ANNUAL REPORT
2010
Highlights
Financial
($ thousands, except per share/unit)
Production revenues
Funds from operations (1)
Per share (1) (2)
Distributions declared
Per unit
Percentage of funds from operations(1)
Net income
Per share (2)
Adjusted net income(3)
Per share (2)
Total assets
Long-term debt, net of working capital (4)
Long-term debt, net of adjusted working capital(3)(4)
Shareholders’ equity
Capital expenditures:
Exploration and development
Acquisitions, net
Three months
ended December 31,
2010
2009
%
Change
Years
ended December 31,
2009
2010
%
Change
234,706
232,870
1%
938,726
759,423
24%
127,258
0.81
64,242
0.48
135,534
0.93
59,783
0.48
50%
44%
39,784
0.25
55,222
0.35
39,647
0.27
56,588
0.39
(6%)
(13%)
7%
-
6%
-
(7%)
(2%)
(10%)
526,987
3.44
252,298
1.92
447,743
3.46
217,965
2.00
48%
49%
201,581
1.32
198,760
1.30
106,606
0.82
169,767
1.31
3,342,988
3,092,129
1,021,455
881,169
1,020,318
874,409
1,877,608
1,723,583
18%
(1%)
16%
(4%)
(1%)
89%
61%
17%
(1%)
8%
16%
17%
9%
94,394
(39,801)
62,044
13,172
52%
(402%)
349,481
220,514
203,845
629,999
71%
(65%)
Weighted average outstanding equivalent shares: (thousands)(2)
Basic
Diluted
156,380
157,670
146,019
148,035
7%
7%
153,094
154,832
129,263
131,233
18%
18%
Operating
(boe conversion – 6:1 basis)
Production:
Natural gas (mmcf/day)
Oil and liquids (bbls/day)
Total oil equivalent (boe/day)
Product prices:(5)
Natural gas ($/mcf)
Oil and liquids ($/bbl)
Operating expenses ($/boe)
General and administrative expenses ($/boe)
Cash costs ($/boe)(6)
Operating netback ($/boe)(7)
250
26,692
68,307
4.08
59.46
7.88
0.87
10.60
22.98
222
24,849
61,832
4.84
62.79
9.04
0.92
10.74
13%
7%
10%
(16%)
(5%)
(13%)
(5%)
(1%)
25.53
(10%)
240
26,182
66,259
4.50
58.56
8.05
0.86
10.12
23.85
191
23,484
55,299
4.78
58.18
9.80
0.89
26%
11%
20%
(6%)
1%
(18%)
(3%)
11.38
(11%)
23.77
-
Highlights (cont’d)
Drilling (gross wells):
Natural gas
Oil
Average success rate
Land:
Undeveloped (net acres)
Total (net acres)
Reserves: (8)
Proved:
Natural gas (bcf)
Oil and liquids (mbbls)
Total oil equivalent (mboe)
Proved and probable:
Natural gas (bcf)
Oil and 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
Reserve life index (years):
Proved
Proved and probable
Finding, development and acquisition costs – proved and probable ($/boe):
Including changes in future development expenditures
Excluding changes in future development expenditures
Recycle ratio – proved and probable: (9)
Including changes in future development expenditures
Excluding changes in future development expenditures
December 31,
2010
2009
%
Change
140
77
61
99%
114
57
55
98%
1,522,867
3,003,411
1,633,649
3,004,146
840.4
83,695
223,756
1,177.4
115,578
311,811
45%
72%
28%
9,947
6,283
4,537
9.1
12.0
13.35
8.99
1.8
2.7
732.2
71,722
193,750
1,039.2
99,419
272,617
46%
71%
29%
9,676
6,497
4,876
8.6
11.5
12.01
8.20
2.0
2.9
23%
35%
11%
1%
(7%)
-
15%
17%
15%
13%
16%
14%
(1%)
1%
(1%)
3%
(3%)
(7%)
6%
4%
11%
10%
(10%)
(7%)
Trust Unit Trading Statistics
($ per unit, except volume)
High
Low
Close
Average Daily Volume - Units
NOTES:
December 31,
2010
September 30,
2010
June 30,
2010
March 31,
2010
Three months ended
29.50
23.88
28.80
24.91
22.34
23.89
25.60
22.03
22.81
25.70
22.40
23.35
304,761
309,312
423,688
341,312
(1) Management uses funds from operations to analyze operating performance, distribution coverage and leverage. Funds from operations as presented do not have any standardized meaning
prescribed by Canadian GAAP 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 Canadian GAAP. All references to funds from operations throughout this report are based on cash flow from operating activities before changes in non-cash working capital and
asset retirement expenditures. 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 per share calculations include exchangeable shares which are convertible into common shares on certain terms and conditions. Previous historical references to “unitholders”, “distributions”,
“trust units” and “per unit” have now been replaced by “common shareholders”, “dividends”, “common shares”, and “per share” respectively, where applicable.
(3) Amounts have been adjusted to exclude unrealized gains and losses on financial instrument contracts, their related tax impact and associated assets or liabilities.
(4) Amounts exclude convertible debentures.
(5) Product prices include realized gains and losses on financial instrument contracts.
(6) Cash costs equal the total of operating, general and administrative, and financing expenses, calculated on a boe basis.
(7) Operating netback equals production revenues including realized gains and losses on financial instrument contracts, less royalties, transportation and operating expenses, calculated on a boe basis.
(8) Company interest reserves are gross reserves prior to deduction of royalties and includes any royalty interests of the Corporation.
(9) Recycle ratio is calculated using operating netback per boe divided by finding, development and acquisition costs per boe.
MESSAGE TO SHAREHOLDERS
Bonavista Energy Corporation (“Bonavista”) is pleased to report to shareholders its consolidated financial and operating
results for the year ended December 31, 2010. Bonavista has continued its pattern of generating profitable results since
commencing operations in 1997. Despite continued volatility in both commodity prices and capital markets throughout
2010, we remained focused on the consistent execution of Bonavista’s disciplined business strategies which has resulted
in excellent operational and financial results.
This past year marked the final year that Bonavista operated as an energy trust, concluding a four year undertaking
focused on ensuring that Bonavista is well positioned to provide our investors with an enhanced growth profile when it
converted to a dividend paying corporation.
As we persevered in adding incremental operational and capital efficiencies to our business through cost discipline, we
continued to assemble a robust inventory of growth opportunities through both organic development and strategic
acquisitions in 2010. Complementing our transformational Hoadley acquisition in our Western Core Region in 2009, we
closed another significant acquisition in the second quarter of 2010 of liquids rich, natural gas weighted assets
(the “Acquired Properties”) adding a high quality, opportunity rich extension to our Western Core Region within the Deep
Basin of Alberta. Bonavista closed this acquisition on May 31, 2010 for a cash purchase price of $230.4 million, which
was partially funded by our $177.0 million equity financing completed on April 15, 2010. The Acquired Properties have
provided Bonavista the opportunity to expand our application of leading technologies to access large, underdeveloped
reservoirs, similar to our efforts over the past two years in our Western Core Region.
On December 14, 2010 Bonavista announced the receipt of security and court approvals for its conversion to a
corporation. With securityholders voting 99.95% in favour of our plan of arrangement, the conversion became effective
on December 31, 2010 and the common shares of Bonavista began trading under the symbol “BNP” on the Toronto
Stock Exchange on January 7, 2011.
Prompted by our desire to strike a healthy balance between sustainable growth and yield, Bonavista established an initial
dividend rate of $0.12 per common share per month commencing January 2011. This new dividend level, although
reduced by 25% from prior trust distribution levels, represents a meaningful dividend yield of approximately 5% based on
the current trading price of Bonavista’s common shares. As a result of the lower payout ratio, the incremental cash flow
available for reinvestment is now being allocated to our low risk, high-impact resource development programs that offer
solid rates of return. Furthermore, these programs exhibit attractive capital efficiencies which we expect will provide
annual production growth of 5% to 7% over a sustained period of time. With our proven underlying operating strategies
remaining intact through our corporate conversion, our business model has been designed to deliver long-term total
shareholder returns of between 10 and 15% per annum.
Specific accomplishments for Bonavista in 2010 include:
Increased production volumes to a record level of 66,259 boe per day. This represents a 20% increase over our
production levels in 2009. We are currently producing 67,800 boe per day after accounting for recent asset
dispositions of approximately 1,000 boe per day;
Increased proved and probable reserves by 14% to 311.8 mmboe;
Added 63.4 mmboe of proved and probable reserves, which replaced 2010 annual production by 262%;
Improved our proved and probable reserve life index to 12.0 years from 11.5 years in 2009 and increased our proved
reserve life index to 9.1 years from 8.6 years in 2009;
Achieved attractive finding, development and acquisition costs, including changes in future development
expenditures, of $14.48 per boe on a proved basis ($10.52 per boe excluding changes in future development
expenditures) and $13.35 per boe on a proved and probable basis ($8.99 per boe excluding changes in future
development expenditures). Increased proved and probable future development capital by 39% to $986 million
representing the significant development and growth potential yet to be realized on our asset base;
Attained a 2010 proved and probable operating netback recycle ratio of 1.8:1 as a result of this level of finding,
development and acquisition costs, including future development capital (2.7:1 recycle ratio excluding future
development costs);
Executed an effective capital program in 2010 investing $349.5 million in exploration and development activities
drilling 140 wells with an overall 99% success rate. We invested an additional $220.5 million on 18 synergistic A&D
property transactions within our core regions which includes the previously mentioned $230.4 million Deep Basin
Acquisition and is net of $65.6 million in non-core asset dispositions;
Drilled 97 successful horizontal wells which include unconventional resource development in the Glauconite,
Cardium, Montney, Viking, Bluesky and Rock Creek horizons. The key highlights of our horizontal drilling program
are as follows:
Hoadley Glauconite
Drilled 35 operated horizontal wells and participated in seven non-operated horizontal wells on the highly
prospective Hoadley Glauconite trend in our Western Core Region. Our Hoadley Glauconite liquids rich natural
gas development program remains the cornerstone of growth for our company and continues to impress with a
predictable production profile and attractive economics even in today’s compressed natural gas price
environment. Bonavista has now participated in the drilling of 66 horizontal Glauconite wells since 2008 and the
results of the producing wells to date continue to meet our expectations. Despite our robust drilling activity, we
have consistently grown our inventory of future opportunities through land consolidation activities and
successful step out development.
Bonavista believes that our Glauconite horizontal development program is one of the most profitable liquids rich
natural gas resource developments in North America with economics that outperform many oil projects being
developed today. Single well economics are exceptionally attractive and provide abundant capital spending
flexibility with half cycle breakeven economics of approximately $2.00 per mcf.
Cardium Light Oil
Drilled 13 horizontal wells and participated in 8 additional non-operated horizontal wells on the emerging
unconventional Cardium light oil play in our Western Core Region. With 29 horizontal Cardium wells drilled to
date, we’ve experienced a meaningful improvement in production rates resulting from a greater understanding
of the geological model, successful refinement of our completion techniques and a robust level of industry
activity within all areas of the known Cardium trends. With the majority of our 300 section land base currently
being held by production, we have the comfort to prudently advance our development program and focus on
gaining continued improvement in average well results. We anticipate the potential to accelerate development
of our currently identified drilling inventory of 120 locations if we continue to see positive improvements in
production results in 2011.
Deep Basin Liquids Rich Natural Gas
Drilled four horizontal wells on lands we acquired through the Deep Basin acquisition which closed in May 2010.
With three Bluesky and six Rock Creek horizontal wells drilled to date, initial test results are positive and we will
continue to allocate capital to these plays in 2011. At Pine Creek, our initial Bluesky well drilled on the
acquisition lands was brought on production in the fourth quarter at 620 boe per day and is currently at 560 boe
per day after four months of production and is supported by an attractive liquids yield of 40 bbls per mmcf.
Similarly, our first two Rock Creek wells drilled at Rosevear have recently been brought on-stream with a first
month production average of 500 boe per day which includes natural gas liquids of 25 bbls per mmcf.
In addition to the development of the Acquired Properties, we continue to pursue multiple liquids rich natural gas
plays on heritage lands throughout the deep basin. Including both acquisition and heritage lands, we currently
have identified 180 horizontal drilling locations, which offer attractive capital efficiencies targeting the Bluesky,
Rock Creek, Notikewin, Pekisko, Mannville and Wilrich horizons.
Blueberry Montney
Assembled a contiguous land position of 55 net sections in the Blueberry area of North East British Columbia
which is prospective for unconventional resource development in both the upper and lower Montney horizons.
2010 marked the commencement of our delineation program with one vertical well and two horizontal wells
drilled into the upper Montney formation. Initial testing has produced a high heat content natural gas stream
plus a significant quantity of free condensate totaling a combined liquids yield of approximately 80 to 150 bbls
per mmcf. While the high liquids yield can drive attractive netbacks at current commodity prices, the elevated
quantities tested to date have prompted us to pursue detailed core and reservoir simulation work prior to
proceeding with a scalable development program at this point.
Participated at Crown land sales in 2010 purchasing approximately 119,000 net acres of undeveloped land spending
$63.8 million. This represents a record participation level at Crown land sales for Bonavista and will enhance our
ability to generate profitable drilling opportunities for many years to come;
Continued to achieve significant improvements in our cost structure with operating costs on a per boe basis
decreasing 18% for the year ended December 31, 2010 to $8.05 per boe from $9.80 per boe in the comparable
period of 2009. These improvements stem from continued cost discipline in all operating areas and continued
development drilling in areas where we own and operate infrastructure with ample processing capacity;
Generated funds from operations of $527.0 million ($3.44 per share) for the year ended December 31, 2010.
Bonavista distributed 48% of these funds to shareholders with the remaining funds reinvested in the business to
continue growing our production base;
Completed the renewal of Bonavista’s $1.4 billion bank credit facility for an additional three year term to
September 10, 2013. On March 3, 2011, Bonavista elected to reduce the committed amount of its bank credit facility
by $400 million from $1.4 billion to $1.0 billion as a result of debt capacity created from Bonavista’s issuance of
senior unsecured notes and the desire to reduce the cost of carrying the larger undrawn facility. Additionally, on
November 2, 2010, Bonavista completed the issuance of approximately $350 million of senior unsecured notes by
way of a private placement for a total of $400 million issued during 2010. The notes issued in November have a
blended rate of 4.1% and a weighted average term of approximately 8.8 years;
Continued to achieve profitability with a return on equity of 11% and an adjusted net income to funds from operations
ratio of 38% for the year ended December 31, 2010. The above ratios reflect net income adjusted to negate the after
tax impact of the unrealized gains and losses on financial instrument contracts; and
Since inception as a trust, and continuing in our new legal structure as a dividend paying corporation, Bonavista has
delivered over $2.0 billion or $23.27 per common share of cumulative dividends.
Strengths of Bonavista Energy Corporation
Beginning in 1997 with an initial restructuring to create a high growth junior exploration company, throughout the income
trust phase between 2003 and 2010, and now operating as a dividend paying corporation, Bonavista remains committed
to the same strategies that have resulted in our tremendous success over the last thirteen years. We have maintained a
high level of investment activity on our asset base, increasing current production by approximately 95% since converting
to an energy trust in 2003. This activity stems from the operational and technical focus of our people, their attention to
detail, and their entrepreneurial approach to generating low risk, highly profitable projects within the Western Canadian
Sedimentary Basin. Our experienced technical teams have a solid understanding of our assets and they continue to
exercise the discipline and commitment required to deliver long-term value to our shareholders. We actively participate
in undeveloped land acquisitions through Crown land sales, property purchases and farm-in opportunities, which have all
enhanced the quality and quantity of our extensive drilling inventory. These activities have led to low cost reserve
additions, lengthening of our reserve life index, and a production base that continues to grow at a healthy pace. Our
production base is currently weighted 61% towards natural gas and is geographically focused within select, multi-zone
regions primarily in Alberta and British Columbia. The low cost structure of our asset base maintains attractive operating
netbacks in most operating environments. In addition, our asset base is predominantly operated by Bonavista, providing
control over the pace of operations and ensuring that operating and capital cost efficiencies are consistently optimized.
Our team brings a successful track record of executing low to medium risk development programs, including both asset
and corporate acquisitions, along with a solid track record of 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 15% of the equity of
Bonavista, resulting in the alignment of interests with all shareholders.
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, 2010. The following MD&A of the financial condition and results of
operations was prepared at, and is dated March 3, 2011. Our audited consolidated financial statements, Annual Report,
and other disclosure documents for 2010 will be available on or before March 31, 2011 through our filings on SEDAR at
www.sedar.com or can be obtained from Bonavista’s website at www.bonavistaenergy.com
Basis of Presentation - The financial data presented below has been prepared in accordance with Canadian Generally Accepted
Accounting Principles (“GAAP”). The reporting and the measurement currency is the Canadian dollar. 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; (ii) exploration,
drilling and development plans; (iii) prospects and inventory; (iv) anticipated production rates; (v) expected royalty rate; (vi)
anticipated operating and service costs; (vii) our financial strength; (viii) incremental development opportunities; (ix) anticipated
natural gas supply and demand; (x) reserve life index; (xi) utilization of technology; and (xii) rate of return and dividend yield, which
are provided to allow investors to better understand our 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. Investors are also cautioned that dividend yield represents a blend of return of an investor’s initial
investment and a return on investors' initial investment and is not comparable to traditional yield on debt instruments where
investors are entitled to full return of the principal amount of debt on maturity in addition to a return on investment through interest
payments.
Non-GAAP 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
Canadian GAAP 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 Canadian GAAP. All references to funds from operations throughout this report are based on cash flow from
operating activities before changes in non-cash working capital and abandonment expenditures. Funds from operations per share is
calculated based on the weighted average number of common shares outstanding consistent with the calculation of net income per
share. Operating netbacks equal production revenue and realized gains and losses on financial instrument contracts, less royalties,
transportation and operating expenses calculated on a boe basis. Total boe is calculated by multiplying the daily production by the
number of days in the period.
Corporate conversion - On December 31, 2010, Bonavista Energy Trust (the “Trust”) completed its conversion from an
energy trust to a dividend paying corporation pursuant to a plan of arrangement (the “Arrangement”) under Section 193
of the Business Corporations Act (Alberta). The conversion involved the internal reorganization of the Trust and certain
subsidiaries through which the trust structure was replaced with the corporate structure of the Corporation. Bonavista
owns, directly or indirectly, the same assets that were owned by the Trust immediately prior to the effective date of the
conversion and assumed all of the obligations of the Trust. In addition, the directors and officers remain unchanged.
Pursuant to the Arrangement, unitholders received one common share of Bonavista for each trust unit held and
exchangeable shareholders of Bonavista Petroleum Ltd. received 2.40917 exchangeable shares of Bonavista for each
exchangeable share held. In conjunction with the Arrangement, a stock option plan and restricted share award incentive
plan were established and the common share rights incentive plan (formerly the trust unit rights incentive plan of the
Trust) and the restricted common share incentive plan (formerly the restricted trust unit incentive plan of the Trust) were
amended. These plans are further outlined in note 9 of the notes to the consolidated financial statements of Bonavista.
The common shares of Bonavista began trading on the Toronto Stock Exchange on January 7, 2011 under the trading
symbol BNP. Beginning with the January 31, 2011 record date, shareholders of the Corporation will receive payments in
the form of dividends. Prior to the conversion of the Trust to Bonavista on December 31, 2010, distributions were paid to
unitholders. Previous historical references to “unitholders”, “distributions”, “trust units” and “per unit” have now been
replaced by “common shareholders”, “dividends”, “common shares”, and “per share”, respectively, where applicable.
Bonavista will continue with the business activities and business strategies of the Trust. The business plan of Bonavista
is to create sustainable and profitable per share growth in reserves, production and cash flow while delivering a
consistent dividend to our shareholders. To accomplish this, Bonavista will pursue an integrated growth strategy with
active development and exploration drilling within its core areas, together with focused acquisitions, similar to the
strategies previously pursued by the Trust.
Operations - Bonavista's exploration and development program for year ended December 31, 2010 led to the drilling of
140 wells in our three core regions with an overall success rate of 99%. This program resulted in 77 natural gas wells
and 61 oil wells. A strong recycle ratio driving a high level of profitability continues to guide our exploration and
development program which remains flexible to changes in commodity price, development risk and deliverability upside.
Once again, our operations for the year have resulted in superior capital efficiencies driven off of strong production
performance, healthy reserve additions and a disciplined approach to spending with every well drilled. These activities
continue to enhance the predictability in our overall production base, in addition, to lengthening our reserve life index
("RLI") to approximately 12.0 years on a proved plus probable basis.
Reserves - Reserve estimates have been calculated in compliance with the National Instrument 51-101 Standards of
Disclosure (“NI 51-101”). Under NI 51-101, proved reserves are defined as reserves that can be estimated with a high
degree of certainty to be recoverable with a target of a 90% probability that the actual reserves recovered over time will
equal or exceed proved reserve estimates, while probable reserves are defined as having an equal (50%) probability that
the actual reserves recovered will equal or exceed the proved and probable reserve estimates. In accordance with
NI 51-101, proved undeveloped reserves have been recognized in cases where plans are in place to bring the reserves
on production within a short, well defined time frame. Proved undeveloped reserves often involve infill drilling into
existing pools. Of the net present value of the Corporation's reserves, 84% were evaluated by independent third party
engineers, GLJ Petroleum Consultants Ltd. ("GLJ") and Ryder Scott Company Canada (“Ryder Scott”) in their reports
dated February 25, 2011 and February 11, 2011, respectively. The balance of approximately 16% of proved and
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, 2010:
Natural Gas
(MMcf)
Reserves:(1)(4)
Proved:
Proved producing
Proved non-producing
Proved undeveloped
Total proved
Probable
Total proved and probable
Proved reserve life index, years(3)
Proved and probable reserve life index, years(3)
509,869
26,634
299,443
835,946
335,938
1,171,884
Light and
Medium Oil
(Mbbls)
Heavy Oil
(Mbbls)
Natural Gas
Liquids
(Mbbls)
Total
Reserves(2)
(Mboe)
25,729
592
6,284
32,605
9,734
42,340
5,062
1,133
502
6,698
2,591
9,289
24,403
1,000
18,891
44,294
19,513
63,806
140,172
7,165
75,585
222,921
87,828
310,749
9.1
12.0
(1)
(2)
(3)
(4)
Bonavista’s gross reserves before royalties, based on the GLJ and Ryder Scott reserve reports dated February 25, 2011 and February 11, 2011 respectively, GLJ and Ryder Scott reserve
estimates based on forecast prices and costs as of January 1, 2011.
Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6Mcf:1bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and
does not represent a value equivalency at the wellhead.
Calculated based on the amount for the relevant reserve category divided by the 2011 production forecast.
Amounts may not add due to rounding.
Reserve Reconciliation:
Balance, December 31, 2009
Extensions and improved recovery
Technical revisions
Acquisitions
Dispositions
Economic factors
Production
Balance, December 31, 2010
Proved
(Mboe)
193,187
24,124
11,462
21,008
(1,909)
(788)
(24,163)
222,921
Probable
(Mboe)
78,726
8,459
(5,447)
7,363
(907)
(366)
-
87,828
Proved
and
Probable
(Mboe)
271,913
32,583
6,015
28,371
(2,816)
(1,154)
(24,163)
310,749
Bonavista’s 2010 year-end proved reserves totalled 222.9 mmboe, a 15% increase compared to the 193.2 mmboe at the
year-end of 2009. Furthermore, Bonavista’s proved and probable reserves increased by 14% to 310.7 mmboe when
compared to the 271.9 mmboe at year-end 2009. The Corporation had proved and probable positive reserve revisions of
5.2 mmboe which were primarily related to improved performance at three properties in British Columbia and enhanced
liquid recoveries in our Hoadley Glauconite development.
Proved and Probable Finding, Development and Acquisition Costs:(1)
Total capital expenditures ($ millions)
Total capital expenditures plus change
2010
570.0
2009
833.8
2008
482.3
in forecast future development costs ($ millions)
846.3
1,221.8
594.4
Proved and probable reserves (Mboe):
Opening balance
Discoveries and extensions
Acquisitions and dispositions
Revisions and economic factors
Production
Closing balance
Proved and probable FD&A costs ($/boe)
Proved and probable three-year FD&A costs ($/boe) (2)
(2)
271,913
32,583
25,555
4,861
(24,163)
190,240
21,799
84,087
(4,061)
(20,152)
178,575
23,861
10,373
(3,410)
(19,159)
310,749
271,913
190,240
13.43
14.85
12.01
15.68
19.11
16.77
(1)
(2)
The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not
reflect total finding and development costs related to reserve additions for that year.
Amounts are calculated including the change in future development costs.
Finding, development and acquisition costs in 2010, including changes in future capital expenditures, amounted to
$14.56 per boe ($10.58 per boe before changes in future capital expenditures) on a proved basis and $13.43 per boe
($9.05 per boe before changes in future capital expenditures) on a proved and probable basis.
Capital Efficiency:
Operating netback ($/boe)
Total capital expenditures
(1)
(excluding future development costs)
Proved and probable FD&A costs ($/boe)
Recycle ratio (3)
(2)
Total capital expenditures
(including future development costs)
Proved and probable FD&A costs ($/boe)
Recycle ratio (3)
2010
23.85
9.05
2.6
13.43
1.8
2009
23.77
8.20
2.9
12.01
2.0
2008
35.49
15.50
2.3
19.11
1.9
Three-Year
Average
27.70
10.92
2.6
14.85
1.9
(1) Operating netback is calculated using production revenues including realized gains or losses on financial instruments contracts less royalties, transportation and operating costs calculated on
a per barrel of oil equivalent basis.
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 finding, development and acquisition costs on a per barrel of oil equivalent.
(2)
(3)
Bonavista generated an attractive recycle ratio of 1.8:1 for proved and probable reserves and 1.6:1 for proved reserves
which includes revisions and changes in future development expenditures; excluding changes in future development
expenditures, the proved and probable recycle ratio improved to 2.6:1 and the proved recycle ratio improved to 2.3:1.
Additional reserves disclosure tables, as required under NI 51-101, are contained in Bonavista’s Annual Information
Form that will be filed on SEDAR.
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/unit amounts where noted)
Three months
ended December 31,
2009
2010
Years
ended December 31,
2009
2010
Product prices:
Natural gas ($/mcf)
Oil and liquids ($/bbl)
Production:
Natural gas (mmcf/d)
Oil and liquids (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
Financing expenses
per boe
Unit-based compensation
per boe
Depreciation, depletion and accretion
per boe
Income taxes (recovery)
per boe
Net income
per boe
per share – basic
Distributions declared
per unit
Funds from operations
per boe
per share – basic
4.08
59.46
4.84
62.79
4.50
58.56
4.78
58.18
250
26,692
68,307
234,706
37.35
35,071
5.58
14.9%
49,494
7.88
10,677
1.70
5,441
0.87
10,956
1.74
3,045
0.48
91,552
14.56
(16,034)
(2.55)
39,784
6.33
0.25
64,242
0.48
127,258
20.25
0.81
222
24,849
61,832
232,870
40.94
36,347
6.39
15.6%
51,407
9.04
9,435
1.66
5,227
0.92
4,456
0.78
2,939
0.52
85,229
14.99
(15,825)
(2.78)
39,647
6.97
0.27
59,783
0.48
135,534
23.83
0.93
240
26,182
66,259
938,726
38.82
143,507
5.93
15.3%
194,755
8.05
39,652
1.64
20,897
0.86
28,272
1.17
11,584
0.48
354,593
14.66
(21,888)
(0.91)
201,581
8.34
1.32
252,298
1.92
526,987
21.79
3.44
191
23,484
55,299
759,423
37.62
117,217
5.81
15.4%
197,795
9.80
36,833
1.82
17,900
0.89
14,035
0.70
11,386
0.56
295,296
14.63
(52,627)
(2.61)
106,606
5.28
0.82
217,965
2.00
447,743
22.18
3.46
Production - For the year ended December 31, 2010, production increased 20% to a record level of 66,259 boe per day
when compared to 55,299 boe per day for the same period a year ago. Natural gas production increased 26% to
240 mmcf per day in 2010 from 191 mmcf per day for the same period a year ago, while total oil and liquids production
increased 11% to 26,182 bbls per day in 2010 from 23,484 bbls per day for the same period in 2009. For the fourth
quarter of 2010, production increased 10% to 68,307 boe per day when compared to 61,832 boe per day for the same
period a year ago. Natural gas production increased 13% to 250 mmcf per day in the fourth quarter of 2010 from
222 mmcf per day for the same period a year ago, while total oil and liquids production increased 7% to 26,692 bbls per
day in the fourth quarter of 2010 from 24,849 bbls per day for the same period in 2009.
The following table highlights Bonavista's production by product for the three months and years ended December 31:
Natural gas (mmcf/day)
Oil and liquids (bbls/day):
Light and medium oil
Heavy oil
Total oil and liquids (bbls/day)
Total oil equivalent (boe/day)
Three months
ended December 31,
2009
2010
Years
ended December 31,
2009
2010
250
222
240
191
22,342
4,350
26,692
68,307
19,864
4,985
24,849
61,832
21,395
4,787
26,182
66,259
18,037
5,447
23,484
55,299
Our current production is approximately 67,800 boe per day, consisting of 61% natural gas, 33% light and medium oil
and 6% heavy oil after accounting for approximately 1,000 boe per day of recent asset divestitures.
Production revenues - Production revenues for the year ended December 31, 2010 increased 24% to $938.7 million
when compared to $759.4 million for the same period a year ago, due mainly to a 20% increase in production volumes.
For the year ended December 31, 2010, natural gas prices decreased 6% to $4.50 per mcf, when compared to
$4.78 per mcf realized in the same period in 2009. The average oil and liquids price increased 1% to $58.56 per bbl for
the year ended December 31, 2010 from $58.18 per bbl for the same period in 2009. For the fourth quarter of 2010,
production revenues increased 1% to $234.7 million when compared to $232.9 million for the same period a year ago.
This increase was due in part to a 10% increase in production volumes offset by an 11% decrease in product pricing in
the fourth quarter of 2010 as compared to the same period in 2009. In the fourth quarter of 2010, natural gas prices
decreased 16% to $4.08 per mcf, when compared to $4.84 per mcf realized in the same period in 2009. The average oil
and liquids price decreased 5% to $59.46 per bbl for the fourth quarter 2010 from $62.79 per bbl for the same period in
2009.
The following table highlights Bonavista's realized product pricing for the three months and years ended December 31:
Natural gas ($/mcf):
Production revenues
Realized gain on financial instrument contracts
Light and medium oil ($/bbl):
Production revenues
Realized gain on financial instrument contracts
Heavy oil ($/bbl):
Production revenues
Realized gain on financial instrument contracts
Total ($/boe):
Production revenues
Realized gain on financial instrument contracts
Three months
ended December 31,
2009
2010
Years
ended December 31,
2009
2010
$ 3.86
0.22
4.08
$ 4.72
0.12
4.84
$ 4.33
0.17
4.50
$ 4.48
0.30
4.78
59.02
0.01
59.03
61.68
-
61.68
58.35
3.70
62.05
65.16
0.54
65.70
58.01
0.07
58.08
60.68
0.04
60.72
37.35
0.78
$ 38.13
40.94
1.68
$ 42.62
38.82
0.66
$ 39.48
51.67
7.22
58.89
53.74
2.08
55.82
37.62
3.57
$ 41.19
Commodity price risk management - As part of our financial management strategy, Bonavista has adopted a
disciplined commodity price risk management program. The purpose of this program is to stabilize funds from operations
against volatile commodity prices, costs and protect economics of capital invested. Bonavista’s Board of Directors has
approved a commodity price risk management limit of 60% of forecast production, net of royalties, primarily using
costless collars. Our strategy of using costless collars limits Bonavista’s exposure to downturns in commodity prices,
while allowing for participation in commodity price increases.
For the year ended December 31, 2010, our risk management program on financial instrument contracts resulted in a
gain of $19.8 million, consisting of a realized gain of $16.1 million and an unrealized gain of $3.7 million. The realized
gain of $16.1 million consisted of a $15.5 million gain on natural gas commodity derivative contracts and a $600,000 gain
on crude oil commodity derivative contracts. For the same period in 2009, our risk management program on financial
instruments contracts resulted in a net loss of $13.6 million, consisting of a realized gain of $72.1 million and an
unrealized loss of $85.7 million. The realized gain of $72.1 million consisted of a $20.4 million gain on natural gas
commodity derivative contracts and a $51.7 million gain on crude oil commodity derivative contracts.
For the fourth quarter of 2010, our risk management program on financial instrument contracts resulted in a net loss of
$16.1 million, consisting of a realized gain of $4.9 million and an unrealized loss of $21.0 million. The realized gain of
$4.9 million is related entirely to a gain on natural gas commodity derivative contracts. For the same period in 2009, our
risk management program on financial instruments contracts resulted in a loss of $13.5 million, consisting of a realized
gain of $9.5 million and an unrealized loss of $23.0 million. The realized gain of $9.5 million consisted of a $2.5 million
gain on natural gas commodity derivative contracts and a $7.0 million gain on crude oil commodity derivative contracts.
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 crude 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 has
attempted to mitigate a portion of the commodity price risk through the use of various financial instrument contracts and
physical delivery sales contracts.
i) Financial instrument contracts:
As at December 31, 2010, Bonavista entered into the following costless collars to sell natural gas and crude oil as
follows:
Volume
Average Price
Term
10,000 gjs/d CDN$5.13 - CDN$7.75 - AECO
10,000 gjs/d CDN$4.30 - CDN$5.55 - AECO
5,000 gjs/d CDN$4.50 - CDN$7.24 - AECO
10,000 gjs/d CDN$5.25 - CDN$7.20 - AECO
9,500 bbls/d CDN$79.58 - CDN$97.09 - WTI
2,000
bbls/d CDN$81.25 - CDN$100.01 - WTI
January 1, 2011 - March 31, 2011
April 1, 2011 - October 31, 2011
January 1, 2011 - October 31, 2011
January 1, 2011 - December 31, 2011
January 1, 2011 - December 31, 2011
January 1, 2012 - December 31, 2012
Subsequent to December 31, 2010 Bonavista entered into the following costless collars to sell natural gas and crude
oil as follows:
Volume
Average Price
Term
5,000
5,000
1,000
gjs/d CDN$3.50 - CDN$4.28 - AECO
gjs/d CDN$3.60 - CDN$4.60 - AECO
bbls/d CDN$87.50 - CDN$110.00 - WTI
April 1, 2011 - October 31, 2011
April 1, 2012 - October 31, 2012
January 1, 2012 - December 31, 2012
As at December 31, 2010, Bonavista entered into the following option contracts to manage its overall commodity
exposure:
Volume
Price
Contract
Term
28,000
10,000
1,000
500
1,000
gjs/d CDN$4.07
gjs/d CDN $6.45
bbls/d CDN$100.00
bbls/d USD$102.50
bbls/d CDN$105.00
Swap - AECO
Sold Call - AECO
Sold Call - WTI
Sold Call - WTI
Sold Call - WTI
April 1, 2011 - October 31, 2011
April 1, 2011 - October 31, 2011
January 1, 2011 - December 31, 2011
January 1, 2011 - December 31, 2011
January 1, 2012 - December 31, 2012
Subsequent to December 31, 2010, Bonavista entered into the following options contracts to manage its overall
commodity exposure:
Volume
Average Price
Contract
Term
5,000 gjs/d CDN$3.72
500
bbls/d USD$105.00
Swap - AECO
Sold Call - WTI
April 1, 2011 - October 31, 2011
February 1, 2011 - December 31, 2011
Financial instrument contracts are recorded on the consolidated balance sheet 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
operations, comprehensive income and accumulated earnings. As at December 31, 2010, the fair market value
recorded on the consolidated balance sheet for these financial instrument contracts was a net liability of $5.8 million,
compared to a net liability of $9.5 million as at December 31, 2009. These financial instrument contracts had the
following gains and losses reflected in the consolidated statements of operations, comprehensive income and
accumulated earnings:
Realized gains on financial instrument contracts
Unrealized gains (losses) on financial
Three months
ended December 31,
2009
2010
Years
ended December 31,
2009
2010
$ 4,927
$ 9,536
$ 16,080
$ 72,100
instrument contracts
(21,024)
(22,998)
3,764
(85,746)
$ (16,097)
$ (13,462)
$ 19,844
$ (13,646)
Bonavista mitigates its risk associated with fluctuations in commodity prices by utilizing financial instrument
contracts. A $0.10 change in the price per thousand cubic feet of natural gas - AECO would have an impact of
approximately $900,000 on net income for those financial instrument contracts that were in place as at
December 31, 2010. A $1.00 change in the price per barrel of oil – WTI would have an impact of approximately
$2.2 million on net income for those financial instrument contracts that were in place as at December 31, 2010.
ii) Physical purchase and sale contracts:
As at December 31, 2010, Bonavista entered into the following physical contracts to sell natural gas as follows:
Volume
Average Price
Term
10,000 gjs/d CDN$5.00 - CDN$7.34 - AECO
10,000 gjs/d CDN$5.13 - CDN$6.99 - AECO
7,000
gjs/d CDN$4.15 - AECO
January 1, 2011 - March 31, 2011
January 1, 2011 - December 31, 2011
April 1, 2011 - October 31, 2011
As at December 31, 2010, Bonavista entered into the following contracts to purchase electricity as follows:
Volume
Average Price
Term
6 mw/h CDN$50.37 - AESO
mw/h CDN$51.00 - AESO
1
January 1, 2011 - December 31, 2011
January 1, 2011 - December 31, 2012
Subsequent to December 31, 2010, Bonavista entered into the following physical contracts to sell natural gas as
follows:
Volume
Average Price
Term
12,500 gjs/d CDN$3.84 - AECO
April 1, 2011 - October 31, 2011
Physical purchase and sale contracts are being accounted for as they are settled.
Royalties - For the year ended December 31, 2010, royalties increased by 22% to $143.5 million from $117.2 million for
the same period a year ago, largely attributed to a 20% increase in production volumes. In addition, royalties as a
percentage of revenues (including
the year ended
December 31, 2010 increased to 15.0% compared to 14.1% in 2009, largely due to the impact of lower realized gains on
financial instruments contracts and a higher percentage of natural gas liquids production volumes that attract higher
royalty rates. For the three months ended December 31, 2010, royalties decreased by 4% to $35.1 million from
$36.3 million from the same period a year ago, largely due to a decrease in product pricing as compared to the same
period in 2009. In addition, royalties as a percentage of revenues (including realized gains and losses on financial
instrument contracts) for the fourth quarter of 2010 decreased to 14.6% as compared to 15.0% in 2009, for the same
reasons as discussed above.
instrument contracts)
realized gains on
financial
for
The following table highlights Bonavista's royalties by product for the three months and years ended December 31:
Natural gas ($/mcf):
Royalties
% of revenues (1)
Light and medium oil ($/bbl):
Royalties
% of revenues (1)
Heavy oil ($/bbl):
Royalties
% of revenues (1)
Three months
ended December 31,
2009
2010
Years
ended December 31,
2009
2010
0.37
9.0%
10.90
18.5%
10.71
17.4%
0.51
10.5%
11.59
18.7%
10.54
16.0%
0.44
9.7%
11.03
19.0%
10.86
17.9%
0.59
12.3%
9.05
15.4%
8.47
15.2%
(1) % of revenues include realized gains and losses on financial instrument contracts
On January 1, 2009 the Alberta Government’s New Royalty Framework (“NRF”) took effect. Subsequent to this
legislation the Government of Alberta has introduced a number of programs to stimulate new and continued economic
activity in Alberta. The Transitional Royalty Plan (“TRP”), which expires December 31, 2013, offers reduced royalty rates
for new wells drilled that meet certain depth requirements. In addition to the TRP, a second royalty incentive program
was announced by the Government of Alberta. The Three Point Incentive Plan includes a drilling royalty credit for new
conventional oil and natural gas wells and a new royalty incentive program which is set to expire on March 31, 2011.
On March 11, 2010 the Alberta Competitiveness Review board made a number of recommendations for further
improvements to Alberta’s current royalty structure. These recommendations are effective on a permanent basis for the
January 2011 production month and are outlined as follows:
The current incentive program rate of 5% on new natural gas and conventional oil wells will become a permanent
feature of the royalty system, with the current time and volume limits;
The maximum royalty rate for conventional oil will be reduced at higher price levels from 50% to 40% to provide
better risk-reward balance to investors;
Recognizing the fundamental changes to the North American supply/demand balance and increased competition
from other jurisdictions, the maximum royalty rate for conventional and unconventional natural gas will be reduced at
higher price levels from 50% to 36%; and
The NRF legislated in November 2008 will continue until its original announced expiration on December 31, 2013.
Effective January 1, 2011, no new wells will be allowed to select the transitional royalty rates.
On May 27, 2010 the Government of Alberta revealed its proposed changes to the base royalty curves for both
conventional oil and natural gas, which take effect on January 1, 2011. The Government also unveiled further initiatives,
as a result of the competiveness review, intended to energize investment and encourage development of Alberta’s
unconventional and deep resource pools. The most significant of these initiatives are modifications to the natural gas
deep drilling program and the implementation of the emerging resources and technologies initiative. Bonavista has
identified approximately 190 horizontal drilling prospects in our Western Region that will benefit from the reduction in
qualifying depth of the deep drilling program from 2,500 to 2,000 meters true vertical depth. This depth change will result
in a significant royalty credit of approximately $1.0 million per horizontal well.
Operating expenses - Operating expenses for the year ended December 31, 2010 decreased 2% to $194.8 million
compared to $197.8 million for the same period a year ago. Operating expenses for the fourth quarter of 2010 decreased
4% to $49.5 million compared to $51.4 million for the same period a year ago, due to increased production volumes in
areas with lower associated per boe operating expenses. Operating expenses per unit of production for the year ended
December 31, 2010 decreased 18% to $8.05 per boe, from $9.80 per boe in the comparable period of 2009. For the
three months ended December 31, 2010 operating expenses per unit of production decreased 13% to $7.88 per boe from
$9.04 per boe in the comparable period of 2009. This significant decrease on a per boe basis is attributed to efficiency
gains derived from production additions through our recent drilling program, lower per unit operating costs from
acquisitions, lower electricity costs and our ongoing operating cost reduction initiatives.
The following table highlights Bonavista's operating expenses by product for the three months and years ended
December 31:
Natural gas ($/mcf)
Light and medium oil ($/bbl)
Heavy oil ($/bbl)
Three months
ended December 31,
2009
2010
$ 1.29
$ 1.10
10.05
9.03
14.44
14.46
Years
ended December 31,
2009
2010
$ 1.41
$ 1.13
10.66
9.05
14.94
14.45
Total ($/boe)
$ 7.88
$ 9.04
$ 8.05
$ 9.80
Transportation expenses - For the year ended December 31, 2010, transportation expenses increased 8% to
$39.7 million compared to $36.8 million for the same period in 2009 and increased 13% to $10.7 million for the three
months ended December 31, 2010 from $9.4 million in the same period in 2009. On a per boe basis for the three months
ended December 31, 2010, transportation costs increased slightly to $1.70 per boe compared to $1.66 per boe in the
same period in 2009 and for the year ended December 31, 2010 transportation costs decreased 10% to $1.64 per boe
compared to $1.82 per boe in the same period in 2009, due to a significant increase in production volumes in areas with
lower associated transportation costs.
The following table highlights Bonavista's transportation expenses by product for the three months and years ended
December 31:
Natural gas ($/mcf)
Light and medium oil ($/bbl)
Heavy oil ($/bbl)
Three months
ended December 31,
2009
2010
$ 0.30
$ 0.33
0.94
0.86
3.53
3.40
Years
ended December 31,
2009
2010
$ 0.33
$ 0.31
0.92
0.83
3.83
3.31
Total ($/boe)
$ 1.70
$ 1.66
$ 1.64
$ 1.82
General and administrative expenses - General and administrative expenses, after overhead recoveries, increased
17% to $20.9 million for the year ended December 31, 2010 from $17.9 million in the same period in 2009 and increased
4% to $5.4 million for the three months ended December 31, 2010 from $5.2 million in the same period in 2009. On a per
boe basis, general and administrative expenses decreased 3% for the year ended December 31, 2010 to $0.86 per boe
from $0.89 per boe in the same period in 2009 and decreased 5% to $0.87 per boe for the three months ended
December 31, 2010 from $0.92 per boe in the same period in 2009. Our current rate of general and administrative
expenses on a boe basis remains among the lowest in our sector.
For the three months and year ended December 31, 2010, Bonavista incurred restructuring costs associated with the
Arrangement of $736,000 (2009 – nil). This includes legal and advisory fees as well as other associated costs.
In connection with its trust unit rights incentive plan and restricted trust unit incentive plan, Bonavista recorded a unit-
based compensation charge of $3.0 million and $11.6 million for the three months and year ended December 31, 2010
respectively, compared to $2.9 million and $11.4 million for the same periods in 2009.
Financing expenses - Financing expenses increased 101% to $28.3 million for the year ended December 31, 2010,
from $14.0 million for the same period in 2009 and on a per boe basis, increased 67% to $1.17 per boe for the year
ended December 31, 2010 from $0.70 per boe for the same period in 2009. For the three months ended
December 31, 2010, financing expenses increased 146% to $11.0 million from $4.5 million for the same period in 2009
and on a per boe basis, increased 123% to $1.74 per boe for the three months ended December 31, 2010 from $0.78 per
boe for the same period in 2009. The increase in financing expenses for the three months and year ended
December 31, 2010 compared to the same period in 2009 is the result of an increase in borrowing costs on our loan
facilities, an increase in our average debt levels and an increase in interest rates. For the year ended
December 31, 2010, Bonavista paid cash interest of $24.6 million compared to $14.4 million for the same period in 2009.
During the fourth quarter of 2010, Bonavista paid cash interest of $8.0 million compared to $5.1 million for the same
period in 2009. Bonavista's effective interest rate as at December 31, 2010 was approximately 3.7% (2009 – 1.5%).
Depreciation, depletion and accretion expenses - Depreciation, depletion and accretion expenses increased 20% to
$354.6 million for the year ended December 31, 2010 from $295.3 million for the same period in 2009. For the three
months ended December 31, 2010, depreciation, depletion and accretion expenses increased 7% to $91.6 million from
$85.2 million for the same period in 2009. These increases are largely due to an increase in our overall production base
compared to the same periods in 2009. For the year ended December 31, 2010, the average cost increased slightly to
$14.66 per boe from $14.63 per boe for the same period in 2009. For the three months ended December 31, 2010, the
average cost decreased 3% to $14.56 per boe from $14.99 per boe for the same period a year ago due to lower finding,
development and acquisition costs.
Income taxes - For the year ended December 31, 2010, the income tax recovery was $21.9 million compared to a
recovery of $52.6 million for the same period in 2009. For the three months ended December 31, 2010, the income tax
recovery was $16.1 million compared to a recovery of $15.8 million for the same period in 2009. Bonavista made no
cash payments on tax installments for the three months and year ended December 31, 2010 or for the comparative
periods in 2009.
Funds from operations, net income and comprehensive income - For the year ended December 31, 2010, Bonavista
experienced an 18% increase in funds from operations to $527.0 million ($3.44 per share, basic) from $447.7 million
($3.46 per share, basic) for the same period in 2009. The increase in funds from operations for the year ended
December 31, 2010 is largely attributed to an increase in production volumes. For the three months ended
December 31, 2010, Bonavista experienced a 6% decrease
to $127.3 million
($0.81 per share, basic) from $135.5 million ($0.93 per share, basic) for the same period in 2009. The decrease in funds
from operations for the three months ended December 31, 2010 is largely due to lower product prices. Net income and
comprehensive income for the year ended December 31, 2010, increased 89% to $201.6 million ($1.32 per share, basic)
from $106.6 million ($0.82 per share, basic) for the same period in 2009. For the three months ended
December 31, 2010, net income and comprehensive income increased slightly to $39.8 million ($0.25 per share, basic)
from $39.6 million ($0.27 per share, basic) for the same period in 2009.
from operations
funds
in
The following table is a reconciliation of a non-GAAP measure, funds from operations, to its nearest measure prescribed
by GAAP:
Calculation of Funds From Operations:
(thousands)
Cash flow from operating activities
Asset retirement expenditures
Changes in non-cash working capital
Three months
ended December 31,
2009
2010
Years
ended December 31,
2009
2010
$ 115,741
7,012
4,505
$ 154,758
3,440
(22,664)
$ 514,164
15,831
(3,008)
$ 423,933
12,036
11,774
Funds from operations
$ 127,258
$ 135,534
$ 526,987
$ 447,743
Capital expenditures - Capital expenditures for the year ended December 31, 2010 were $570.0 million, consisting of
$349.5 million spent on exploration and development activities with the remaining $220.5 million spent on net property
acquisitions. For the same period in 2009 capital expenditures were $833.8 million, consisting of $203.8 million on
exploration and development spending and $630.0 million on net property acquisitions. Capital expenditures for the
three months ended December 31, 2010 were $54.6 million, consisting of $94.4 million spent on exploration and
development activities and net property dispositions of $39.8 million. For the same period in 2009, capital expenditures
were $75.2 million, consisting of $62.0 million spent on exploration and development and $13.2 million spent on net
property acquisitions. Our service costs supporting our exploration and development activities have experienced some
pressure in the fourth quarter of 2010. A significant increase in the demand for services year over year has resulted in a
modest erosion in pricing efficiency. We will continue to monitor the situation and will rely heavily on our relationships
that we have cultivated over the past 13 years.
The following table outlines capital expenditures by category for the years ended December 31, 2010 and 2009:
(thousands)
Land acquisitions
Geological and geophysical
Drilling and completion
Production equipment and facilities
Other
Exploration and development expenditures
Acquisitions
Dispositions
Net capital expenditures
Years
ended December 31,
2010
2009
$
71,444
11,898
199,669
65,051
1,419
349,481
286,084
(65,570)
$
20,385
6,829
133,811
41,704
1,116
203,845
737,117
(107,118)
$
569,995
$
833,844
Liquidity and capital resources - As at December 31, 2010, long-term debt including working capital (excluding
associated assets and liabilities from financial instrument contracts and their related tax impact) was $1.0 billion with a
debt to fourth quarter 2010 annualized funds from operations ratio of 2.0:1. Bonavista has significant flexibility to finance
future expansions of its capital programs, through the use of its current funds generated from operations and its debt
facilities. As at December 31, 2010, Bonavista has approximately $844.7 million of unused borrowing capacity from its
$1.4 billion bank credit facility. In addition to the bank credit facility, Bonavista has a US$125.0 million master shelf
agreement of which US$75.0 million remains undrawn.
On September 10, 2010 Bonavista combined and renewed its bank credit facilities into a single facility of $1.4 billion
provided by a syndicate of 12 domestic and international banks. This facility is a three year revolving facility and may at
the request of Bonavista and with the consent of the lenders be extended on an annual basis. The facility has a maturity
date of September 10, 2013. Under the terms of the 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 and accretion;
(ii) consolidated total debt will not exceed three and one half times consolidated net income before unrealized gains and
losses on financial instrument contracts and marketable securities, interest, taxes and depreciation, depletion and
accretion; and (iii) consolidated senior debt borrowing will not exceed one-half of consolidated total debt plus
consolidated shareholders’ equity of the Corporation, in all cases calculated based on a rolling prior four quarters.
On March 3, 2011, Bonavista elected to reduce the committed amount of its bank credit facility by $400 million from
$1.4 billion to $1.0 billion as a result of capacity created from the issuance of senior unsecured debt and the desire to
reduce the cost of carrying the larger undrawn facility. The result of this reduction will leave Bonavista with $444.7 million
of undrawn borrowing capacity, proforma as at December 31, 2010.
In the second quarter of 2010, Bonavista 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. On June 4, 2010 Bonavista 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. Under the terms of the master shelf agreement, the
Corporation has provided the same significant covenants that exist under the bank credit facility.
On November 2, 2010, Bonavista issued by way of a private placement US$300 million and CDN$50 million of long-term
notes with a weighted average coupon rate of 4.12% and a weighted average term of 8.8 years. Proceeds from the
issuance were used to repay existing long-term debt under the bank credit facility.
In 2011, Bonavista plans to invest between $345 and $375 million on its capital programs within its core regions.
Bonavista intends on financing its 2011 capital program with a combination of funds from operations and to the extent
required its existing credit facilities. Going forward, Bonavista remains committed to the fundamental principle of
maintaining financial flexibility and the prudent use of debt.
Shareholders’ and Unitholders’ equity – On December 31, 2010, pursuant to the Arrangement, unitholders received
one common share of Bonavista for each trust unit held, in addition, exchangeable shareholders of Bonavista Petroleum
Ltd. received 2.40917 exchangeable shares of Bonavista for each exchangeable share held. As at December 31, 2010,
Bonavista had 156.6 million equivalent common shares outstanding, which includes 22.6 million exchangeable shares.
As at March 3, 2011, Bonavista had 156.8 million equivalent common shares outstanding. This includes 22.2 million
exchangeable shares, which are exchangeable into 22.3 million common shares. The exchange ratio in effect at
March 3, 2011 for exchangeable shares was 1.00413:1. In addition, Bonavista has 5.0 million common share incentive
rights outstanding as at March 3, 2011, with an average exercise price of $21.77 per common share.
Contractual obligations - The following is a summary of Bonavista’s contractual obligations and commitments as at
December 31, 2010:
(thousands)
Long-term debt repayments (1)(3)
Interest payments (2)(3)
Transportation expenses
Office premises
Total
2011
2012
2013
2014
2015 and
thereafter
Payments Due by Period
$ 955,348
143,126
49,205
21,376
$
-
16,765
16,428
1,272
$
-
16,765
12,662
3,054
$ 555,348
16,765
9,521
3,054
$
-
16,765
5,612
3,054
$ 400,000
76,066
4,982
10,942
Total contractual obligations
$1,169,055 $ 34,465
$ 32,481
$ 584,688
$ 25,431
$ 491,990
(1)
(2)
(3)
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 2013.
Fixed interest payments on senior unsecured notes.
US dollars payments are converted using the exchange rate of $1.00 US/Canadian dollar.
Distributions/Dividends - For the year ended December 31, 2010, Bonavista declared distributions of $252.3 million
($1.92 per unit) compared to $218.0 million ($2.00 per unit) in the same period in 2009. For the three months ended
December 31, 2010, Bonavista declared distributions of $64.2 million ($0.48 per unit) compared to $59.8 million
($0.48 per unit) in the same period in 2009. Bonavista’s dividend policy is constantly monitored and is dependent upon
its forecasted production, commodity prices, funds from operations, debt levels and capital expenditures. Within a
dividend paying corporate structure, Bonavista is well positioned to provide our shareholders a combination of
sustainable growth and meaningful income. While the proven underlying operating strategies of Bonavista will remain
intact, our new business model has been designed to deliver long-term total shareholder returns of between 10% and
15% per annum.
The following table illustrates the relationship between cash flow provided from operating activities and distributions
declared, as well as net income and distributions declared. Net income includes significant non-cash charges, such as
depreciation, depletion and accretion, unrealized gains and losses on financial instrument contracts, unrealized gains
and losses on foreign exchange, fluctuations in future income taxes due to changes in tax rates and tax rules, and unit-
based compensation.
These non-cash charges do not represent the actual cost of maintaining our production capacity given the natural
declines associated with oil and natural gas assets. For the three months ended December 31, 2010, the non-cash
charges amounted to $87.5 million compared to $95.3 million for the same period in 2009. For the year ended
December 31, 2010, the non-cash charges amounted to $327.3 million compared to $339.8 million for the same period in
2009. In instances where distributions exceed net income, a portion of the cash distribution paid to unitholders may be
considered an economic return of unitholders' equity.
Distribution Analysis
(thousands)
Cash flow provided from operating activities
Net income
Distributions declared
Excess of cash flow provided from operating
Three months
ended December 31,
Years
ended December 31,
2010
2009
2010
2009
$ 115,741
39,784
64,242
$ 154,758
39,647
59,783
$ 514,164
201,581
252,298
$ 423,933
106,606
217,965
activities over distributions declared
Shortfall of net income over distributions declared
51,499
(24,458)
94,975
(20,136)
261,866
(50,717)
205,968
(111,359)
Bonavista expects to deliver a 5% to 7% annual production growth rate and expects to pay a monthly dividend of
$0.12 per share for the production month beginning January 2011.
Annual financial information - The following table highlights selected annual financial information for each of the three
years ended December 31, 2010, 2009 and 2008:
Years ended December 31,
(thousands, except per share amounts)
Consolidated Statement of Operations Information:
Production revenues, net of royalties
Funds from operations
Per share – basic
Per share – diluted
Net income
Per share – basic
Per share – diluted
Consolidated Balance Sheet Information:
Total capital expenditures
Total assets
Working capital deficiency
Long-term debt
Shareholders’ equity
Distributions declared
2010
2009
2008
$ 795,219
526,987
3.44
3.40
201,581
1.32
1.30
$ 569,995
3,342,988
(70,012)
951,443
1,877,608
252,298
$ 642,206
447,743
3.46
3.43
106,606
0.82
0.81
$ 833,844
3,092,129
(87,124)
832,138
1,723,583
217,965
$ 994,424
643,876
5.64
5.56
438,366
3.84
3.80
$ 482,297
2,543,240
(11,726)
588,792
1,411,972
332,540
Quarterly financial information - The following table highlights Bonavista’s performance for the eight quarterly periods
ending on March 31, 2009 to December 31, 2010:
December 31 September 30
June 30
March 31
December 31 September 30
June 30
March 31
2010
2009
($ thousands, except per share amounts)
Production revenues
Net income
Net income per share:
Basic
Diluted
234,706
39,784
222,656
36,614
227,732
45,449
253,632
79,734
232,870
39,647
180,977
33,339
166,430
661
179,146
32,959
0.25
0.25
0.24
0.23
0.30
0.30
0.54
0.53
0.27
0.27
0.25
0.25
0.01
0.01
0.28
0.28
Production revenues over the past eight quarters have fluctuated largely due to the volatility of commodity prices and
increasing production volumes. Net income in the past eight quarters has fluctuated from a low of $661,000 in the
second quarter of 2009 to a high of $79.7 million in the first quarter of 2010. These fluctuations are primarily influenced
by production volumes, commodity prices, realized and unrealized gains and losses on financial instrument contracts and
marketable securities; gains and losses on foreign exchange and future income tax recoveries associated with the
reduction in corporate income tax rates. Net income increased slightly in the fourth quarter of 2010 as compared to the
fourth quarter of 2009, as the decline in product pricing was offset by a 10% increase in production volumes.
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 has
concluded that their internal control over financial reporting was effective as of December 31, 2010. There were no
material changes to the internal controls over financial reporting during the three months ended December 31, 2010.
the effectiveness of Bonavista’s
internal control over
financial
International financial reporting standards - On January 1, 2011 International Financial Reporting Standards (“IFRS”)
will become the generally accepted accounting principles in Canada. The adoption date of January 1, 2011 will require
restatement, for comparative purposes, of amounts reported by Bonavista for the year ended December 31, 2010,
including the opening consolidated balance sheet as at January 1, 2010. Since its inception the project has been led by
a group of internal staff assisted by external consultants and supported by the management team. Bonavista’s auditors
have also continued to be involved throughout the process to ensure that its accounting policies are in accordance with
the standards set out by IFRS.
Most adjustments required on the transition to IFRS will be made retrospectively against the opening retained earnings of
the first comparative balance sheet presented, based on the applicable standards at that time. IFRS 1 provides entities
adopting IFRS for the first time certain optional and mandatory exemptions to the general requirements of full
retrospective application of IFRS. Management has analyzed the various exemptions available under IFRS 1 and has
implemented those determined to be the most appropriate for Bonavista at this time. Accordingly, Bonavista has applied
the following IFRS 1 exemptions in its opening consolidated balance sheet.
Property, Plant and Equipment (“PP&E”) – Bonavista’s PP&E assets must be allocated to its cash generating units
(“CGU”) unlike under Canadian GAAP where all oil and natural gas assets are accumulated into one cost centre.
The deemed cost of Bonavista’s oil and natural gas assets have been allocated to its defined CGUs based on
Bonavista’s proved and probable reserve values as at January 1, 2010. These CGUs are aligned within the major
geographic regions in which Bonavista operates and could change in the future as a result of significant acquisition
and disposition activity.
Business Combinations – IFRS 1 would allow Bonavista to use the IFRS rules from business combinations on a
prospective basis rather than restating all business combinations. Bonavista will not be recording adjustments to
retrospectively restate any of its business combinations that have occurred prior to January 1, 2010.
The following is a listing of key areas where accounting policies will differ from Canadian GAAP and where accounting
policy decisions will impact our reported financial position and results of operations:
Exploration and Evaluation (“E&E”) expenditures – Upon transition to IFRS, Bonavista will reclassify all E&E
expenditures that are currently included in the PP&E balance on the Consolidated Balance Sheet. This will consist
of the book value for Bonavista’s undeveloped land that relates to exploration properties. E&E assets will not be
depleted and must be assessed for impairment when indicators of impairment exist. Management has identified and
reclassified approximately $179.7 million of assets from PP&E to E&E in the opening consolidated balance sheet
prepared under IFRS as at January 1, 2010.
Depletion expense – Upon transition to IFRS, Bonavista has the option to calculate depletion using a reserve base of
proved reserves or both proved plus probable reserves, as compared to using only proved reserves under Canadian
GAAP. Bonavista has determined to calculate its depletion expense based upon using proved and probable
reserves as its depletion base and therefore we anticipated the depletion expense for the year ended
December 31, 2010 to decrease as compared to its current calculation under Canadian GAAP.
Impairment of PP&E assets – Under IFRS, an impairment test of PP&E must be performed at the CGU level as
opposed to the entire PP&E balance, which is currently required under Canadian GAAP through the full cost ceiling
test. Bonavista is required to recognize an impairment loss if the carrying amount of a CGU exceeds the higher of its
fair value less cost to sell and value in use. Under Canadian GAAP, estimated future cash flows used to assess
impairments are not discounted.
Impairment of Goodwill – For goodwill impairment under IFRS, goodwill that arises from a business combination is
allocated to the specific CGUs that are expected to benefit from the business combination. The carrying value of the
CGU including goodwill is compared to the fair value of the CGU and any excess of the carrying value over the fair
value is considered impairment and would be charged to retained earnings on the opening consolidated balance
sheet prepared under IFRS. Bonavista is currently in the process of determining whether a goodwill impairment
exists or not.
Provisions for Asset Retirement costs – Under IFRS, Bonavista is required to revalue its liability for asset retirement
costs at each balance sheet date using the current risk-free rate of interest when the expected cash flows are risked.
Under present Canadian GAAP, once recorded, asset retirement obligations are not adjusted for future changes in
discount rates. IFRS also requires that asset retirement obligations be re-measured each reporting period for
changes in the discount rate with a corresponding adjustment to the cost of property, plant and equipment, whereas
under Canadian GAAP, changes in discount rates do not result in a re-measurement. At January 1, 2010
Bonavista’s total of its asset retirement obligations will increase by $141.0 million to $301.4 million as the liability is
revalued to reflect the estimated risk free rate of interest of 4.1% as compared to the credit adjusted risk-free rate of
7.5% used under Canadian GAAP.
Exchangeable shares - Under IFRS, exchangeable shares are considered to be a puttable financial instrument and
will be classified as a financial liability. They will be recorded on the statement of financial position at their fair value
with any changes being recorded in the statement of comprehensive income. As at January 1, 2010, Bonavista’s
liability associated with Bonavista Petroleum Ltd. exchangeable shares under IFRS is $479.1 million. On
December 31, 2010 the Trust completed its conversion from an energy trust to a corporation resulting in
exchangeable shares being classified as equity under IFRS.
Common share-based payments – Under IFRS, Bonavista’s common share incentive rights and restricted common
share incentive rights are considered to be cash-settled awards and will be classified as a liability. The liability is
measured at fair value with subsequent changes in the fair value recognized in the statement of comprehensive
income. Under Canadian GAAP, Bonavista uses the fair value based method for the determination of the common
share-based compensation costs. As at January 1, 2010, Bonavista’s liability associated with common share-based
payments under IFRS is approximately $12.0 million. On December 31, 2010, the Trust completed its conversion
from an energy trust to a corporation resulting in common share based awards to be classified as equity under IFRS.
Deferred taxes – Under IFRS, entities that are subject to different tax rates on distributed and undistributed income
must calculate deferred taxes using the undistributed profits rate, which is the higher of the two. Canadian GAAP
requires each individual tax rate to be applied to distributed and undistributed profits, respectively. As a result of
using the undistributed profits rate, Bonavista will record a reduction in its deferred tax liability upon transition to
IFRS, with the offset recorded as a reduction to its shareholders equity. This amount has been calculated based
upon the adjustments made to the opening consolidated balance sheet prepared under IFRS as determined at
March 3, 2011.
The following table summarizes Bonavista’s January 1, 2010 consolidated balance sheet under Canadian GAAP and the
transitional entries required to present the opening consolidated balance sheet under IFRS as determined at
March 3, 2011. The amounts are unaudited as Bonavista has not yet completed a full set of annual financial statements
under IFRS.
Consolidated Balance Sheet as at January 1, 2010
(thousands)
Current assets
Long-term assets
Current liabilities
Long-term liabilities
Shareholders’ equity
Canadian GAAP
IFRS Adjustments
IFRS
$
144,735
2,947,394
3,092,129
231,859
1,136,687
1,723,583
$ 3,092,129
$
$
(4,424)
(192)
(4,616)
486,475
116,891
(607,982)
(4,616)
$
140,311
2,947,202
3,087,513
718,334
1,253,578
1,115,601
$ 3,087,513
In addition to accounting policy differences, Bonavista’s transition to IFRS is expected to impact internal controls over
financial reporting, disclosure controls and procedures, certain business activities and information systems.
Internal controls over financial reporting (“ICFR”) – In conjunction with assessing our accounting policy choices under
IFRS, we also assessed whether there were any instances where controls needed to be amended or added. We
have determined that there are no material changes to our control procedures as we transition to IFRS.
Disclosure controls and procedures – Bonavista has assessed the impact of the transition to IFRS on its disclosure
controls and procedures and has not identified any material changes required to its control environment. It is
expected that there will be increased note disclosure around certain financial statement items than what is currently
required under Canadian GAAP. Management is currently drafting its IFRS note disclosure in accordance with the
current IFRS standards and will continue to monitor further requirements put forth by the International Accounting
Standards Board in discussion papers and exposure drafts for future disclosure requirements. Bonavista will
continue to assess its stakeholders’ information requirements to ensure that adequate and timely information is
provided to meet these needs.
Business activities – Upon transition to IFRS, management has been cognizant of ensuring that any existing
agreements with counterparties and lenders that contain references to Canadian GAAP are modified to allow for
IFRS statements. Based on the changes to Bonavista’s accounting policies no issues are expected to arise with the
existing wording of our debt covenants and other related agreements as a result of converting to IFRS.
Information systems – Bonavista has completed the accounting system updates required in order to prepare for the
transition to IFRS reporting. These updates while not significant are critical to allow for reporting of both Canadian
GAAP and IFRS statements in 2010 as well as tracking of PP&E and E&E expenditures to a more detailed level as
required under IFRS.
Critical Accounting Estimates - The consolidated financial statements have been prepared in accordance with
Canadian GAAP. A summary of significant accounting policies are presented in note 1 of the Notes to the Consolidated
Financial Statements. Certain accounting policies are critical to understanding the financial condition and results of
operations of Bonavista.
a) Proved oil and natural gas reserves - Proved oil and natural gas reserves, as defined by the Canadian Securities
Administrators in National Instrument 51-101 with reference to the Canadian Oil and Natural Gas Evaluation
Handbook, are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that
the actual remaining quantities recovered will exceed the estimated proved reserves.
An independent reserve evaluator using all available geological and reservoir data as well as historical production
data has prepared Bonavista’s oil and natural gas reserve estimates. Estimates are reviewed and revised as
appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes, reservoir performance or a
change in Bonavista’s development plans. The effect of changes in proved oil and natural gas reserves on the
financial results and position of Bonavista is described in b) below.
b) Depreciation, depletion and accretion expense - Bonavista uses the full cost method of accounting for exploration
and development activities whereby all costs associated with these activities are capitalized, whether successful or
not. The aggregate of capitalized costs, net of certain costs related to unproved properties, and estimated future
development costs is amortized using the unit-of-production method based on estimated proved reserves. Changes in
estimated proved reserves or future development costs have a direct impact on depreciation and depletion expense.
Certain costs related to unproved properties and major development projects may be excluded from costs subject to
depletion until proved reserves have been determined or their value is impaired. These properties are reviewed
quarterly to determine if proved reserves should be assigned, at which point they would be included in the depletion
calculation, or for impairment, for which any write-down would be charged to depreciation and depletion expense.
c) Full cost accounting ceiling test - The carrying value of property, plant and equipment is reviewed at least annually
for impairment. Impairment occurs when the carrying value of the assets is not recoverable by the future
undiscounted cash flows. The cost recovery ceiling test is based on estimates of proved reserves, production rates,
petroleum and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are
subject to measurement uncertainty and the impact on the financial statements could be material. Any impairment
would be charged as additional depletion and depreciation expense.
d) Asset retirement obligations - The asset retirement obligations are estimated based on existing laws, contracts or
other policies. The fair value of the obligation is based on estimated future costs for abandonment and reclamation
discounted at a credit adjusted risk free rate. The costs are included in property, plant and equipment and amortized
over their useful life. The liability is adjusted each reporting period to reflect the passage of time, with the accretion
charged to earnings and for revisions to the estimated future cash flows. By their nature, these estimates are subject
to measurement uncertainty and the impact on the financial statements could be material.
e) Income taxes - The determination of Bonavista’s income and other tax liabilities requires interpretation of complex
laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential
reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly
from that estimated and recorded.
Assessment of Business Risks
The following are the primary risks associated with our business. Bonavista’s financial position, results of operations and
dividends to shareholders are directly impacted by these factors and include:
1) operational risk associated with the production of oil and natural gas;
2) reserve risk in respect to the quantity and quality of recoverable reserves;
3) market risk relating to the availability of transportation systems to move the product to market;
4) commodity risk as crude oil and natural gas prices fluctuate due to market forces;
5)
financial risk such as volatility of the Canadian/US dollar exchange rate, interest rates and debt service
obligations;
6) potential risk of change in dividends;
7) environmental and safety risk associated with well operations and production facilities;
8) changing government regulations relating to royalty legislation, income tax laws, incentive programs, operating
practices and environmental protection relating to the oil and natural gas industry;
9) continued participation of Bonavista’s lenders;
10) counterparty risk with respect to non-performance by counterparties to financial derivative contracts; and
11) financial risk associated with domestic and international debt and equity markets.
Bonavista seeks to mitigate these risks by:
1) acquiring properties with well established production trends to reduce technical uncertainty;
2) acquiring long life reserves to ensure more stable production and to reduce the economic risks associated with
commodity price cycles;
3) maintaining a low cost structure to maximize product netbacks and reduce impact of commodity price cycles;
4) diversifying properties to mitigate individual property and well risk;
5) maintaining product mix to balance exposure to commodity prices;
6) conducting rigorous reviews of all property acquisitions;
7) monitoring pricing trends and developing a mix of contractual arrangements for the marketing of products with
creditworthy counterparties;
8) maintaining a hedging program to hedge commodity prices and foreign exchange currency rates with
creditworthy counterparties;
9) ensuring strong third party-operators for non-operated properties;
10) adhering to our safety program and keeping abreast of current operating best practices;
11) keeping informed of proposed changes in regulations and laws to properly respond to and plan for the effects
that these changes may have on our operations;
12) carrying insurance to cover losses and business interruption; and
13) establishing and maintaining adequate cash resources to fund future abandonment and site restoration costs.
OUTLOOK
As we embark on our first year as a dividend paying corporation, we continue to apply the same proven strategies that
we have employed throughout our history of creating value for our investors. The foundation of these strategies is to
consistently exercise cost discipline and a high level of capital spending efficiency as we actively pursue a variety of
quality drilling opportunities on our extensive land base, coupled with complementary acquisitions within geographically
concentrated areas of operations. Since the Federal Government’s trust tax announcement on October 31, 2006,
Bonavista has been preparing for the inevitable corporate conversion by enhancing our entrepreneurial team, improving
both our operating cost structure and capital efficiencies, and increasing our inventory of organic growth opportunities.
This transition has been successfully completed.
We currently have identified approximately 1,150 drilling prospects on our land base which represents a 100% increase
over our inventory at the time of the government’s announcement signaling the end of the trust structure. More
importantly, we have also managed to gain significant improvements in the quality of our drilling inventory. Through a
purposeful effort to pursue higher impact drilling targets, we have focused our development and acquisition efforts on
deeper geological horizons towards scalable resource plays that are amenable to the benefits of horizontal drilling and
multi-stage completion technology. We have been successful in this regard with average reserves per well increasing by
over 400% and average initial production rates increasing by over 250% as compared to 2007 results. As we proceed
into 2011, more than 80% of our future opportunities involve the application of horizontal drilling and multi-stage fracture
technology within scalable resource plays. Our timely and prudent approach to capital investment has been very effective
in the past and our attention to detail together with our steadfast commitment to adding shareholder value will continue to
provide the foundation for the future success of our organization. Today our efficiency, productivity, and confidence are
among the highest level in our thirteen year history.
We continue to closely monitor natural gas prices and believe the excessive North American supply growth will moderate
as current pricing does not generate sufficient full cycle profitability metrics for most plays being developed today.
However, because the timing of this supply response is difficult to determine and current natural gas prices remain weak,
we will reduce our capital spending program for 2011 between $345 and $375 million, directed entirely towards
exploration and development activities. We plan to allocate a majority of our 2011 capital spending towards the
development of four key resource plays consisting of our Hoadley Glauconite, Cardium Light Oil, Deep Basin Liquids
Rich Natural Gas and Blueberry Montney programs, collectively making up approximately 60% of total budgeted
development spending in 2011. As always, maximum flexibility over our capital spending will be maintained and while
our primary focus will be to efficiently execute our drilling program in 2011, we will also continue to evaluate incremental
acquisition opportunities as they present themselves. With 75% of the wells budgeted in 2011 targeting high impact
plays using horizontal drilling and multi-stage completion techniques, we remain confident that we can achieve modest
growth in our 2011 annual production to average between 69,000 and 71,000 boe per day.
We are proud of our accomplishments over the past year and despite continued weak natural gas prices, we remain
enthusiastic and confident about our future. Throughout many business cycles Bonavista has converted adversity into
opportunity, pursued counter-cyclical strategies and has emerged as an even stronger entity. We would like to thank our
employees for their significant effort and their continued perseverance as we embrace the future as a dividend paying
corporation. We remain confident that our operating philosophy works well in any environment and this will aid in our
goal to continually create long-term value for our shareholders. Our team is very committed to this vision.
On behalf of the Board of Directors
Keith A. MacPhail
Chairman and Chief Executive Officer
Jason E. Skehar
President and Chief Operating Officer
March 3, 2011
Calgary, Alberta
MANAGEMENT’S REPORT
The preparation of the accompanying consolidated financial statements in accordance with accounting principles generally accepted in
Canada is the responsibility of management. Financial information contained elsewhere in this Annual Report is consistent with that in
the consolidated financial statements.
Management is responsible for the integrity and objectivity of the financial statements. Where necessary, the financial statements
include estimates, which are based on management’s informed judgments. Management has established systems of internal controls,
which are designed to provide reasonable assurance those assets, are safeguarded from loss or unauthorized use and to produce
reliable accounting records for the preparation of financial information.
The Board of Directors is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal
control. It exercises its responsibilities primarily through the Audit Committee, all of whose members are non-management directors.
The Audit Committee has reviewed the consolidated financial statements with management and the auditors and has reported to the
Board of Directors, which have approved the consolidated financial statements.
KPMG LLP are independent auditors appointed by Bonavista’s shareholders. The auditors have considered, for the purposes of
determining the nature, timing and extent of their audit procedures, Bonavista’s internal controls and have audited the consolidated
financial statements in accordance with generally accepted auditing standards to enable them to express an opinion on the fairness of
the financial statements in accordance with Canadian generally accepted accounting principles.
Keith A. MacPhail
Chairman and Chief Executive Officer
Glenn A. Hamilton
Senior Vice President and Chief Financial Officer
March 3, 2011
Calgary, Alberta
INDEPENDENT AUDITORS’ REPORT
To the Shareholders of Bonavista Energy Corporation
We have audited the accompanying consolidated financial statements of Bonavista Energy Corporation (“the Corporation”), which
comprise the consolidated balance sheets as at December 31, 2010 and 2009, the consolidated statements of operations,
comprehensive income, and accumulated earnings, 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
Canadian generally accepted accounting principles, and for such internal control as management determines is necessary to enable
the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.
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 the
Corporation as at December 31, 2010 and 2009, and the results of its consolidated operations and its consolidated cash flows for the
years then ended in accordance with Canadian generally accepted accounting principles.
Chartered Accountants
Calgary, Canada
March 3, 2011
BONAVISTA ENERGY CORPORATION
Consolidated Balance Sheets
December 31,
(thousands)
Assets:
Current assets:
Accounts receivable and prepaids
Marketable securities
Financial instrument contracts (note 11)
Future income tax asset (note 10)
Oil and natural gas properties and equipment (note 6)
Goodwill
Liabilities and Shareholders’/Unitholders’ Equity:
Current liabilities:
2010
2009
$ 139,008
$ 128,363
-
11,413
3,241
6,322
5,626
4,424
153,662
144,735
3,148,005
2,906,073
41,321
41,321
$ 3,342,988
$ 3,092,129
Accounts payable and accrued liabilities
$ 186,447
$ 157,019
Distributions payable
Financial instrument contracts (note 11)
Convertible debentures (note 8)
Future income tax (note 10)
Financial instrument contracts (note 11)
Long-term debt (note 7)
Asset retirement obligations (note 4)
Future income tax (note 10)
Shareholders’/Unitholders’ equity: (note 9)
21,436
12,931
-
2,860
223,674
4,261
951,443
168,423
117,579
19,937
15,169
38,093
1,641
231,859
-
832,138
160,314
144,235
Unitholders’ capital and debenture conversion component
-
1,531,299
Shareholders’ capital
Exchangeable shares
Contributed surplus
Accumulated earnings
Commitments (note 13)
See accompanying notes to the consolidated financial statements.
Approved on behalf of the Board of Directors of Bonavista Energy Corporation:
1,737,077
57,286
14,292
68,953
-
59,295
13,319
119,670
1,877,608
1,723,583
$ 3,342,988
$ 3,092,129
Ian S. Brown, Director
Michael M. Kanovsky, Director
BONAVISTA ENERGY CORPORATION
Consolidated Statements of Operations, Comprehensive Income and Accumulated Earnings
Years ended December 31,
(thousands, except per share amounts)
Revenues:
Production
Royalties
Realized gains on financial instruments contracts (note 11)
Unrealized gains (losses) on financial instruments contracts (note 11)
Expenses:
Operating
Transportation
General and administrative
Restructuring costs
Financing (note 7)
Loss (Gain) on marketable securities
Foreign exchange gain
Unit-based compensation
Depreciation, depletion and accretion
Income before taxes
Income taxes (recovery) (note 10)
Net income and comprehensive income
Accumulated earnings, beginning of year
Distributions declared
Accumulated earnings, end of year
Net income per share – basic
Net income per share – diluted
See accompanying notes to the consolidated financial statements.
2010
2009
$ 938,726
$ 759,423
(143,507)
(117,217)
795,219
642,206
16,080
3,764
19,844
72,100
(85,746)
(13,646)
815,063
628,560
194,755
39,652
20,897
736
28,272
(1,871)
(13,248)
11,584
354,593
197,795
36,833
17,900
-
14,035
1,336
-
11,386
295,296
635,370
574,581
179,693
(21,888)
53,979
(52,627)
201,581
106,606
119,670
231,029
(252,298)
(217,965)
68,953
$ 119,670
1.32
$
0.82
1.30
$
0.81
$
$
$
BONAVISTA ENERGY CORPORATION
Consolidated Statements of Cash Flows
Years ended December 31,
(thousands)
Cash provided by (used in):
Operating Activities:
Net income
Items not requiring cash from operations:
Depreciation, depletion and accretion
Unit-based compensation
Unrealized (gains) losses on financial instruments contracts
Loss (Gain) on marketable securities
Foreign exchange gain
Future income taxes (recovery)
Asset retirement expenditures
Changes in non-cash working capital items
Financing Activities:
Issuance of equity, net of issue costs
Issuance of senior notes
Distributions
Repayment of bank credit facility
Increase in bank credit facility
Repayment of convertible debentures
Changes in non-cash working capital items
Investing Activities:
Exploration and development
Property acquisitions
Property dispositions
Proceeds on sale of marketable securities
Changes in non-cash working capital items
2010
2009
$ 201,581
$ 106,606
354,593
11,584
(3,764)
(1,871)
(13,248)
(21,888)
(15,831)
3,008
295,296
11,386
85,746
1,336
-
(52,627)
(12,036)
(11,774)
514,164
423,933
188,043
409,301
(250,799)
(409,301)
132,511
(38,567)
1,079
404,115
-
(226,759)
-
243,346
(6,586)
(349)
32,267
413,767
(349,481)
(285,409)
65,570
8,193
14,696
(203,845)
(737,117)
107,118
-
(3,856)
(546,431)
(837,700)
Change in cash
Cash, beginning of year
Cash, end of year
See accompanying notes to the consolidated financial statements.
-
-
-
$
-
-
-
$
BONAVISTA ENERGY CORPORATION
Notes to Consolidated Financial Statements
Years ended December 31, 2010 and 2009
Structure of Bonavista and Basis of Presentation:
The principal undertakings of Bonavista Energy Corporation, its predecessor Bonavista Energy Trust (the “Trust”) 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. On December 31, 2010, the Trust effectively completed its conversion from an energy trust to a corporation
pursuant to the plan of arrangement (the “Arrangement”) under Section 193 of the Business Corporations Act (Alberta) that was
approved by securityholders at the Joint Special Meeting of Securityholders of the Trust and Bonavista Petroleum Ltd. on
December 14, 2010. On December 31, 2010, the Trust and Bonavista Petroleum Ltd. were merged into the Corporation. Unitholders
of the Trust received one common share of the Corporation for each trust unit held, in addition, exchangeable shareholders of
Bonavista Petroleum Ltd. received 2.40917 exchangeable shares of Bonavista for each exchangeable share held. The Board of
Directors and senior management of the Trust continued as the Board of Directors and senior management of the Corporation.
In connection with the Arrangement, Bonavista assumed all of the obligations of the Trust in respect of the trust unit rights incentive
plan (amended to the common share rights incentive plan) and the restricted trust unit incentive plan (amended to the restricted
common share incentive plan). The Arrangement did not result in the acceleration of vesting of any such awards. Upon vesting,
holders of these rights are entitled to receive common shares on the same terms and conditions that existed prior to the Arrangement.
No new incentive awards will be granted in the amended plans. The stock option plan and restricted share award incentive plan of
Bonavista were established for new stock options and incentive rights under the Corporation. These plans are functionally similar to
their predecessor plans. The incentive plans are further outlined in note 9 of the notes to the consolidated financial statements of the
Corporation.
The Arrangement has been accounted for as a continuity of interests and accordingly, the consolidated financial statements for
periods prior to the effective date of the Arrangement reflect the financial position, income and cash flows as if the Corporation had
always carried on the business formerly conducted by the Trust. In these and future consolidated financial statements, Bonavista will
refer to “common shares”, “shareholders”, “dividends” and “ per share” which were formerly referred to as “trust units”, “unitholders”,
“distributions” and “per unit” under the trust structure. Comparative amounts in these and future consolidated financial statements will
reflect the history of the Trust.
1. Significant accounting policies:
As determination of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of these
consolidated financial statements requires the use of estimates and assumptions, which have been made using careful
judgement. In particular, the amounts recorded for depreciation, depletion and accretion of the oil and natural gas properties and
for asset retirement obligations are based on estimates of reserves and future costs. By their nature, these estimates, and those
related to future cash flows used to assess impairment, are subject to change and the impact on the financial statements of future
periods could be material. In the opinion of management, these consolidated financial statements have been properly prepared
within reasonable limits of materiality and within the framework of the significant accounting policies summarized below:
a) Principles of consolidation:
The consolidated financial statements include the accounts of the Corporation and its wholly-owned subsidiaries and
proportionate share of its partnerships. All inter-entity transactions have been eliminated.
b) Oil and natural gas properties and equipment:
The Corporation follows the full cost method of accounting, whereby all costs associated with the exploration for and
development of oil and natural gas reserves are capitalized in cost centres on a country-by-country basis. Such costs include
land and property acquisitions, geological and geophysical activities, drilling, well equipment and facilities. Gains or losses
are not recognized upon disposition of oil and natural gas properties unless crediting the proceeds against accumulated costs
would result in a change in the rate of depletion by 20% or more.
Costs capitalized in the cost centres, including well equipment, together with estimated future capital costs associated with
proved reserves, are depreciated and depleted using the unit-of-production method which is based on gross production and
estimated proved oil and natural gas reserves as determined by independent engineers. The cost of unproven properties is
excluded from the depreciation and depletion base. For purposes of the depreciation and depletion calculations, oil and
natural gas reserves are converted to a common unit of measure on the basis of their relative energy content, being six
thousand cubic feet of natural gas for one barrel of oil. Facilities are depreciated using the declining balance method over
their useful lives, which range from 12 to 15 years.
Oil and natural gas properties and equipment are evaluated in each reporting period to determine whether the carrying
amount in a cost centre is recoverable and does not exceed the fair value of the properties in the cost centre. The carrying
amounts are assessed to be recoverable when the sum of the undiscounted future cash flows expected from the production
of proved reserves, the lower of cost and market of unproved properties and the cost of major development projects exceeds
the carrying amount of the cost centre. When the carrying amount is not assessed to be recoverable, an impairment loss is
recognized to the extent that the carrying amount of the cost centre exceeds the sum of the discounted cash flows expected
from the production of proved and probable reserves, the lower of cost and market of unproved properties and the cost of
major development projects of the cost centre. The cash flows are estimated using expected future product prices and costs,
and are discounted using a risk-free interest rate.
c) Joint operations:
A portion of Bonavista’s oil and natural gas operations are conducted jointly with others. Accordingly, the consolidated
financial statements reflect only Bonavista’s proportionate interest in such activities.
d) Goodwill:
Goodwill is tested for impairment on an annual basis in the fourth quarter of each year. If indications of impairment are
present, a loss would be charged to net income for the amount that the carrying value of goodwill exceeds its fair value.
e) Asset retirement obligations:
Bonavista records a liability for the fair value of legal obligations associated with the retirement of long-lived tangible assets in
the period in which they are incurred, normally when the asset is purchased or developed. On recognition of the liability there
is a corresponding increase in the carrying amount of the related asset known as the asset retirement cost, which is depleted
on a unit-of-production basis over the life of the reserves. The liability is adjusted each reporting period to reflect the passage
of time, with the accretion charged to earnings, and for revisions to the estimated future cash flows. Actual costs incurred
upon settlement of the obligations are charged against the liability.
f) Revenue recognition:
Revenues from the sale of oil and natural gas are recorded when title passes to an external party.
g) Financial instruments:
i) A financial instrument is any contract that gives rise to a financial asset of one entity and a financial liability or equity
instrument to another entity. Upon initial recognition, all financial instruments, including all derivatives, are recognized on
the balance sheet at fair value. Subsequent measurement is then based on the financial instruments being classified into
one of five categories: held for trading, held to maturity, loans and receivables, available for sale and other liabilities. The
Corporation has designated its cash and cash equivalents and investments, other than equity investments, as held for
trading which are measured at fair value. Accounts receivable are classified as loans and receivables which are measured
at amortized cost. Accounts payable and accrued liabilities, distributions payable, and long-term debt are classified as
other liabilities which are measured at amortized cost, which is determined using the effective interest rate method. The
convertible debentures are classified as debt on the balance sheet with a portion of the proceeds allocated to equity. The
debt component has been measured at amortized cost.
ii) The Corporation is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates and
interest rates in the normal course of operations. A variety of derivative instruments may be used by the Corporation to
reduce its exposure to fluctuations in commodity prices, foreign exchange rates, and interest rates. The Corporation does
not use these derivative instruments for trading or speculative purposes. The Corporation considers all of these
transactions to be economic hedges; however, the majority of the Corporation’s contracts do not qualify or have not been
designated as hedges for accounting purposes. As a result, all derivative contracts are classified as held for trading and
are recorded on the balance sheet at fair value, with changes in the fair value recognized in net income, unless specific
hedge criteria are met. The fair values of these derivative instruments are based on an estimate of the amounts that would
have been received or paid to settle these instruments prior to maturity given future market prices and other relevant
factors. Proceeds and costs realized from holding the derivative contracts are recognized in net income at the time each
transaction under a contract is settled. The Corporation has elected to account for its 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 on an accrual basis rather than as non-
financial derivatives. The Corporation nets all transaction costs incurred, in relation to the acquisition of a financial asset
or liability, against the related financial asset or liability. In accordance with this policy convertible debentures are recorded
net of issue costs and long-term debt is presented net of deferred interest payments, with interest recognized in net
income on an effective interest basis.
h) Share-based compensation:
Bonavista has established long-term incentive plans for employees which are described in note 9. These plans include a
stock option plan and the restricted share award incentive plans, in addition to the amended plans of the Trust; the common
share rights incentive plan (formerly the trust unit right incentive plan) and the restricted common share incentive plan
(formerly the restricted trust unit incentive plan).
i) Stock Option Plan and Common Share Rights Incentive Plan:
The equity incentive plans for employees do not involve the direct award of common shares, or call for the settlement in
cash or other assets. Bonavista uses the fair value method for valuing these incentive rights. Under this method, the
compensation cost attributable to the share rights granted is measured at fair value at the grant date and expensed over
the vesting period with a corresponding increase to contributed surplus. Upon the exercise of the share rights,
consideration received together with the amount previously recognized in contributed surplus is recorded as an increase
to Shareholders’ equity.
ii) Restricted Share Awards Plan and Restricted Common Shares Incentive Plan:
Vesting arrangements on these awards are within the discretion of our board of directors, but all awards will vest within
three years from the date of grant. On the vesting date, the holder will receive equivalent common shares for each share
award, including dividends made on the shares from the date of the grant to and including the vesting date, net of
statutory withholding tax. Common shares may be issued from treasury or purchased on the open market. The
compensation cost attributable to these restricted awards is measured at fair value at the grant date and expensed to
contributed surplus. Upon the vesting of the restricted shares, the amount previously recognized in contributed surplus is
recorded as an increase in Shareholders’ equity.
i)
Income taxes:
Bonavista follows the asset and liability method of accounting for income taxes. Under this method, income tax assets and
liabilities are recognized for the estimated tax consequences attributable to differences between the amounts reported in the
financial statements of Bonavista and their respective tax base, using substantively enacted future income tax rates. The
effect of a change in income tax rates on future tax assets and liabilities is recognized in income in the period in which the
change occurs, provided that the income tax rates are substantively enacted. Temporary differences arising on acquisitions
result in the recording of future income tax assets and liabilities.
j) Per share amounts:
Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common
shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of
the Stock Option and Common Share Rights Incentive Plans.
2. Future accounting changes:
International Financial Reporting Standards (“IFRS”)
In October 2009, the Accounting Standards Board issued a third and final IFRS Omnibus Exposure Draft confirming that publicly
accountable enterprises will be required to apply IFRS, in full and without modification, for all financial periods beginning
January 1, 2011. The transition to IFRS at January 1, 2011 requires the restatement, for comparative purposes, of amounts
reported by Bonavista for the year ended December 31, 2010, including the opening balance sheet as at January 1, 2010.
3. Business relationships:
Bonavista and NuVista are considered related as two directors of NuVista, one of whom is NuVista’s chairman, are directors and
officers of Bonavista and a director of NuVista is also an officer of Bonavista.
For the year ended December 31, 2010, no management fees, other than standard industry overhead recoveries, were charged
by NuVista for our jointly owned partnership (2009 - $1.2 million). As at December 31, 2010, the amount payable to NuVista was
$134,000 (2009 - $343,000).
On February 2, 2011, Bonavista completed the rationalization of its partnership interest in NuVista Energy in exchange for
working interests in certain of NuVista Energy’s oil and natural gas properties. NuVista Energy was a general partnership held
with NuVista Energy Ltd. of which Bonavista Petroleum had a 24.22% beneficial interest.
4. Asset retirement obligations:
Bonavista’s asset retirement obligations result from net ownership interests in oil and natural gas assets including well sites,
gathering systems and processing facilities. The Corporation estimates the total undiscounted amount of expenditures required to
settle its asset retirement obligations is approximately $776.0 million (2009 - $753.5 million) which will be incurred over the next
50 years. The majority of the costs will be incurred between 2012 and 2039. A credit-adjusted risk-free rate of 7.5%
(2009 - 7.5%) and an inflation rate of 2% (2009 - 2%) were used to calculate the fair value of the asset retirement obligations. A
reconciliation of the asset retirement obligations is provided below:
(thousands)
Balance, beginning of year
Accretion expense
Liabilities incurred
Liabilities acquired
Liabilities settled
Change in estimate
Balance, end of year
5. Property acquisition:
Years
ended December 31,
2010
2009
$ 160,314
$ 127,467
11,741
3,369
6,820
(15,831)
2,010
10,033
3,195
31,234
(12,036)
421
$ 168,423
$ 160,314
On May 31, 2010 the Corporation acquired certain long-life natural gas weighted properties located in west central Alberta for a
cash purchase price of approximately $230.4 million.
6. Oil and natural gas properties and equipment:
December 31, 2010
(thousands)
Oil and natural gas properties
Facilities
Office equipment
December 31, 2009
(thousands)
Oil and natural gas properties
Facilities
Office equipment
Cost
$
$
4,163,248
929,442
9,796
5,102,486
Cost
Accumulated
depreciation and
depletion
$
$
1,726,779
221,671
6,031
1,954,481
Accumulated
depreciation and
depletion
$
$
3,667,533
842,307
8,378
4,518,218
$
$
1,423,169
183,886
5,090
1,612,145
Net book value
$ 2,436,469
707,771
3,765
$ 3,148,005
Net book value
$ 2,244,364
658,421
3,288
$ 2,906,073
Unproved property costs of $219.6 million as at December 31, 2010 (2009 - $179.7 million) were excluded from the depreciation
and depletion calculation. Future development costs of $759.0 million as at December 31, 2010 (2009 - $587.0 million) were
included in the depreciation and depletion calculation.
Bonavista has calculated the ceiling test as of December 31, 2010. Based on the calculation, the present value of future net
revenues from the Corporation’s proved reserves exceeds the carrying value of Bonavista’s oil and natural gas properties and
equipment at December 31, 2010. The benchmark reference prices, as provided by our independent engineering consultants,
used in the calculation and adjusted for commodity differentials specific to Bonavista are as follows:
Benchmark Reference Price Forecasts:
Year
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
Remainder (1)
(1) Escalated at 2% per year thereafter
7. Long-term debt:
(thousands)
Bank credit facility
Senior unsecured notes
Balance, end of year
a) Bank credit facility:
WTI Oil
(US$/bbl)
88.00
89.00
90.00
92.00
95.17
97.55
100.26
102.74
105.45
107.56
2.0%
AECO Gas
(Cdn$/mmbtu)
4.16
4.74
5.31
5.77
6.22
6.53
6.76
6.90
7.06
7.21
2.0%
USD/CAD
Exchange Rates
0.98
0.98
0.98
0.98
0.98
0.98
0.98
0.98
0.98
0.98
0.98
December 31,
2010
December 31,
2009
$ 555,348
396,095
$ 951,443
$ 832,138
-
$ 832,138
On September 10, 2010, Bonavista combined and renewed its bank credit facilities into a single facility of $1.4 billion provided
by a syndicate of 12 domestic and international banks with a maturity date of September 10, 2013. This facility is an
unsecured, covenant-based, extendible revolving facility and includes a $50 million working capital facility. This 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. This facility is a
three year revolving credit and may, at the request of the Corporation with the consent of the lenders, be extended on an
annual basis. There is an accordion feature providing that at anytime during the term, on participation of any existing or
additional lenders, the Corporation can increase the facility by $250 million. On March 3, 2011, Bonavista elected to reduce
the committed amount of its bank credit facility by $400 million from $1.4 billion to $1.0 billion.
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 and accretion; (ii) consolidated total debt will not exceed three and one
half times consolidated net income before unrealized gains and losses on financial instrument contracts and marketable
securities, interest, taxes and depreciation, depletion and accretion; and (iii) consolidated senior debt borrowing will not
exceed one-half of consolidated total debt plus consolidated shareholders’ 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:
In the second quarter of 2010, 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. On June 4, 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. Under the terms of the master shelf agreement, Bonavista has
provided similar significant covenants that exist under the bank credit facility.
c) Senior unsecured notes not subject to the master shelf agreement:
On November 2, 2010, Bonavista issued the following senior unsecured notes by way of a private placement. The significant
covenants of the senior unsecured notes are the same as those 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
Principal
CDN $50.0 million
US $90.0 million
US $160.0 million
US $50.0 million
Coupon Rate
3.79%
3.66%
4.37%
4.47%
Maturity Date
November 2, 2015
November 2, 2017
November 2, 2020
November 2, 2022
for
Financing expenses
long-term debt of $27.0 million
(2009 - $11.2 million) and convertible debentures of $1.3 million (2009 - $2.8 million). For the year ended December 31, 2010,
Bonavista paid cash interest of $24.6 million (2009 - $14.4 million). Our effective interest rate for period ending
December 31, 2010 was approximately 4.3% (2009 – 1.5%).
the year ended December 31, 2010
interest on
include
8. Convertible debentures:
On June 30, 2010, the 6.75% convertible debentures with a conversion price of $29.00 per trust unit matured and were cash
settled. The debt component of the debentures has been recorded net of the fair value of the conversion feature and issue costs.
The fair value of the conversion feature of the debentures included in shareholders’ equity at the date of issue was $2.8 million.
The issue costs are amortized to net income over the term of the obligation. The debt portion is accreted over the term of the
obligation to the principal value on maturity with a corresponding charge to net income. The following table sets out the
convertible debenture activities to December 31, 2010:
(thousands)
Balance, December 31, 2008
Accretion
Issue expenses related to conversions to trust units
Amortization of issue expenses
Repayment of convertible debentures on maturity
Conversion to trust units
Balance, December 31, 2009
Accretion
Amortization of issue expenses
Repayment of convertible debentures on maturity
Balance, December 31, 2010
Debt
Component
Equity
Component
$
$
$
43,711
452
2
525
(6,586)
(11)
(11)
38,093
285
189
(38,567)
-
$
$
$
933
-
-
-
(123)
(2)
(2)
808
-
-
(808)
-
9. Shareholders’ and Unitholders’ equity:
On December 31, 2010, pursuant to the Arrangement, all outstanding trust units were exchanged for common shares of the
Corporation on a one for one basis and holders of exchangeable shares of Bonavista Petroleum Ltd. received 2.40917
exchangeable shares of Bonavista for each exchangeable share held.
a) Authorized:
Unlimited number of voting common shares.
b)
Issued and outstanding:
(i) Trust units:
(thousands)
Balance, December 31, 2008
Issued for cash
Issued on conversion of convertible debentures
Issued on conversion of exchangeable shares
Issued upon exercise of trust unit incentive rights
Conversion of restricted trust units
Issue costs, related to debenture conversions
Issue costs, net of future tax benefit
Adjustment to equity component of debenture on conversion
Unit-based compensation
Balance, December 31, 2009
Issued for cash
Issued on property acquisition
Issued on conversion of exchangeable shares
Issued upon exercise of trust unit incentive rights
Conversion of restricted trust units
Issue costs, net of future tax benefit
Unit-based compensation
Exchanged pursuant to the Arrangement
Balance, December 31, 2010
(ii) Common shares:
(thousands)
Balance, December 31, 2009
Issued pursuant to the Arrangement
Balance, December 31, 2010
(iii) Contributed surplus:
(thousands)
Balance, December 31, 2008
Unit-based compensation expense
Unit-based compensation capitalized
Exercise of trust unit incentive rights and conversion of restricted trust units
Adjustment to equity component of debenture on repayment
Balance, December 31, 2009
Unit-based compensation expense
Unit-based compensation capitalized
Exercise of trust unit incentive rights and conversion of restricted trust units
Adjustment to equity component of debenture on repayment
Balance, December 31, 2010
Number of
Units
95,770
25,000
1
3,380
335
118
-
-
-
-
124,604
7,500
28
741
1,021
81
-
-
(133,975)
-
Number of
Shares
-
133,975
133,975
Amount
$ 1,099,835
421,250
11
10,193
4,478
-
(2)
(16,218)
2
10,942
$ 1,530,491
177,000
675
2,009
20,395
-
(6,986)
13,493
(1,737,077)
$
-
Amount
$
-
1,737,077
$ 1,737,077
Amount
$
10,687
11,386
2,065
(10,942)
123
13,319
11,584
2,074
(13,493)
808
$
14,292
(iv) Exchangeable shares:
Pursuant to the Arrangement, 9.4 million exchangeable shares of Bonavista Petroleum Ltd. were exchanged for
exchangeable shares of Bonavista based on the exchange ratio of 2.40917 resulting in 22.6 million exchangeable shares
being authorized and issued. The exchangeable shares of Bonavista are exchangeable into common shares of the
Corporation 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.
(thousands)
Balance, beginning of year
Exchanged for trust units
Exchangeable shares issued pursuant to the Arrangement
Balance, end of year
Exchange ratio, end of year
Shares issuable on exchange
Years ended December 31,
2010
2009
Number
Amount
Number
Amount
9,707
(329)
13,215
$ 59,295
(2,009)
-
11,375
(1,668)
-
$ 69,488
(10,193)
-
22,593
$ 57,286
9,707
$ 59,295
1.00000
-
2.21352
-
22,593
$ 57,286
21,486
$ 59,295
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 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.
c) Stock option and common share rights incentive plan:
In conjunction with the Arrangement, 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. The amended plan will remain in place until such time
as all rights granted have been exercised or expired. All new rights granted after December 31, 2010 will be granted under
the stock option plan. As at December 31, 2010, there were no stock options granted under the stock option plan.
The number of common shares under all long-term incentive plans shall be limited to 8% of the aggregate number of issued
and outstanding common shares of the Corporation. The option exercise prices are equal to the weighted average trading
price of the five trading days preceding the date of the grant. The incentive rights granted under the stock option plan vest
over a three year period and expire three years after each vesting date, whereas rights granted under the amended common
share rights incentive plan vest over a four year period and expire two years after each vesting date.
The following tables summarize the common share incentive rights outstanding and exercisable under the plan at
December 31, 2010:
Balance, December 31, 2008
Granted
Exercised
Expired and forfeited
Reduction in exercise price
Balance, December 31, 2009
Granted
Exercised
Expired and forfeited
Reduction in exercise price
Balance, December 31, 2010
Exercisable, December 31, 2010
Number of Common
Share Incentive
Rights
Weighted Average
Exercise
Price
3,208,795
1,616,820
(335,410)
(673,963)
-
3,816,242
1,563,840
(1,021,017)
(402,337)
-
3,956,728
952,368
$
25.88
16.57
(13.35)
(22.62)
(1.80)
21.28
23.13
(19.93)
(20.86)
(1.85)
$
$
20.28
20.98
Range of
exercise
prices
$ 12.35 – 20.69
20.70 – 22.68
22.69 – 35.99
$ 12.35 – 35.99
Common Share Incentive
Rights Outstanding
Common Share Incentive
Rights Exercisable
Number
outstanding
at year-end
1,316,118
1,202,910
1,437,700
3,956,728
Weighted
average
remaining
contractual
life
Weighted
average
exercise
price
Number
exercisable at
year-end
Weighted
average
exercise
price
2.7
2.6
3.1
2.8
$
13.13
21.24
26.02
$
20.28
361,433
280,280
310,655
952,368
$
$
12.96
21.26
30.05
20.98
The Corporation uses the fair value based method for the determination of the share-based compensation costs. The fair
value of each common share incentive right granted was estimated on the date of grant using the modified Black-Scholes
option-pricing model. In the pricing model, the risk free interest was 3.5% (2009 - 3.5%); average volatility of 33%
(2009 - 66%); a forfeiture rate of 10% (2009 - 10%) and an expected life of 4.5 years. The fair value of the options granted in
2010 average $7.68 (2009 - $9.76) per common share incentive right.
d) Restricted share award incentive plan and restricted common share incentive plan:
In conjunction with the Arrangement, the restricted share award incentive plan was established and the restricted common
share incentive plan (formerly the restricted trust unit incentive plan of the Trust) was amended. The amended plan provided
that all rights to acquire trust units became rights to acquire common shares. The amended plan will remain in place until
such time as all rights granted have vested or been cancelled. All new rights granted after December 31, 2010 will be
granted under the restricted share award plan. As at December 31, 2010 there were no share awards granted under the
restricted share award plan.
Vesting arrangements are within the discretion of our Board of Directors, but all awards will vest within three years from the
date of grant. On the vesting date, the holder will receive equivalent common shares for each share award, including
dividends made on the common shares from the date of the grant to and including the vesting date, net of statutory
withholding tax.
The
following
December 31, 2010:
table summarizes
the restricted common share
incentive rights outstanding under
the plan at
Balance, December 31, 2009
Granted
Forfeited
Conversion of restricted trust units
Balance, December 31, 2010
197,896
163,855
(31,938)
(81,261)
248,552
For the year ended December 31, 2010, Bonavista expensed $2.9 million (2009 – $2.2 million) relating to the restricted
common share incentive plan.
e) Per common share/trust unit amounts:
The following table summarizes the weighted average common shares/trust units, exchangeable shares and convertible
debentures used in calculating net income per common share/trust unit:
(thousands)
Trust units
Common shares
Exchangeable shares converted at the exchange ratio
Basic equivalent common shares/trust units
Convertible debentures
Common share incentive rights
Restricted common share incentive rights
Diluted equivalent common shares/trust units
Years ended December 31,
2010
-
131,075
22,019
153,094
656
832
250
154,832
2009
108,029
-
21,234
129,263
1,471
281
218
131,233
For the purposes of calculating net income per common share/unit on a diluted basis, the net income has been increased by
$1.8 million (2009 - $3.8 million) with respect to the accretion, amortization and interest expense on the convertible
debentures. For the year ended December 31, 2010 the Corporation excluded 3.1 million (2009 – 3.5 million) weighted
average common share incentive rights from the diluted share/unit calculation as they are anti-dilutive.
10.
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. This difference results from the following items:
Expected tax rate
(thousands)
Expected tax expense
Effect of change in tax rate
Distributions to unitholders
Other
Income tax recovery
The income tax recovery consists of:
Current
Future
Income tax recovery
Years ended December 31,
2009
2010
28.1%
29.2%
$
50,494
$
15,762
(3,620)
(70,911)
2,149
(21,888)
-
(21,888)
(21,888)
$
$
$
(8,949)
(63,701)
4,261
(52,627)
-
(52,627)
(52,627)
$
$
$
The significant components of future income tax assets and liabilities as at December 31 are:
(thousands)
Oil and natural gas properties
Facilities
Asset retirement obligations
Unrealized financial instruments contracts & Other
Future income taxes
For the years ended December 31, 2010 and 2009 Bonavista paid no tax installments.
11. Financial instruments:
2010
2009
$
124,809
30,775
(38,598)
212
$
146,547
36,135
(38,354)
(2,876)
$
117,198
$
141,452
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 companies 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 purchaser’s
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 events 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, 2010 Bonavista’s
receivables consisted of $77.7 million of receivables from oil and natural gas marketers which has substantially been
collected, subsequent to December 31, 2010, $26.1 million from joint venture partners of which $6.3 million has been
subsequently collected. As at December 31, 2010 the Corporation has $12.0 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, 2010 and did not provide for any doubtful accounts nor was it required to write-off any receivables during the
three months or year ended December 31, 2010.
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, financial instruments contracts, bank
debt and senior unsecured notes. Accounts payable consists of invoices payable to trade suppliers for office, field operating
activities, capital expenditures, and distributions payable. Bonavista processes invoices within a normal payment period.
Accounts payable and accrued liabilities have contractual maturities of less than one year. Financial instruments contracts
have contractual maturities of less than two years. Bonavista maintains a three year revolving credit facility, as outlined in
note 7, which may, at the request of the Corporation with the consent of the lenders, be extended on an annual basis. The
Corporation also has a series of senior unsecured notes outstanding, as outlined in note 7, which range in maturities from
June 4, 2016 to November 2, 2022. The Corporation also maintains and monitors a certain level of cash flow which is used
to partially finance all operating, investing and capital expenditures.
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 has attempted to
mitigate a portion of the commodity price risk through the use of various financial instrument contracts and physical delivery
sales contracts. The Corporation's policy is to enter into commodity price contracts when considered appropriate to a
maximum of 60% of net after royalty, forecasted production volumes.
i) Financial instrument contracts:
As at December 31, 2010, Bonavista entered into the following costless collars to sell natural gas and crude oil as
follows:
Volume
Average Price
Term
10,000
10,000
5,000
10,000
9,500
2,000
gjs/d CDN$5.13 - CDN$7.75 - AECO
gjs/d CDN$4.30 - CDN$5.55 - AECO
gjs/d CDN$4.50 - CDN$7.24 - AECO
gjs/d CDN$5.25 - CDN$7.20 - AECO
bbls/d CDN$79.58 - CDN$97.09 - WTI
bbls/d CDN$81.25 - CDN$100.01 - WTI
January 1, 2011 - March 31, 2011
April 1, 2011 - October 31, 2011
January 1, 2011 - October 31, 2011
January 1, 2011 - December 31, 2011
January 1, 2011 - December 31, 2011
January 1, 2012 - December 31, 2012
Subsequent to December 31, 2010, Bonavista entered into the following costless collar to sell natural gas and crude oil
as follows:
Volume
Average Price
Term
5,000
5,000
1,000
gjs/d CDN$3.50 - CDN$4.28 - AECO
gjs/d CDN$3.60 - CDN$4.60 - AECO
bbls/d CDN$87.50 - CDN$110.00 - WTI
April 1, 2011 - October 31, 2011
April 1, 2012 - October 31, 2012
January 1, 2012 - December 31, 2012
As at December 31, 2010, Bonavista entered into the following option contracts to manage its overall commodity
exposure:
Volume
Price
Contract
Term
28,000
10,000
1,000
500
1,000
gjs/d CDN$4.07
gjs/d CDN$6.45
bbls/d CDN$100.00
bbls/d USD$102.50
bbls/d CDN$105.00
Swap - AECO
Sold Call - AECO
Sold Call - WTI
Sold Call - WTI
Sold Call - WTI
April 1, 2011 - October 31, 2011
April 1, 2011 - October 31, 2011
January 1, 2011 - December 31, 2011
January 1, 2011 - December 31, 2011
January 1, 2012 - December 31, 2012
Subsequent to December 31, 2010, Bonavista entered into the following options contracts to manage its overall
commodity exposure:
Volume
Average Price
Contract
Term
5,000
500
gjs/d CDN$3.72
bbls/d USD$105.00
Swap - AECO
Sold Call - WTI
April 1, 2011 - October 31, 2011
February 1, 2011 - December 31, 2011
Financial instrument contracts are recorded on the consolidated balance sheet 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 operations,
comprehensive income and accumulated earnings. As at December 31, 2010, the fair market value recorded on the
consolidated balance sheet for these financial instrument contracts was a net liability of $5.8 million, compared to a net
liability of $9.5 million as at December 31, 2009. These financial instrument contracts had the following gains and losses
reflected in the consolidated statements of operations, comprehensive income and accumulated earnings:
Realized gains on financial instrument contracts
Unrealized gains (losses) on financial
instrument contracts
Years
ended December 31,
2009
2010
$ 16,080
$ 72,100
3,764
(85,746)
$ 19,844
$ (13,646)
Bonavista mitigates its risk associated with fluctuations in commodity prices by utilizing financial instrument contracts. A
$0.10 change in the price per thousand cubic feet of natural gas - AECO would have an impact of approximately
$900,000 on net income for those financial instrument contracts that were in place as at December 31, 2010. A $1.00
change in the price per barrel of oil – WTI would have an impact of approximately $2.2 million on net income for those
financial instrument contracts that were in place as at December 31, 2010.
iii) Physical purchase and sale contracts:
As at December 31, 2010, Bonavista entered into the following physical contracts to sell natural gas as follows:
Volume
10,000
10,000
7,000
Average Price
Term
gjs/d CDN$5.00 - CDN$7.34 - AECO
gjs/d CDN$5.13 - CDN$6.99 - AECO
gjs/d CDN$4.15 - AECO
January 1, 2011 - March 31, 2011
January 1, 2011 - December 31, 2011
April 1, 2011 - October 31, 2011
As at December 31, 2010, Bonavista entered into the following contracts to purchase electricity as follows:
Volume
Average Price
Term
6
1
mw/h CDN$50.37 - AESO
mw/h CDN$51.00 - AESO
January 1, 2011 - December 31, 2011
January 1, 2011 - December 31, 2012
Subsequent to December 31, 2010, Bonavista entered into the following physical contracts to sell natural gas as follows:
Volume
Average Price
Term
12,500
gjs/d CDN$3.84 - AECO
April 1, 2011 - October 31, 2011
Physical purchase and sale contracts are being accounted for as they are settled.
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.
A one cent change in the US/Canadian dollar exchange rate would have an impact of approximately $3.0 million on the
revaluation of the outstanding US denominated debt.
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 one percent it is estimated that Bonavista’s net income for the year ended December 31, 2010 would
decrease by $6.1 million.
Fair value of financial instruments:
The fair value of the financial instruments carried on Bonavista’s consolidated balance sheet is classified according to the
following hierarchy based on the amount of observable inputs used to value the 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 and convertible debentures have been classified as Level 1, financial instrument
contracts, bank debt and senior unsecured notes are classified as Level 2.
The fair value of financial instrument contracts is determined by the financial intermediary to extinguish all rights or obligations of
the financial instrument contracts. As at December 31, 2010, the fair market value of these financial instrument contracts was a
net liability of approximately $5.8 million (2009 - $9.5 million net liability).
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, 2010 is approximately $383.0 million (2009 – nil),
compared to a carrying amount of $396.1 million.
12. 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 our shareholders with stable dividends and rates of return.
The Corporation considers its capital structure to include working capital (excluding associated asset and liabilities from financial
instrument contracts and their related tax impact), 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, and senior unsecured notes, plus or minus net 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, 2010, Bonavista’s ratio of net debt to fourth quarter annualized funds from
operations was 2.0 to 1 (2009 - 1.6 to 1), which is within the acceptable range established by the Corporation.
In order 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 differential, royalties, operating costs and transportation
costs.
In order 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 shareholder's 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 7 of the consolidated financial statements.
There has been no change in Bonavista’s approach to capital management during the year ended December 31, 2010.
13. Commitments:
The following is a summary of Bonavista’s commitments as at December 31, 2010:
(thousands)
Long-term debt repayments (1)(3)
Interest payments (2)(3)
Transportation expenses
Office premises
Total
2011
2012
2013
2014
2015 and
thereafter
Payments Due by Period
$ 955,348
143,126
49,205
21,376
$
-
16,765
16,428
1,272
$
-
16,765
12,662
3,054
$ 555,348
16,765
9,521
3,054
$
-
16,765
5,612
3,054
$ 400,000
76,066
4,982
10,942
Total contractual obligations
$1,169,055
$ 34,465
$ 32,481
$ 584,688
$ 25,431
$ 491,990
(1)
(2)
(3)
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 2013.
Fixed interest payments on senior unsecured notes.
US dollars payments are converted using the exchange rate of $1.00 US/Canadian dollar.
CORPORATE INFORMATION
DIRECTORS
Keith A. MacPhail,
Chairman and CEO
Ian S. Brown,
Independent Businessman
Michael M. Kanovsky,
Sky Energy Corporation
Harry L. Knutson,
Nova Bancorp Inc.
Margaret A. McKenzie,
Range Royalty Management Ltd.
Ronald J. Poelzer,
Executive Vice President and Vice Chairman
Christopher P. Slubicki,
OPTI Canada Inc.
Walter C. Yeates,
Independent Businessman
OFFICERS
Keith A. MacPhail,
Chairman and CEO
Jason E. Skehar,
President and COO
Ronald J. Poelzer,
Executive Vice President and Vice Chairman
Glenn A. Hamilton,
Senior Vice President and CFO
Thomas J. Mullane,
Senior Vice President
Johannes H. Thiessen,
Senior Vice President
Scott H. Hanson,
Vice President, Production
Orest G. Humeniuk,
Vice President, Land
Bruce W. Jensen,
Vice President, Engineering
Dean M. Kobelka,
Vice President, Finance
Wayne E. Merkel,
Vice President, Exploration
Lynda J. Robinson,
Vice President, Human Resources and Administration
Hank R. Spence,
Vice President, Operations
Grant A. Zawalsky,
Corporate Secretary
FOR FURTHER INFORMATION CONTACT:
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
HSBC Bank Canada
Union Bank of California, N.A. (Canada Branch)
BNP Paribas (Canada)
Citibank, N.A. (Canadian Branch)
Sumitomo Mitsui Banking Corporation of Canada
Calgary, Alberta
ENGINEERING CONSULTANTS
GLJ Petroleum Consultants Ltd.
Ryder Scott Company Canada
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:
inv_rel@bonavistaenergy.com
Email:
www.bonavistaenergy.com
Website:
Keith A. MacPhail
Chairman and CEO
(403) 213-4315
or
Jason E. Skehar
President and COO
(403) 213-4363
or
Glenn A. Hamilton
Senior Vice President and CFO
(403) 213-4302