
producing them and such intention is based upon:
•
•
•
a reasonable assessment of the future economics of such production;
a reasonable expectation that there is a market for all or substantially all the expected oil and natural gas
production; and
evidence that the necessary production, transmission and transportation facilities are available or can be
made available.
Reserves may only be considered total proved plus probable if producibility is supported by either actual production
or conclusive formation test. The area of reservoir considered proved includes (a) that portion delineated by drilling
and defined by gas-oil and/or oil-water contacts, if any, or both, and (b) the immediately adjoining portions not yet
drilled, but which can be reasonably judged as economically productive on the basis of available geophysical,
geological and engineering data. In the absence of information on fluid contacts, the lowest known structural
occurrence of oil and natural gas controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application of improved recovery techniques (such as fluid
injection) are only included in the proved plus probable classification when successful testing by a pilot project, the
operation of an installed program in the reservoir, or other reasonable evidence (such as, experience of the same
techniques on similar reservoirs or reservoir simulation studies) provides support for the engineering analysis on
which the project or program was based.
The estimated useful lives for certain production assets for the current and comparative years are as follows:
Facilities
Oil and natural gas properties
15 years
Based on CGU Reserve Life
For other assets, depreciation is recognized in profit or loss on a straight-line basis over the estimated useful lives of
each part of an item of property, plant and equipment. Leased assets are depreciated over the shorter of the lease
term and their useful lives unless it is reasonably certain that the Corporation will obtain ownership by the end of the
lease term.
The estimated useful lives for other assets for the current and comparative years are as follows:
Office equipment
Fixtures and fittings
Leaseholds
5 years
5 years
9.5 years
Depreciation methods, useful lives and residual values are reviewed at each reporting date.
e) Goodwill and Exploration and evaluation assets:
i) Goodwill:
Goodwill arises on the acquisition of businesses, subsidiaries, associates and joint ventures. Goodwill is measured
at cost less accumulated impairment losses. Goodwill is evaluated for impairment on an annual basis, or more
frequently if potential indicators of impairment exist.
ii) Exploration and evaluation assets:
Other intangible assets that are acquired by the Corporation, which have finite useful lives, are measured at cost
less accumulated amortization and accumulated impairment losses.
Subsequent expenditure is capitalized only when it increases the future economic benefits embodied in the specific
asset to which it relates.
Amortization is recognized in profit or loss on a straight-line basis over the estimated useful lives of other intangible
assets, other than goodwill, from the date they were available for use.
35
f)
Impairment:
i) Non-derivative financial assets:
A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is
impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have
had a negative effect on the estimated future cash flows of that asset.
An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference
between its carrying amount and the present value of the estimated future cash flows discounted at the original
effective interest rate.
Individually significant financial assets are tested for impairment on an individual basis. The remaining financial
assets are assessed collectively in groups that share similar credit risk characteristics.
All impairment losses are recognized in the consolidated statement of income.
An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment
loss was recognized. For financial assets measured at amortized cost the reversal is recognized in the consolidated
statement of income.
ii) Non-financial assets:
The carrying amounts of the Corporation’s non-financial assets, other than E&E assets and deferred income tax
assets, are reviewed at each reporting date to determine whether there is any indication of impairment. If any such
indication exists, then the asset’s recoverable amount is estimated. For goodwill and other intangible assets that
have indefinite lives or that are not yet available for use an impairment test is completed each year. E&E assets are
assessed for impairment when they are reclassified to property, plant and equipment, as oil and natural gas
interests, and also if facts and circumstances suggest that the carrying amount exceeds the recoverable amount.
For the purpose of impairment testing, assets are grouped together into the smallest group of assets that generates
cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets,
the CGU. The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs
to sell.
In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax
discount rate that reflects current market assessments of the time value of money and the risks specific to the asset.
Value in use is generally computed by reference to the present value of the future cash flows expected to be derived
from production of proved plus probable reserves.
The goodwill acquired in a business combination, for the purpose of impairment testing, is allocated to the CGUs
that are expected to benefit from the synergies of the combination.
An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable
amount. Impairment losses are recognized in profit or loss. Impairment losses recognized in respect of CGUs are
allocated first to reduce the carrying amount of any goodwill allocated to the units and then to reduce the carrying
amounts of the other assets in the unit (group of units) on a pro rata basis.
An impairment loss in respect of goodwill is not reversed. In respect of other assets, impairment losses recognized in
prior years are assessed at each reporting date for any indications that the loss has decreased or no longer exists.
An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable
amount. An 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 or amortization, if no
impairment loss had been recognized.
g) Employee benefits:
i) Share-based compensation:
Long-term incentives are granted to officers, directors, employees and certain consultants in accordance with the
Corporation’s stock option, incentive award and restricted share award plans.
The fair value of stock options is assessed on the grant date using the Black-Scholes option pricing model. The fair
value is subsequently recognized as compensation expense over the vesting period with a corresponding increase
in contributed surplus. Upon exercise of the options, consideration paid by the stock option holders and the value in
contributed surplus pertaining to the exercised options are recorded as shareholders’ capital.
The fair value of incentive awards and restricted share awards is assessed on the grant date factoring in the
weighted average trading price of the five days preceding the grant date and forecasted dividends. This fair value is
recognized as compensation expense over the vesting period with a corresponding increase in contributed surplus.
Upon the conversion of the restricted share awards or the settlement of the incentive awards by common shares, on
the predetermined vesting dates, the value in contributed surplus pertaining to the awards is recorded as
shareholders’ capital.
Under both incentive plans, forfeiture rates are assigned in the determination of fair value. Upon vesting, the
difference between estimated and actual forfeitures is adjusted through share-based compensation.
36
ii) Short-term employee benefits:
Short-term employee benefit obligations are expensed as the related service is provided. A liability is recognized for
the amount expected to be paid under short-term cash bonus or profit-sharing plans if the Corporation has a present
legal or constructive obligation to pay this amount as a result of past service provided by the employee, and the
obligation can be estimated reliably.
h) Lease payments:
Payments made under operating leases are recognized in profit and loss on a straight-line basis over the term of the
lease. Lease incentives received are recognized as an integral part of the total lease expense, over the term of the
lease.
i) Provisions:
A provision is recognized if, as a result of a past event, the Corporation has a present legal or constructive obligation that
can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation.
Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market
assessments of the time value of money and the risks specific to the liability. Provisions are not recognized for future
operating losses.
j) Decommissioning liabilities:
The Corporation’s activities give rise to dismantling, decommissioning and site disturbance remediation activities.
Provision is made for the estimated cost of site restoration and capitalized in the relevant asset category.
Decommissioning liabilities are measured at the present value of management’s best estimate of expenditure required to
settle the present obligation at the balance sheet date. Subsequent to the initial measurement, the obligation is adjusted
at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the
obligation. The increase in the provision due to the passage of time is recognized as finance costs whereas
increases/decreases due to changes in the estimated future cash flows are capitalized. Actual costs incurred upon
settlement of the decommissioning obligations are charged against the provision to the extent the provision was
established.
k) Revenues:
Revenues from the sale of oil and natural gas are recorded when the significant risks and rewards of ownership of the
product is transferred to the buyer, which is usually when legal title passes to the external party. This is generally at the
time product enters the pipeline. Revenues are measured net of discounts, customs, duties and royalties. With respect to
the latter, the entity is acting as a collection agent on behalf of others.
Royalty income is recognized as it accrues in accordance with the terms of the overriding royalty agreements.
l) Finance income and costs:
Finance costs comprise of interest expense on borrowings, unwinding of the discount on provisions and impairment
losses recognized on financial assets, fair value losses on financial assets at fair value through profit and loss.
Interest income is recognized as it accrues in profit or loss, using the effective interest method.
Foreign currency gains and losses, are reported under finance income or expenses.
m)
Income taxes:
Income tax expense comprises current and deferred income taxes. Current and deferred income taxes are recognized in
the consolidated statement of income except to the extent that it relates to a business combination, or items recognized
directly in equity or in other comprehensive income.
Current tax is the expected tax payable or receivable on the taxable income or loss for the period, using tax rates
enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.
Deferred income taxes are recognized in respect of temporary differences between the carrying amounts of assets and
liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred income taxes are not
recognized for:
•
•
•
temporary differences on the initial recognition of assets or liabilities in a transaction that is not a business
combination and that affects neither accounting nor taxable profit or loss; and
temporary differences related to investments in subsidiaries to the extent that it is probable that they will not
reverse in the foreseeable future; and
taxable temporary differences arising on the initial recognition of goodwill.
Deferred income taxes are measured at the tax rates that are expected to be applied to temporary differences when they
reverse, based on the laws that have been enacted or substantively enacted by the reporting date.
37
Deferred income tax assets and liabilities are offset if there is a legally enforceable right to offset current tax liabilities and
assets, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax
entities, but they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be
realized simultaneously.
A deferred income tax asset is recognized for unused tax losses, tax credits and deductible temporary differences, to the
extent that it is probable that future taxable profits will be available against which they can be utilized. Deferred income
tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related
tax benefit will be realized.
n) Net income per share:
Basic net income per share is calculated by dividing the profit or loss attributable to common shareholders of the
Corporation by the weighted average number of common shares outstanding during the period. Diluted net income per
share is determined by adjusting the profit or loss attributable to common shareholders and the weighted average
number of common shares outstanding for the effects of dilutive instruments such as options granted to employees.
3. New accounting standards:
Changes in accounting policies
On January 1, 2013, Bonavista adopted the following new standards and amendments which became effective for annual
periods on or after January 1, 2013:
•
•
•
•
IFRS 10, “Consolidated Financial Statements,” supersedes IAS 27 “Consolidated and Separate Financial
Statements” and SIC-12 “Consolidation - Special Purpose Entities”. This standard provides a single model to be
applied in control analysis for all investees including special purpose entities. The adoption of this standard had no
impact on the amounts recorded in Bonavista’s financial statements.
IFRS 11, “Joint Arrangements,” whereby joint arrangements are classified as either joint operations or joint ventures,
each with their own accounting treatment. All joint arrangements are required to be reassessed on transition to
IFRS 11 to determine their type to apply the appropriate accounting. The adoption of this standard had no impact on
the amounts recorded in Bonavista’s financial statements.
IFRS 12, “Disclosure of Interest in Other Entities,” combines the disclosure requirements for entities that have
interest in subsidiaries, joint arrangements, and associates as well as unconsolidated structured entities. The
adoption of this standard had no impact on Bonavista’s financial statements.
IFRS 13, “Fair Value Measurement,” establishes a framework for measuring fair value and sets out disclosure
requirements for fair value measurements. This standard defines fair value as the price that would be received to
sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement
date. The standard also requires additional annual fair value disclosures, as well as additional interim disclosures.
The adoption of this standard had no material impact on Bonavista’s financial statements.
• Amendments to IAS 32, “Financial Instruments: Presentation” clarify the requirements for offsetting financial assets
with financial liabilities. Amendments to IFRS 7, "Financial Instruments: Disclosures," develop common disclosure
requirements for financial assets and financial liabilities that are offset in the financial statements, or that are subject
to enforceable master netting arrangements or similar agreements. The adoption of these amendments has no
impact on Bonavista's financial statements.
Future accounting policies
In May 2013, the IASB issued amendments to IAS 36, “Impairment of Assets” which will restrict the requirements to disclose
the recoverable amount of an asset or CGU to periods in which an impairment loss has been recognized or reverses. The
amendment also expands and clarifies the disclosure requirements applicable when an impairment loss has been recognized
or reversed in the period. The amendments apply retrospectively for annual periods beginning on or after January 1, 2014.
Bonavista plans to adopt the amendments in its financial statements for the annual period beginning on January 1, 2014. The
adoption will impact Bonavista’s disclosures in the notes to the financial statements in periods when an impairment loss or
impairment reversal is recognized.
In May 2013, the IASB issued IFRIC 21, “Levies” which provides guidance on accounting for levies in accordance with the
requirements of IAS 37, “Provisions, Contingent Liabilities and Contingent Assets”. The interpretation clarifies that an entity is
to recognize a liability for a levy when the activity that triggers payment, as identified by the relevant legislation, occurs. The
interpretation also clarifies that a levy liability is to be accrued progressively only if the activity that triggers payment occurs
over a period of time, in accordance with the relevant legislation. IFRIC 21 is effective for annual periods commencing on or
after January 1, 2014 and is to be applied retrospectively. Bonavista intends to adopt IFRIC 21 in its financial statements for
the annual periods beginning on January 1, 2014. Bonavista is currently assessing but has not yet determined the impact of
the adoption of the amendments.
In November 2013, the IASB issued amendments to the recognition, presentation and disclosure to pension accounting under
IAS 19, “Employee Benefits”. The amendments apply retrospectively for annual periods beginning on or after July 1, 2014.
Bonavista intends to adopt these amendments in its financial statements for the annual period beginning on January 1, 2014;
no impact to the financial statements is expected.
38
In November 2009 the IASB issued IFRS 9, “Financial Instruments” as the first step in its project to replace IAS 39 “Financial
Instruments: Recognition and Measurement”. IFRS 9 introduced new requirements for classifying and measuring financial
assets. On October 28, 2010, the IASB reissued IFRS 9, incorporating new requirements on accounting for financial
liabilities. The new standard eliminates the existing multiple classification and measurement categories under IAS 39 of
held-to-maturity, available-for-sale and loans receivable and replaces them with a single model that has only two classification
categories: amortized cost and fair value.
In November 2013, the IASB issued a new general hedge accounting standard which forms part of IFRS 9. While hedge
accounting remains optional under IFRS 9, the new general hedge accounting statement was designed to more closely align
hedge accounting with the risk management activities of an entity. The new standard does not fundamentally change the
types of hedging relationships or the requirements to measure and recognize ineffectiveness, however, it does provide for
more hedging strategies to qualify for hedge accounting and introduces more judgment into the assessment of hedge
effectiveness. In July of 2013, the IASB deferred the mandatory effective date of IFRS 9, which previously had been effective
for annual periods beginning on or after January 1, 2015. The IASB has yet to determine the mandatory effective date; early
adoption of the new standard is still permitted. The extent of the impact of the adoption of IFRS 9 on Bonavista’s financial
statements has not yet been determined.
In December 2013, the IASB issued narrow-scope amendments to a total of nine standards as part of its annual improvement
process. The improvement process is designed to make non-urgent but necessary amendments to IFRS. Some of the
amendments made to the existing standards included; clarifying the definition of “vesting conditions” in IFRS 2, “Share-based
payment”; defining the classification and measurement of contingent consideration; scope exclusion for the formation of joint
arrangements in IFRS 3, “Business Combinations”; and modifying the definition of a “related party” in IAS 24, “Related Party
Disclosures”. Bonavista intends to adopt these amendments in its financial statement for the annual period beginning on
January 1, 2014. The adoption of these amendments is not expected to have a material impact on the financial statements.
4. Financial risk management:
Bonavista has exposure to credit and market risks from its use of financial instruments. This note provides information about
the Corporation's exposure to each of these risks, the Corporation's objectives, policies and processes for measuring and
managing risk. Further quantitative disclosures are included throughout these financial statements.
a)
Credit risk:
Credit risk is the risk of financial loss to the Corporation if a customer or counterparty to a financial instrument fails to
meet its contractual obligation and arises, primarily from joint venture partners, marketers and financial intermediaries.
The Corporation’s accounts receivable are with customers and joint venture partners in the oil and natural gas business
and are subject to normal credit risks. Concentration of credit risk is mitigated by marketing production to numerous
purchasers under normal industry sale and payment terms. The Corporation routinely assesses the financial strength of
its customers.
The Corporation may be exposed to certain losses in the event of non-performance by counterparties to financial
instrument contracts. The Corporation mitigates this risk by entering into transactions with highly rated financial
institutions.
The carrying amount of accounts receivable represents the maximum credit exposure. As at December 31, 2013
Bonavista’s receivables consisted of $89.0 million of receivables from oil and natural gas marketers which has
substantially been collected subsequent to December 31, 2013 and $32.6 million from joint venture partners of which
$13.8 million has been subsequently collected. As at December 31, 2013 Bonavista has $10.2 million in accounts
receivable that is considered to be past due. Although these amounts have been outstanding for greater than 90 days,
they are still deemed to be collectible. As the operator of properties, Bonavista has the ability to withhold production to
joint venture partners, who are in default of amounts owing. The Corporation does not have an allowance for doubtful
accounts as at December 31, 2013 and did not provide for any doubtful accounts during the year ended December 31,
2012.
b) Liquidity risk:
Liquidity risk is the risk that Bonavista will encounter difficulty in meeting obligations associated with the financial
liabilities. The Corporation's financial liabilities consist of accounts payable and accrued liabilities, dividends payable,
financial instruments contracts, bank debt, and senior unsecured notes. Accounts payable consists of invoices payable to
trade suppliers for office, field operating activities, and capital expenditures. Bonavista processes invoices within a
normal payment period.
Accounts payable and accrued liabilities have contractual maturities of less than one year. Dividends payable are
declared on a monthly basis and are dependent upon a number of factors including current and future commodity prices,
foreign exchange rates, Bonavista’s commodity hedging program, current operations and future investment opportunities.
Financial instrument contracts have contractual maturities of less than three years on all commodity contracts and range
from three to ten years on foreign exchange hedge contracts. Bonavista’s four year revolving credit facility, as outlined in
note 12, may at the request of the Corporation with the consent of the lenders, be extended on an annual basis beyond
the existing term. The Corporation also has a series of senior unsecured notes outstanding, as outlined in note 12, which
range in maturities from November 2, 2015 to May 23, 2025. The Corporation also maintains and monitors a certain
level of cash flow, which is used to partially finance all operating, investing and capital expenditures.
39
c) Commodity price risk:
Commodity price risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in commodity
prices. Commodity prices for oil and natural gas are impacted not only by global economic events that dictate the levels
of supply and demand but also by the relationship between the Canadian and United States dollar.
Bonavista mitigates a portion of the commodity price risk through the use of various financial instrument commodity
contracts and physical delivery sales contracts. The Corporation's policy is to enter into commodity price contracts when
considered appropriate to a maximum of 70% for 2014 budgeted revenues, net of royalties and 60% thereafter, provided
that no more than 80% of forecasted revenues, net of royalties, from any one product may be hedged, or in the case of
electricity, 60% of Bonavista's forecasted net consumption. The term of any commodity hedge executed will be limited to
no more than three calendar years subsequent to the current calendar year.
Financial instrument commodity contracts:
As at December 31, 2013, Bonavista entered into the following costless collars to sell oil and natural gas as follows:
Volume
Average Price
Term
5,000
40,000
15,000
15,000
10,000
20,000
8,000
3,500
500
gjs/d
gjs/d
gjs/d
gjs/d
gjs/d
gjs/d
bbls/d
bbls/d
bbls/d
CDN $3.50 - CDN $4.00 - AECO
CDN $2.93 - CDN $3.73 - AECO
CDN $3.33 - CDN $4.09 - AECO
CDN $3.38 - CDN $3.95 - AECO
CDN $2.85 - CDN $3.50 - AECO
CDN $3.53 - CDN $4.02 - AECO
CDN $89.78 - CDN $98.65 - WTI
CDN $88.36 - CDN $98.09 - WTI
CDN $87.50 - CDN $97.50 - WTI
January 1, 2014 - March 31, 2014
January 1, 2014 - December 31, 2014
January 1, 2014 - December 31, 2014
January 1, 2014 - December 31, 2015
April 1, 2014 - October 31, 2014
January 1, 2015 - December 31, 2015
January 1, 2014 - December 31, 2014
January 1, 2014 - December 31, 2015
January 1, 2015 - December 31, 2015
Subsequent to December 31, 2013, Bonavista entered into the following costless collars to sell oil and natural gas as
follows:
Volume
10,000
5,000
25,000
Average Price
Term
gjs/d
gjs/d
gjs/d
CDN $3.50 - CDN $3.75 - AECO
CDN $3.50 - CDN $4.00 - AECO
CDN $3.50 - CDN $3.87 - AECO
April 1, 2014 - October 31, 2014
November 1, 2014 - March 31, 2015
January 1, 2015 - December 31, 2015
As at December 31, 2013, Bonavista entered into the following contracts to manage its overall commodity exposure:
Volume
55,000
10,000
5,000
5,000
40,000
5,000
5,000
25,000
15,825
26,375
35,000
5,000
500
gjs/d
gjs/d
gjs/d
gjs/d
gjs/d
gjs/d
gjs/d
gjs/d
gjs/d
gjs/d
gjs/d
gjs/d
bbls/d
Price
CDN $3.45
CDN $3.52
CDN $3.35
CDN $3.48
CDN $3.63
CDN $3.49
CDN $3.71
CDN $3.53
US $3.62
US $3.80
US $(0.48)
US $(0.48)
US 50%
Contract
Term
Swap - AECO
Swap - AECO
Swap - AECO
Swap - AECO
Swap - AECO
Swap - AECO
Swap - AECO
Swap - AECO
Swap - NYMEX
Swap - NYMEX
Swap - NYMEX Basis
Swap - NYMEX Basis
Swap - CNWY/WTI
January 1, 2014 - December 31, 2014
January 1, 2014 - December 31, 2015
January 1, 2014 - March 31, 2014
April 1, 2014 - October 31, 2014
April 1, 2014 - December 31, 2014
April 1, 2014 - March 31, 2015
November 1, 2014 - March 31, 2015
January 1, 2015 - December 31, 2015
April 1, 2014 - October 31, 2014
April 1, 2014 - December 31 2014
April 1, 2014 - December 31, 2014
November 1, 2014 - December 31, 2014
April 1, 2014 - March 31, 2015
Subsequent to December 31, 2013, Bonavista entered into the following contracts to manage its overall commodity
exposure:
Volume
10,000
75,000
1,000
gjs/d
gjs/d
bbls/d
Price
CDN $3.90
CDN $3.73
US 51%
Contract
Term
Swap - AECO
Swap - AECO
Swap - CNWY/WTI
April 1, 2014 - October 31, 2014
January 1, 2015 - December 31, 2015
April 1, 2014 - March 31, 2015
40
As at December 31, 2013, Bonavista entered into the following contracts to purchase electricity:
Volume
6
2
Mwh
Mwh
Price
CDN $50.88
CDN $52.00
Contract
Swap - AESO
Swap - AESO
Term
January 1, 2014 - December 31, 2015
January 1, 2016 - December 31, 2016
Financial instrument commodity contracts are recorded on the consolidated statement of financial position at fair value at
each reporting period with the change in fair value being recognized as an unrealized gain or loss on the consolidated
statements of income and comprehensive income.
A $0.10 change in the price per thousand cubic feet of natural gas - AECO would have an impact of approximately
$6.8 million on net
in place as at
December 31, 2013 (2012 - $3.5 million). A $1.00 change in the price per barrel of oil - WTI would have an impact of
approximately $3.5 million on net income for those financial instrument commodity contracts that were in place as at
December 31, 2013 (2012 - $1.6 million).
instrument commodity contracts
that were
financial
income
those
for
d) Foreign exchange risk:
Commodity prices are largely denominated in US dollars and as a result the prices that Canadian producers receive is
determined by the relationship between the US and Canadian dollar. In addition, Bonavista also has US denominated
debt and interest obligations of which future cash payments are directly impacted by the exchange rate in effect on the
due date.
On July 21, 2011, Bonavista entered into an agreement with three financial intermediaries to purchase the following US
dollars that coincide with Bonavista’s note repayment commitments:
Forward date
November 2, 2017
November 2, 2020
November 2, 2022
Contract
US$ purchased forward
US$ purchased forward
US$ purchased forward
Notional US$
$30,000,000
$53,300,000
$16,500,000
CDN$/US$
0.995
0.995
0.995
A $0.01 change in CDN$/US$ exchange rate would have an impact of approximately $709,000 on net income for those
foreign exchange forward contracts in place as at December 31, 2013 (2012 - $655,000).
e)
Interest rate risk:
Bonavista is exposed to interest rate risk on its outstanding bank debt, as it has a floating interest rate and consequently
changes to interest rates would impact the Corporation’s future cash flows. If interest rates applicable to the variable rate
debt increases by 1% it is estimated that Bonavista’s net income for the year ended December 31, 2013 would decrease
by $2.2 million (2012 - $3.6 million).
Fair value of financial instruments:
The fair value of the financial instruments carried on Bonavista’s consolidated statement of financial position is classified
according to the following hierarchy based on the amount of observable inputs used to value the financial instruments.
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 – valuation in this level are those with inputs for the asset or liabilities that are not based on observable market data.
The Corporation’s marketable securities have been classified as Level 1, financial instrument contracts, bank debt and senior
unsecured notes are classified as Level 2.
41
The fair market value recorded on the consolidated statements of financial position for these financial instrument contracts
were as follows:
(thousands)
Current asset:
Marketable securities(1)
Financial instrument commodity contract(2)
Long-term asset:
Financial instrument commodity contract(2)
Financial instrument contract(2)
Current liabilities:
Financial instrument commodity contract(2)
Long-term liability:
Financial instrument commodity contract(2)
Net asset/(liability)
(1)
(2)
Level 1
Level 2
December 31,
December 31,
2013
2012
$
2,645
419
$
2,768
8,608
346
8,023
1,224
4,293
(31,985)
(8,786)
(3,710)
(1,550)
$
(24,262)
$
6,557
Bank debt bears interest at a floating market rate and accordingly the fair market value approximates the carrying value.
The fair market value of the senior unsecured notes as at December 31, 2013 is approximately $789.2 million
(2012 - $579.8 million), compared to a carrying amount of $819.8 million (2012 - $547.5 million).
5. Capital management:
The Corporation's objective when managing capital is to maintain a flexible capital structure which allows it to execute its
growth strategy through strategic acquisitions and expenditures on exploration and development activities while maintaining a
strong financial position that provides its shareholders with stable dividends and rates of return.
The Corporation considers its capital structure to include working capital (excluding associated assets and liabilities from
financial instrument contracts and decommissioning liabilities), bank debt, senior unsecured notes and shareholders' equity.
Bonavista monitors capital based on the ratio of net debt to annualized funds from operations. The ratio represents the time
period it would take to pay off the debt if no further capital expenditures were incurred and if funds from operations remained
constant. This ratio is calculated as net debt, defined as outstanding bank debt, senior unsecured notes and working capital,
divided by funds from operations for the most recent calendar quarter, annualized (multiplied by four). The Corporation's
strategy is to maintain a ratio of less than 2.0 to 1. This strategy is more restrictive than the existing financial covenants on
both the Corporation's bank credit facility and senior unsecured notes. This ratio may increase at certain times as a result of
acquisitions or low commodity prices. As at December 31, 2013, Bonavista’s ratio of net debt to fourth quarter annualized
funds from operations was 2.1 to 1 (2012 - 2.2 to 1), which is slightly above the range established by the Corporation.
The following table reconciles funds from operations to its nearest measure prescribed by IFRS, cash flow from operating
activities.
Calculation of Funds From Operations:
(thousands)
Cash flow from operating activities
Interest expense
Decommissioning expenditures
Changes in non-cash working capital
Funds from operations
Fourth quarter annualized
Three months ended
Three months ended
December 31, 2013
December 31, 2012
$
$
$
115,021
(11,076)
10,539
9,870
124,354
497,416
$
$
$
102,886
(9,487)
11,410
5,206
110,015
440,060
To facilitate the management of this ratio, the Corporation prepares annual funds from operations and capital expenditure
budgets, which are updated as necessary, and are reviewed and periodically approved by Bonavista’s Board of Directors.
The Corporation manages its capital structure and makes adjustments by continually monitoring its business conditions,
including: the current economic conditions; the risk characteristics of Bonavista’s oil and natural gas assets; the depth of its
investment opportunities; current and forecasted net debt levels; current and forecasted commodity prices; and other factors
that influence commodity prices and funds from operations, such as quality and basis differentials, royalties, operating costs
and transportation costs.
42
To maintain or adjust the capital structure, Bonavista will consider: its forecasted ratio of net debt to forecasted funds from
operations while attempting to finance an acceptable capital expenditure program including acquisition opportunities; the
current level of bank credit available from the Corporation's lenders; the availability of other sources of debt with different
characteristics than the existing bank debt; the sale of assets; limiting the size of the capital expenditure program; issuance of
new equity if available on favourable terms; and its level of dividends payable to its shareholders. The Corporation's
shareholders' capital is not subject to external restrictions, however, the Corporation's bank credit facility and senior
unsecured notes do contain financial covenants that are outlined in note 12 of the consolidated financial statements.
6. Finance costs and income:
a) Finance costs:
Finance costs:
Interest on bank debt
Interest on notes payable
Accretion of decommissioning liabilities
Unrealized loss on marketable securities
Foreign exchange loss
Accretion on other liabilities
Finance costs
b) Finance income:
Finance income:
Unrealized gain on financial instrument contracts
Foreign exchange gain
Finance income
Year ended
December 31, 2013
Year ended
December 31, 2012
13,347
30,339
10,566
123
42,373
1,691
98,439
$
19,278
23,445
9,895
732
-
-
$
53,350
Year ended
December 31, 2013
Year ended
December 31, 2012
(3,730)
-
(3,730)
$
$
(689)
(11,050)
(11,739)
$
$
$
$
The Corporation’s effective interest rate for the year ending December 31, 2013 was approximately 4.4% (2012 - 4.1%).
7. Supplemented cash flow information:
Changes in non-cash working capital is comprised of:
Year ended
December 31, 2013
Year ended
December 31, 2012
Source/(use) of cash
Accounts receivable
Prepaid expenses
Marketable securities
Other assets
Accounts payable and accrued liabilities, net of
interest accrual
Related to:
Operating activities
Investing activities
$
$
$
$
(21,931)
3,767
-
(1,595)
28,749
8,990
(2,830)
11,820
8,990
$
$
$
$
30,824
(1,429)
(3,500)
(3,536)
3,503
25,862
13,466
12,396
25,862
43
8.
Property, plant and equipment:
Cost:
Oil and natural
gas properties
Facilities
Other
assets
Total
Balance as at December 31, 2011
$ 3,588,447
$
494,132
$
15,068
$ 4,097,647
Additions
Acquisitions
Transfer from exploration and evaluation
Changes in decommissioning liabilities
380,105
148,574
25,076
19,256
9,943
32,767
-
-
Dispositions
(129,831)
(24,561)
3,307
-
-
-
-
393,355
181,341
25,076
19,256
(154,392)
Balance as at December 31, 2012
$ 4,031,627
$
512,281
$
18,375
$ 4,562,283
Additions
Acquisitions
Transfer from exploration and evaluation
Changes in decommissioning liabilities
Dispositions
412,638
116,156
15,563
(26,607)
(77,414)
15,409
25,797
-
-
(14,909)
6,183
-
-
-
-
434,230
141,953
15,563
(26,607)
(92,323)
Balance as at December 31, 2013
$ 4,471,963
$
538,578
$
24,558
$ 5,035,099
Depletion, depreciation and amortization:
Balance as at December 31, 2011
$
(532,427)
$
(43,187)
$
(3,186)
$
(578,800)
Depletion, depreciation and amortization
Dispositions
(304,746)
35,301
(23,703)
3,811
(2,574)
(331,023)
-
39,112
Balance as at December 31, 2012
$
(801,872)
$
(63,079)
$
(5,760)
$
(870,711)
Depletion, depreciation and amortization
Dispositions
(320,117)
27,431
(25,740)
2,810
(3,428)
(349,285)
-
30,241
Balance as at December 31, 2013
$ (1,094,558)
$
(86,009)
$
(9,188)
$ (1,189,755)
Net book value as at December 31, 2013
$ 3,377,405
$
452,569
$
15,370
$ 3,845,344
Net book value as at December 31, 2012
$ 3,229,755
$
449,202
$
12,615
$ 3,691,572
For the year ended December 31, 2013, Bonavista capitalized $8.7 million (2012 - $8.8 million) of direct general and
administrative expenses.
9. Goodwill and Exploration and evaluation assets :
(thousands)
Balance as at December 31, 2011
$
11,225
$
233,642
Goodwill
Exploration and
evaluation assets
Additions
Acquisitions
Dispositions
Transfers to property, plant and equipment
-
-
-
-
14,520
6,127
(11,831)
(25,076)
Balance as at December 31, 2012
$
11,225
$
217,382
Additions
Acquisitions
Dispositions
Transfers to property, plant and equipment
-
-
-
-
24,825
2,876
(7,435)
(15,563)
Balance as at December 31, 2013
$
11,225
$
222,085
Exploration and evaluation assets consist of the Corporation’s exploration projects which are pending the determination of
proved or probable reserves. Additions represent the Corporation’s share of costs incurred on E&E assets during the year.
44
There were no incidents of impairment identified on the Corporation’s exploration and evaluation assets for the years ended
December 31, 2013 and December 31, 2012.
The impairment test of goodwill concluded that the estimated recoverable amount exceeded the carrying amount for the years
ended December 31, 2013 and December 31, 2012. As such, no goodwill impairment existed.
10. Acquisitions:
a) On January 9, 2013, Bonavista completed the acquisition of certain multi-zone oil and liquids rich natural gas assets
located within its Deep Basin core area in west central Alberta. The assets were acquired for cash consideration of
$72.5 million. The amounts recognized on the date of acquisition to identifiable net assets were as follows:
(thousands)
Net assets acquired:
Exploration and evaluation assets
Facilities
Oil and natural gas properties
Decommissioning liabilities
Net assets acquired
(thousands)
Purchase consideration:
Cash
Total purchase consideration
Amount
$
2,682
14,080
64,916
(9,189)
$
72,489
$
$
72,489
72,489
In the period from January 9, 2013 to December 31, 2013, the acquisition contributed revenues of $18.8 million and net
income of $2.4 million, which are included in the consolidated statement of income for the year ended
December 31, 2013. In conjunction with the transaction, Bonavista expensed $95,000 of applicable transaction costs.
b) On November 6, 2013, Bonavista completed the acquisition of certain multi-zone oil and liquids rich natural gas assets
located within its Deep Basin core area in west central Alberta. The assets were acquired for cash consideration and oil
and natural gas properties totaling $42.6 million. The amounts recognized on the date of acquisition to identifiable net
assets were as follows:
(thousands)
Net assets acquired:
Exploration and evaluation assets
Facilities
Oil and natural gas properties
Decommissioning liabilities
Net assets acquired
(thousands)
Purchase consideration:
Cash
Oil and natural gas properties
Total purchase consideration
Amount
$
194
8,800
36,415
(2,767)
$
42,642
$
$
29,795
12,847
42,642
In the period from November 6, 2013 to December 31, 2013 the acquisition contributed revenues of $1.5 million and net
income of $193,000 which is included in the consolidated statement of income for the year ended December 31, 2013. If
the acquisition had occurred on January 1, 2013, management estimates that the acquisition would have contributed
revenues of $10.5 million and net income of $1.2 million for the year ended December 31, 2013. In conjunction with the
transaction, Bonavista expensed $25,000 of applicable transaction costs.
c) Subsequent to December 31, 2013, Bonavista disposed of non-core properties for proceeds of approximately $103
million with combined production of approximately 2,500 boe per day. These properties are located in northwest Alberta
and the Provost area of Alberta.
45
11. Shareholders' equity:
The Corporation is authorized to issue an unlimited number of common shares without nominal or par value, an unlimited
number of exchangeable shares without nominal or par value and 10,000,000 preferred shares, issuable in series.
The holders of common shares are entitled to receive dividends as declared by the Corporation and are entitled to one
vote per share. Dividends declared for the year ended December 31, 2013 were $0.84 per share (2012 -
$1.44 per share).
Bonavista announced that it had adopted a dividend reinvestment plan ("DRIP") and stock dividend plan (“SDP”) on
December 31, 2011 and May 3, 2012 respectively. The DRIP and SDP provide eligible holders of common shares the
option to reinvest cash dividends into common shares issued either from treasury at a five per cent discount to the
prevailing average market price or acquired through the facilities of the Toronto Stock Exchange at prevailing market
rates with no discount. Under the DRIP, a cash dividend is paid to the common shareholder and then immediately
reinvested in new common shares. Under the SDP program, dividends are paid directly in common shares to electing
participants. The implementation of the DRIP began in January 2012 and the implementation of the SDP began in
June 2012.
The exchangeable shares of Bonavista are exchangeable into common shares based on the exchange ratio, which is
adjusted monthly, to reflect dividends paid on common shares. As a result, dividends are not paid on exchangeable
shares. The holders of exchangeable shares are entitled to one vote times the exchange ratio for each exchangeable
share.
a)
Issued and outstanding:
i) Common shares:
(thousands)
Balance as at December 31, 2011
Issued for cash
Issued on conversion of exchangeable shares
Issued pursuant to the dividend reinvestment and
stock dividend plans
Issued upon exercise of common share incentive rights
Share-based compensation
Issue costs, net of future tax benefit
Conversion of restricted share awards
Balance as at December 31, 2012
Issued on conversion of exchangeable shares
Issued pursuant to the dividend reinvestment and
stock dividend plans
Issued upon exercise of common share incentive rights
Share-based compensation
Issue costs, net of future tax benefit
Conversion of restricted share awards
Number of
Shares
144,098
20,930
6,953
5,034
372
-
-
135
177,522
4,023
4,562
208
-
-
647
Amount
$ 1,446,804
345,345
180,571
82,892
4,510
9,792
(10,609)
-
$ 2,059,305
97,715
59,162
1,984
10,118
(74)
-
Balance as at December 31, 2013
186,962
$ 2,228,210
ii) Exchangeable shares:
(thousands)
Balance, beginning of year
Exchanged for common shares
Balance, end of year
Exchange ratio, end of year
Year ended
December 31, 2013
Year ended
December 31, 2012
Number
Amount
Number
Amount
14,069
(3,393)
$ 405,183
(97,715)
20,339
(6,270)
$ 585,754
(180,571)
10,676
$ 307,468
14,069
$ 405,183
1.20836
-
1.13313
-
Common shares issuable on exchange
12,900
$ 307,468
15,942 $ 405,183
The holders of the Corporation’s exchangeable shares shall be entitled to notice of, to attend at, and to that number of
votes equal to the number of exchangeable shares held multiplied by the exchange ratio in effect at the meeting record
date at any meeting of the shareholders of Bonavista. In accordance with the provisions of the Corporation’s
exchangeable shares, Bonavista may require, at any time, the exchange of that number of the Corporation’s
exchangeable shares as determined by the Board of Directors on the basis of the exchange ratio in effect on the date set
by Bonavista (the “Compulsory Exchange Date”). On and after the applicable Compulsory Exchange Date, the holders
46
of the Corporation’s exchangeable shares called for exchange shall cease to be holders of such Corporation’s
exchangeable shares and shall not be entitled to exercise any of the rights of holders in respect thereof, other than;
(i) the right to receive their proportionate part of the common shares; and (ii) the right to receive any declared and unpaid
dividends on such common shares.
b) Share-based compensation:
Bonavista has option and incentive award programs (“long-term incentive plans”) that entitle officers, directors,
employees and certain consultants to purchase and receive shares in the Corporation. The number of common shares
awarded under all long-term incentive plans shall be limited to 8% of the aggregate number of issued and outstanding
equivalent shares of the Corporation.
i)
Stock option and common share incentive rights plans:
Upon conversion to a corporation, the stock option plan of the Corporation was established and the common share
rights incentive plan (formerly the trust unit rights incentive plan of the Trust) was amended. The amended plan
provided that all rights to acquire trust units became rights to acquire common shares. All new rights granted after
December 31, 2010 are granted under the stock option plan.
Directors, officers, employees and certain consultants of Bonavista are eligible to receive options under the stock
option plan. Grants made under the stock option plan vest evenly over a three year period and expire three years
after each vesting date, whereas grants made under the amended common share rights incentive plan vest over a
four year period and expire two years after each vesting date.
Bonavista estimates the fair value of share options granted using a Black-Scholes option pricing model. The
following average assumptions were used to arrive at the estimated fair value during each respective period:
Weighted average for the period
Dividend yield
Volatility
Risk-free interest rate
Forfeiture rate (1)
Expected life
December 31,
2013
December 31,
2012
6.57%
38.97%
1.64%
8.78%
5.0
7.90%
39.82%
1.28%
8.14%
5.0
(1)
The estimated forfeiture rate is adjusted for actual forfeitures throughout the vesting period.
The following table summarizes the stock option and common share incentive rights outstanding and exercisable
under the plans at December 31:
Balance as at December 31, 2011
Granted
Exercised
Expired and forfeited
Reduction in exercise price
Balance as at December 31, 2012
Granted
Exercised
Expired and forfeited
Reduction in exercise price
Balance as at December 31, 2013
Exercisable as at December 31, 2013
Number of Stock
Options/Common
Share Incentive
Rights
5,295,478
2,762,385
(371,678)
(1,280,949)
-
6,405,236
1,282,823
(211,140)
(678,441)
-
6,798,478
3,125,778
Weighted
Average
Exercise
Price
$
22.65
18.62
(12.13)
(23.45)
(0.66)
$
20.75
13.84
(9.38)
(21.17)
(0.26)
19.52
21.00
$
$
As at December 31, 2013 there are 5.5 million stock options outstanding (2012 - 4.4 million) of which 2.1 million are
exercisable (2012 - 654,376) and 1.3 million common share incentive rights outstanding (2012 - 2.0 million) with
1.1 million exercisable (2012 - 1.2 million).
47
The range of exercise prices of the outstanding stock option and common share incentive rights plans is as follows:
Stock Options/Common Share Incentive
Rights Outstanding
Weighted
average
remaining
contractual
life (years)
Weighted
average
exercise
price
Number
outstanding
Range of
exercise
prices
$ 8.54 – 15.53
15.54 – 25.80
25.81 – 30.73
2,888,780
2,130,808
1,778,890
$ 8.54 – 30.73
6,798,478
3.5
2.4
2.3
2.8
$
13.83
20.46
27.62
$
19.52
ii)
Incentive award and restricted share award incentive plans:
Stock Options/Common Share
Incentive
Rights Exercisable
Number
exercisable
Weighted
average
exercise
price
803,356
1,293,675
1,028,747
$
12.48
20.76
27.94
3,125,778
$
21.00
Bonavista’s incentive award and restricted share award incentive plans provide compensation in relation to a
notional number of underlying common shares to directors, officers, employees and certain consultants. Awards
granted between December 31, 2010 and May 2, 2013 were granted under the restricted share award incentive
plan. On May 2, 2013 the restricted share award incentive plan was replaced by the incentive award plan.
Vesting arrangements are within the discretion of Bonavista’s Board of Directors, but all awards vest evenly over a
period of three years from the date of grant. On the vesting date, the holder will receive, in the case of incentive
awards, cash or equivalent common shares for each incentive award and equivalent common shares for each
restricted share award, including dividends made on the common shares from the date of the grant to and including
the vesting date, net of the statutory withholding tax.
The fair value of incentive and restricted share awards is assessed on the grant date factoring in the weighted
average trading price of the five days preceding the grant date and forecasted dividends. This fair value is
recognized as share-based compensation expense over the vesting period with a corresponding increase to
contributed surplus. Upon the conversion of the restricted share awards or the settlement of the incentive awards by
common shares, on the predetermined vesting dates, the value in contributed surplus pertaining to the awards is
recorded as shareholders’ capital.
The following table summarizes the incentive award and restricted share award incentive plans outstanding at
December 31:
Balance as at December 31, 2011
Granted
Exercised
Forfeited
Balance as at December 31, 2012
Granted
Exercised
Forfeited
Balance as at December 31, 2013
487,484
1,480,706
(178,432)
(151,538)
1,638,220
1,600,582
(646,544)
(135,173)
2,457,085
As at December 31, 2013, there were 2.5 million incentive and restricted share awards (2012 - 1.6 million)
outstanding.
As at December 31, 2013, the balance of contributed surplus attributable to the share-based compensation awards
was $61.2 million (2012 - $44.8 million). Share-based compensation expense recognized in the year ended
December 31, 2013 was $23.9 million (2012 - $19.5 million). For the year ended December 31, 2013, $2.6 million of
share-based compensation expense was capitalized to property, plant and equipment (2012 - $2.9 million).
48
c) Per share amounts:
The following table summarizes the weighted average common shares and exchangeable shares used in calculating net
income per equivalent share:
(thousands)
Common shares
Exchangeable shares converted at the
exchange ratio
Basic equivalent shares
Stock option and common share incentive
rights
Restricted share awards and restricted
common share rights
Year ended
December 31, 2013
Year ended
December 31, 2012
181,685
15,611
197,296
125
1,919
154,551
21,030
175,581
223
943
Diluted equivalent shares
199,340
176,747
12. Long-term debt:
(thousands)
Bank credit facility
Senior unsecured notes
Balance, end of year
a) Bank credit facility:
December 31, 2013
December 31, 2012
$ 229,323
816,854
$ 1,046,177
$ 344,195
544,876
$ 889,071
Bonavista has a $600 million, covenant-based bank credit facility provided by a syndicate of 11 domestic and
international banks. The current maturity date of the credit facility is September 10, 2016. Bonavista also has in place a
$50 million demand working capital facility, which is subject to the same covenants as the credit facility.
The credit facility provides that advances may be made by way of prime rate loans, bankers' acceptances and/or US
dollar LIBOR advances. These advances bear interest at the banks' prime rate and/or at money market rates plus a
stamping fee. The credit facility is a four year revolving credit and may, at the request of Corporation with the consent of
the lenders, be extended on an annual basis beyond the existing term. There is an accordion feature providing that at
any time during the term, on participation of any existing or additional lenders, the Corporation can increase the facility by
$250 million.
Under the terms of the bank credit facility, Bonavista has provided the covenant that its: (i) consolidated senior debt
borrowing will not exceed three times net income before unrealized gains and losses on financial instrument contracts
and marketable securities, interest, taxes and depreciation, depletion, amortization and impairment; (ii) consolidated total
debt will not exceed three and one half times of consolidated net income before unrealized gains and losses on financial
instrument contracts and marketable securities, interest, taxes and depreciation, depletion, amortization and impairment;
and (iii) consolidated senior debt borrowing will not exceed one-half of consolidated total debt plus consolidated
shareholder’s equity of the Corporation, in all cases calculated based on a rolling prior four quarters.
b) Senior unsecured notes issued under a master shelf agreement:
The Corporation entered into an uncommitted master shelf agreement that allows for an aggregate draw of up to US$125
million in notes at a rate equal to the related US treasury rate corresponding to the term of the notes plus an appropriate
credit risk adjustment at the time of issuance. In 2010, the Corporation drew down US$50 million on the master shelf
agreement with a coupon rate of 4.86% with US$25 million maturing on June 4, 2016 and the remaining US$25 million
maturing on June 4, 2017.
In the second quarter of 2013, Bonavista agreed to increase its existing master shelf agreement from US$125 million to
US$150 million allowing the Corporation to draw an additional US$100 million in notes at a rate equal to the related US
treasury rate corresponding to the term of the notes plus an appropriate credit risk adjustment at the time of issuance.
On April 25, 2013, the Corporation drew down US$100 million on the master shelf agreement with a coupon rate of
3.80% and a maturity date of April 25, 2025. Under the terms of the master shelf agreement, Bonavista has provided
similar significant covenants that exist under the bank credit facility.
49
c) Senior unsecured notes not subject to the master shelf agreement:
On November 2, 2010, October 25, 2011 and May 23, 2013 Bonavista issued the following senior unsecured notes by
way of a private placement. Under the terms of the senior unsecured notes, Bonavista has provided similar significant
covenants that exist under the bank credit facility.
The terms and coupon rates of the notes are summarized below:
Issued Date
November 2, 2010
November 2, 2010
November 2, 2010
November 2, 2010
October 25, 2011
May 23, 2013
May 23, 2013
May 23, 2013
Principal
CDN $50.0 million
US $90.0 million
US $160.0 million
US $50.0 million
US $150.0 million
US $85.0 million
CDN $20.0 million
US $20.0 million
Coupon Rate
3.79%
3.66%
4.37%
4.47%
4.25%
3.68%
4.09%
3.78%
Maturity Dates
November 2, 2015
November 2, 2017
November 2, 2020
November 2, 2022
October 25, 2021
May 23, 2023
May 23, 2023
May 23, 2025
As at December 31, 2013, Bonavista was in compliance with all the covenants under its credit facilities and senior unsecured
notes. The weighted average interest rate under the bank credit facility was 3.1% for the year ended December 31, 2013
(2012 - 3.1%). The average interest rate on Bonavista’s outstanding long-term notes as at December 31, 2013 was 4.1%
(2012 – 4.2%).
13. Decommissioning liabilities:
Bonavista’s decommissioning liabilities results from net ownership interests in oil and natural gas assets including well sites,
gathering systems and processing facilities. Bonavista estimates the net present value of its total decommissioning liabilities
to be $406.5 million as at December 31, 2013 (2012 - $447.8 million), based on an estimated total future undiscounted liability
of approximately $1.4 billion (2012 - $899.4 million). At December 31, 2013 management estimates expenditures required to
settle the liability will be made over the next 55 years with the majority of payments being made in years 2048 to 2064. A risk-
free rate of approximately 3.2% (2012 - 2.4%) based on the Bank of Canada’s long-term risk-free bond rate and an inflation
rate of 2% (2012 - 2%) were used to calculate the present value of the decommissioning liability. The impact of the change in
the risk free rate is reflected in the table below in the category change in estimate.
A reconciliation of the decommissioning liabilities is provided below:
(thousands)
Balance, beginning of year
Accretion expense
Liabilities incurred
Liabilities acquired
Liabilities disposed
Liabilities settled
Change in estimate (1)
Balance, end of year
$
Current portion of decommissioning liabilities
Long-term decommissioning liabilities
(1)
Relates to changes in estimates, discount rates and anticipated settlement of decommissioning liabilities.
Year ended
December 31, 2013
Year ended
December 31, 2012
$
447,753
$
444,132
10,566
6,394
13,423
(14,899)
(30,143)
(26,607)
406,487
9,313
397,174
9,895
5,173
15,805
(35,635)
(25,530)
33,913
$
447,753
-
447,753
50
14. Deferred income taxes:
The provision for income tax differs from the result which would have been obtained by applying the combined Federal and
Provincial income tax rates to net income before taxes. The difference results from the following items:
(thousands)
Income before taxes
Current statutory income tax rate
Income tax expense at current statutory rate
Non-taxable portion of capital gain
Change in unrealized tax benefits
Non-deductible portion of unrealized foreign exchange
Non-deductible share-based compensation
Effect of tax rate changes and rate variance
Other
Year ended
December 31, 2013
Year ended
December 31, 2012
$
73,548
$
90,494
25.1%
18,461
(2,436)
(2,436)
4,845
5,370
264
(25)
25.1%
22,714
-
-
(1,470)
4,873
(64)
239
Deferred income taxes
$
24,043
$
26,292
The tax rate consists of the combined federal and provincial statutory tax rates for Bonavista for the years ended
December 31, 2013 and December 31, 2012. The general combined federal and provincial tax rate increased slightly in 2013
due to the BC provincial rate increasing from 10 percent in 2012 to 11 percent effective April 1, 2013.
December 31, 2013
December 31, 2012
(thousands)
Deferred income tax liabilities:
Capital assets in excess of tax value
$
463,502
$
Partnership deferral
Foreign exchange on long-term debt
Debt issue costs
Deferred income tax assets:
Decommissioning liabilities
Non-capital losses
Other liability
Issue costs
Financial instrument contracts
Marketable securities
Share-based compensation
-
(2,151)
1,455
(101,988)
(105,993)
(3,786)
(4,465)
(8,764)
-
(616)
348,848
92,306
2,694
1,656
(112,207)
(107,704)
(4,046)
(8,153)
(126)
(92)
-
Deferred income tax liability
$
237,194
$
213,176
The December 31, 2012 comparative deferred income tax liability presented above includes a deferred income tax liability for
the deferral of partnership income. During the year ended December 31, 2013, Bonavista wound up its partnership
eliminating any deferral of partnership income.
51
A continuity of the net deferred income tax liability is detailed in the following tables:
Balance
December 31,
2012
(Asset)/
Liability
Recognized
in profit and
loss
(Asset)/
Liability
Recognized
in equity
(Asset)/
Liability
Acquired in
business
combinations
(Asset)/
Liability
Balance
December 31,
2013
(Asset)/
Liability
(thousands)
Property, plant and equipment
$
348,848
$ 113,960
$
Decommissioning liabilities
Non-capital losses
Partnership deferral
Issue costs
Other liability
Foreign exchange
Debt issue costs
Financial instrument contracts
Marketable securities
Share-based compensation
(112,207)
(107,704)
92,306
(8,153)
(4,046)
2,694
1,656
(126)
(92)
-
10,913
1,711
(92,306)
3,713
260
(4,845)
(201)
(8,638)
92
(616)
-
-
-
-
(25)
-
-
-
-
-
-
$
213,176
$ 24,043
$ (25)
$
$
694
$
463,502
(694)
-
-
-
-
-
-
-
-
-
-
(101,988)
(105,993)
-
(4,465)
(3,786)
(2,151)
1,455
(8,764)
-
(616)
$
237,194
Balance
December 31,
2011
(Asset)/
Liability
Recognized
in profit
and loss
(Asset)/
Liability
Recognized
in equity
(Asset)/
Liability
Acquired in
business
combinations
(Asset)/
Liability
Balance
December 31,
2012
(Asset)/
Liability
(thousands)
Property, plant and equipment
$
271,029
$
68,980
$
Decommissioning liabilities
Non-capital losses
Partnership deferral
Issue costs
Other liability
Foreign exchange
Debt issue costs
Financial instrument contracts
Marketable securities
Share-based compensation
(111,300)
(99,720)
137,069
(5,865)
-
772
32
(1,732)
-
(616)
2,956
(7,984)
(44,763)
1,260
167
1,922
1,624
1,606
(92)
616
-
-
-
-
(3,548)
-
-
-
-
-
$
8,839
$
348,848
(3,863)
-
-
-
(4,213)
-
-
-
-
-
(112,207)
(107,704)
92,306
(8,153)
(4,046)
2,694
1,656
(126)
(92)
-
$
189,669
$
26,292
$
(3,548) $
763
$
213,176
52
The following is a summary of the estimated tax pools:
(thousands)
Canadian oil and gas property expense
$
937,202
$
1,032,539
December 31, 2013
December 31, 2012
Canadian development expense
Canadian exploration expense
Undepreciated capital cost
Non-capital losses
Other
Total
723,968
149,719
431,025
391,788
17,796
645,918
73,223
428,513
391,041
32,535
$
2,651,498
$
2,603,769
Non-capital losses carry forward of $391.8 million (2012 - $391.0 million) expire in the years 2025 through 2033. Bonavista
has capital losses of $48.7 million (2012 - $67.8 million) available for carry forward against future capital gains indefinitely that
is not included in the deferred income tax asset. For the years ended December 31, 2013 and 2012 Bonavista paid no tax
installments.
15. Commitments:
The following table details Bonavista’s contractual obligations for long-term debt, lease obligations, and other purchase
commitments as at December 31, 2013:
(thousands)
Long-term debt repayments (1)(3)
Interest payments (2)(3)
Office lease (4)
Drilling service contracts (5)
Transportation expenses
Total
2014
2015
2016
2017
2018 and
thereafter
Payments Due by Year
$ 1,046,177
243,180
41,192
70,700
44,111
$
-
33,568
5,929
35,266
17,229
$ 50,000
33,257
6,068
29,527
11,511
$ 255,913
31,027
6,068
5,907
7,298
$ 122,314
29,160
6,068
-
4,070
$ 617,950
116,168
17,059
-
4,003
Total contractual obligations
$ 1,445,360
$ 91,992
$ 130,363
$ 306,213
$ 161,612
$ 755,180
(1)
Long-term debt repayments include the bank loan facility and principal payments due on senior unsecured notes. Based on the existing terms of the revolving bank credit facility, the
amounts owing under this facility are required to be paid in 2016.
Fixed interest payments on senior unsecured notes.
US dollars payments are converted using the exchange rate of $1.0636 CDN/US dollar.
(2)
(3)
(4) Office lease expires July 31, 2020.
(5)
The drilling service contracts are with two service providers extending over a three year term.
16. Supplemental disclosure:
a)
Income Statement Presentation:
Bonavista's statement of income is prepared primarily by nature of expense, with the exception of employee
compensation costs which are included in both the operating and general and administrative expense line items. The
following table details the amount of total employee compensation costs included in the operating and general and
administrative expense line items in the consolidated statements of income and comprehensive income.
(thousands)
Operating
General and administrative
Total employee compensation costs
Year ended
Year ended
December 31, 2013
December 31, 2012
$
$
7,337
31,125
$
38,462
$
6,409
26,684
33,093
53
b) Compensation of key management personnel:
Bonavista has determined that its key management personnel includes both officers and directors. Short-term benefits
are comprised of salaries and directors fees, annual bonuses and other benefits. In addition, share-based compensation
provided to key management personnel includes awards offered under Bonavista’s long-term incentive plans. The
following table details remuneration to key management personnel included in general and administrative expenses on
the consolidated statements of income and comprehensive income.
(thousands)
Short-term benefits
Share-based payments
Year ended
Year ended
December 31, 2013
December 31, 2012
$
$
3,513
4,133
7,646
$
$
2,823
6,523
9,346
54
CORPORATE INFORMATION
DIRECTORS
Keith A. MacPhail, (2)(5)
Executive Chairman
Jason E. Skehar, (5)
President and CEO
Ian S. Brown (1)(4)
Michael M. Kanovsky (1)(2)(4)(5)
Sue Lee (3)(4)
Margaret A. McKenzie (1)(3)
Ronald J. Poelzer (5)
Christopher P. Slubicki (2)(3)
Walter C. Yeates
(1) Member of the Audit Committee
(2) Member of the Reserves Committee
(3) Member of the Compensation Committee
(4) Member of the Governance and Nominating Committee
(5) Member of the Executive Committee
OFFICERS
Keith A. MacPhail,
Executive Chairman
Jason E. Skehar,
President and CEO
Glenn A. Hamilton,
Senior Vice President and CFO
Scott H. Hanson,
Vice President, Production
Bruce W. Jensen,
Vice President, Engineering
Dean M. Kobelka,
Vice President, Finance
Magni Lake,
Vice President, Marketing
Wayne E. Merkel,
Vice President, Exploration
Lynda J. Robinson,
Vice President, Human Resources and Administration
Hank R. Spence,
Vice President, Operations
Cory J. Stewart,
Vice President, Land
Grant A. Zawalsky,
Corporate Secretary
FOR FURTHER INFORMATION CONTACT:
Keith A. MacPhail
Executive Chairman
or
Jason E. Skehar
President and CEO
AUDITORS
KPMG LLP
Chartered Accountants
Calgary, Alberta
BANKERS
Canadian Imperial Bank of Commerce
The Toronto-Dominion Bank
Bank of Montreal
Royal Bank of Canada
The Bank of Nova Scotia
National Bank of Canada
Alberta Treasury Branches
Citibank, N.A. (Canadian Branch)
HSBC Bank Canada
Sumitomo Mitsui Banking Corporation of Canada
Union Bank of California, N.A. (Canada Branch)
Calgary, Alberta
ENGINEERING CONSULTANTS
GLJ Petroleum Consultants Ltd.
Calgary, Alberta
LEGAL COUNSEL
Burnet, Duckworth & Palmer LLP
Calgary, Alberta
REGISTRAR AND TRANSFER AGENT
Valiant Trust Company
Calgary, Alberta
STOCK EXCHANGE LISTING
Toronto Stock Exchange
Trading Symbol “BNP”
HEAD OFFICE
1500, 525 – 8th Avenue SW
Calgary, Alberta T2P 1G1
Telephone: (403) 213-4300
(403) 262-5184
Facsimile:
investor.relations@bonavistaenergy.com
Email:
www.bonavistaenergy.com
Website:
or
Glenn A. Hamilton
Senior Vice President and CFO
55