Highlights
Financial
($ thousands, except per unit)
Production revenues
Funds from operations (1)
Per unit (1) (2)
Distributions declared
Per unit
Percentage of funds from operations (1)
Net income
Per unit (2)
Adjusted net income (3)
Per unit (2)
Total assets
Long-term debt, including working capital deficiency(4)
Long-term debt, net of adjusted working capital (3)(4)
Unitholders’ equity
Capital expenditures:
Exploration and development
Acquisitions, net
ANNUAL REPORT
2009
Three months
ended December 31,
2008
2009
Years
ended December 31,
2008
2009
232,870
135,534
0.93
59,783
0.48
221,782
131,741
1.12
85,824
0.90
759,423
1,234,391
447,743
3.46
217,965
2.00
643,876
5.64
332,540
3.60
44%
65%
49%
52%
39,647
0.27
56,588
0.39
129,192
1.09
61,326
0.52
62,044
13,172
60,236
(105)
106,606
0.82
169,767
1.31
438,366
3.84
351,252
3.08
3,092,129
2,543,240
881,169
874,409
600,518
654,500
1,723,583
1,411,972
203,845
629,999
129,263
131,233
305,514
176,783
114,190
116,468
Weighted average outstanding equivalent trust units: (thousands) (2)
Basic
Diluted
146,019
148,035
118,065
119,905
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)
222
24,849
61,832
4.84
62.79
9.04
0.92
10.74
25.53
171
24,733
53,288
7.52
53.05
9.91
0.78
11.87
28.83
191
23,484
55,299
4.78
58.18
9.80
0.89
11.38
23.77
175
24,079
53,190
8.30
70.68
9.45
0.74
11.87
35.49
Highlights (cont’d)
Drilling (gross wells)
Natural gas
Oil
Average success rate
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 ($/boe):
Including changes in future development expenditures
Excluding changes in future development expenditures
Recycle ratio – proved and probable: (9)
Including changes in future development expenditures
Excluding changes in future development expenditures
December 31,
2009
2008
114
57
55
98%
732.2
71,722
193,750
1,039.2
99,419
272,617
46%
71%
29%
9,676
6,497
4,876
8.6
11.5
12.01
8.20
2.0
2.9
200
84
106
95%
462.6
65,044
142,150
613.7
88,817
191,095
59%
74%
26%
7,465
4,804
3,555
7.4
9.4
19.11
15.50
1.9
2.3
Trust Unit Trading Statistics
December 31,
2009
September 30,
2009
June 30,
2009
March 31,
2009
Three months ended
($ per unit, except volume)
High
Low
Close
Average Daily Volume - Units
NOTES:
24.00
19.86
22.30
21.89
16.64
20.42
19.95
14.84
18.04
18.93
11.74
15.30
314,701
566,846
231,577
306,298
(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 unit is calculated based on the weighted average number of units outstanding consistent with the
calculation of net income per unit.
(2) Basic per unit calculations include exchangeable shares which are convertible into trust units on certain terms and conditions.
(3) Amounts have been adjusted to exclude unrealized gains or losses on financial instruments and its related tax impact.
(4) Amounts exclude convertible debentures.
(5) Product prices include realized gains or losses on financial instruments.
(6) Cash costs equal the total of operating, general and administrative, and financing expenses.
(7) Operating netback equals production revenues including realized gains or losses on financial instruments, less royalties, transportation and operating expenses, calculated on a boe basis.
(8) Company interest reserves are working interest reserves prior to deduction of royalties and includes any royalty interests of the Company.
(9) Recycle ratio is calculated using operating netback per boe divided by finding, development and acquisitions costs per boe.
MESSAGE TO UNITHOLDERS
Bonavista Energy Trust (“Bonavista” or the “Trust”) is pleased to report to its unitholders (the “Unitholders”) its
consolidated financial and operating results for the year ended December 31, 2009. Throughout the year, Bonavista
continued its transition towards 2011 when the trust taxation rules change by upgrading our asset and opportunity
base while continuing to focus on optimizing production and revenues at the lowest possible cost. This consistent
effort has resulted in excellent operational and healthy financial results for the year and provides us with tremendous
confidence heading into 2010.
Bonavista's determination to position our organization for long term growth and profitability resulted in the completion
of a significant acquisition, at an opportune time, as signs of a recovering global economy began to emerge. On
August 20, 2009, Bonavista completed the acquisition of certain long-life, liquids rich natural gas weighted properties
located in its Western Region (the "Acquired Properties") for a cash purchase price of $698 million. In conjunction
with this acquisition, Bonavista completed equity and bank financings and a property disposition of our entire
southeast Saskatchewan assets. Details of all of these activities are as follows:
a) Acquisition - The acquisition is consistent with Bonavista's strategy of acquiring high
quality, long-life oil and natural gas assets with significant low-risk development
potential at opportunistic times in the cycle. The Acquired Properties are characterized
by high working interests and operatorship with extensive underutilized gathering and
processing infrastructure that result in low operating costs and accommodate efficient
production additions. This area is characterized as one of the most prolific multi-zone
regions in western Canada with a minimum of twelve different producing horizons
available to pursue. Both production and reserves have grown by approximately 25%
since acquiring the property. We have drilled 17 horizontal wells focusing primarily on
the Glauconite Hoadley trend and have identified 230 horizontal drilling locations within
numerous formations on the Acquired Properties.
b) Financing - The cash to close the acquisition was funded through a combination of
bank debt and an issuance of units. Bonavista issued 25 million units at a price of
$16.85 per unit for gross proceeds of approximately $421.3 million. In addition,
Bonavista increased the bank facilities by $400 million with the current members of its
banking syndicate having the same maturity and financial covenants of its existing bank
credit facility. This provides Bonavista with $1.4 billion of total bank credit facilities to
fund its ongoing capital programs.
c) Disposition - On August 31, 2009, Bonavista closed the disposition of its southeast
Saskatchewan assets to Legacy Oil and Gas Inc. (“Legacy”, formerly Glamis
Resources Ltd.), for cash consideration of $98.7 million and approximately 650,000
common shares of Legacy. The rationale for this disposition was as follows:
•
•
Bonavista received an attractive purchase price with equity upside in a high-growth
company;
The size of our southeastern Saskatchewan assets were less than 2% of our
overall operations and the area had become extremely competitive making it
difficult to expand operations significantly;
• Created an opportunity for Bonavista to focus both human and capital resources in
areas of greater presence and higher impact, generating superior returns over the
long term; and
•
The assets were better suited to a junior oil and natural gas company with plans to
aggressively accelerate capital investment to achieve significant growth objectives.
Further accomplishments for Bonavista in 2009 include:
• Operationally, production volumes averaged a record level of 55,299 boe per day during 2009, versus
53,190 boe per day in 2008, an increase of 4% year over year;
•
Increased proved and probable reserves by 43% to 272.6 mmboe while spending 186% of funds from
operations on all investment activities. The following attractive key reserve metrics were achieved:
(cid:190) Added 101.7 mmboe of proved and probable reserves, which replaced 500% of 2009 annual production;
(cid:190)
Improved the Trust’s proved and probable reserve life index to 11.5 years from 9.4 years in 2008 and
increased the Trust’s proven reserve life index to 8.6 years from 7.4 years in 2008;
(cid:190) Achieved attractive finding, development and acquisition costs, including changes in future development
expenditures, of $15.83 per boe on a proved basis ($11.62 per boe excluding changes in future
development expenditures) and $12.01 per boe on a proved and probable basis ($8.20 per boe excluding
changes in future development expenditures);
(cid:190) Attained a 2009 proved and probable operating netback recycle ratio of 2.0:1 as a result of this level of
finding, development and acquisition costs, including future development capital;
(cid:190)
Increased proven and probable future development capital by 121% to $710.0 million representing the
significant development and growth potential yet to be realized on our asset base;
• Maintained a conservative exploration and development program in 2009 investing $203.8 million compared to
$305.5 million in the same period of 2008 by drilling 114 wells with an overall 98% success rate. We spent an
additional $630.0 million, net of dispositions, on 20 synergistic property transactions within our core regions, one
of which was our transformational Hoadley acquisition. Collectively, our drilling inventory has grown by
approximately 40% with a significant enhancement in quality throughout 2009;
• Drilled 57 successful horizontal wells, on 13 different play types within our existing core regions. Sixteen of
these wells were drilled on our highly prospective Hoadley Glauconite trend in our Western Region. These
sixteen wells have collectively added over 9,000 boe per day in their first month of production at an average cost
of approximately $2.7 million per well. Since inception, we have drilled 27 horizontal Glauconite wells, of which
21 have been brought on production and six wells are awaiting completion and tie-in. Eleven of these wells
have been on production for greater than six months and their average rate over the first six months of
production is in excess of 300 boe per day per well. Bonavista believes that our Glauconite horizontal
development program continues to compete with the top tier resource developments in North America;
• Continued to participate at Crown land sales and freehold purchases, investing $20.4 million in land activity,
further enhancing our future drilling prospect inventory for several years. Bonavista has 1.3 million net acres of
undeveloped land holdings as at December 31, 2009;
• Generated funds from operations of $447.7 million ($3.46 per unit) for the year ended December 31, 2009 and
$135.5 million ($0.93 per unit) for the fourth quarter of 2009. Of the total funds from operations generated in the
respective periods, Bonavista distributed 49% of these funds for the year ended December 31, 2009 and 44% of
these funds in the fourth quarter to Unitholders with the remaining funds reinvested in the business to continue
growing our production base;
• Continued to record attractive levels of profitability for the fourth quarter and year ended December 31, 2009
with a return on equity of 13% and 11% respectively after adjusting net income to negate the impact of
unrealized gains or losses on financial instruments and its related tax impact, and recorded an adjusted net
income to funds from operations ratio of 42% for the fourth quarter of 2009 and 38% for the year ended
December 31, 2009;
•
Since inception as a Trust, Bonavista has delivered cumulative distributions of $1.7 billion or $21.11 per unit.
These cumulative distributions are in excess of our closing price of $16.00 per unit on the first trading day after
becoming an energy trust on July 2, 2003 and exceeds our initial market capitalization of $1.6 billion.
Strengths of Bonavista Energy Trust
Upon restructuring from an exploration and production corporation into an energy trust in July 2003, Bonavista employed
the same strategy that resulted in our tremendous success between 1997 and 2003. We have maintained a high level of
investment activity on our asset base, increasing current production by almost 80% since 2003. This activity stems from
the operational and technical focus of our Trust, the attention to detail, and the ability to continuously generate economic
prospects on our asset base 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 profitable results to our Unitholders. 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
low-risk drilling inventory. These activities have led to low cost reserve additions, lengthening of our reserve life index, a
significant increase in our drilling inventory and a growing production base. Our production base, including the recently
closed property transactions, is weighted 61% in favour of natural gas and 39% towards oil and liquids 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, the high working
interest asset base is predominantly operated by Bonavista, providing control over the pace of operations and ensuring
that operating and capital cost efficiencies are realized.
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. Despite its size, the recently
announced acquisition has been integrated quickly and efficiently into our base of operations due to the concentrated
nature of the assets and our existing presence in the area. Our management team and Board of Directors possess
extensive experience in the oil and natural gas business, navigating successfully through many different economic cycles
utilizing a proven strategy consisting of strict cost controls and prudent financial management. Directors, management
and employees also own approximately 16% of the Trust after giving effect to the recent financing, resulting in a close
alignment of interests with all Unitholders.
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 Trust’s (“Bonavista” or the “Trust”) audited consolidated financial statements and
MD&A for the year ended December 31, 2009. The following MD&A of the financial condition and results of operations
was prepared at, and is dated March 4, 2010. Our audited consolidated financial statements, Annual Report, and other
disclosure documents for 2009 will be available on or before March 31, 2010 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 and
prospects; (iii) anticipated production rates; (iv) expected royalty rate; (v) annualized debt to funds from operations; (vi) funds from operations, (vii)
anticipated operating and service costs; (viii) expected service agreement fees; (ix) expected finding and development costs; (x) expected on-stream
costs; (xi) our financial strength; (xii) incremental development opportunities, 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 cash-on-cash 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 unit is calculated based on the weighted average number of trust units outstanding consistent with the calculation of net income per unit.
Operating netbacks equal production revenue and realized gains or losses on financial instruments, 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. Management
uses these terms to analyze operating performance and leverage.
Operations - Bonavista's exploration and development program for the year ended December 31, 2009 led to the drilling
of 114 wells within our core regions with an overall success rate of 98%. This program resulted in 57 natural gas wells
and 55 oil wells. Bonavista continues to shift toward higher impact drilling opportunities focusing on unconventional
resource development through the use of horizontal drilling and multi-stage fracture stimulation technology. As a result,
50% of our wells drilled in 2009 were horizontal in nature. More specifically, operations in our Western region 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, along with our significant third quarter
acquisition, continue to enhance the predictability in our overall production base in addition to lengthening our reserve life
index ("RLI") to approximately 11.5 years.
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 Trust's reserves, 88% were evaluated by independent third party
engineers, GLJ Petroleum Consultants Ltd. ("GLJ") and Ryder Scott Company Canada in their reports dated
February 23, 2010 and February 11, 2010, respectively. The balance of approximately 12% 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 trust reserves as at December 31, 2009:
Natural Gas
(MMcf)
Trust Reserves(1):
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)
454,249
38,361
236,577
729,187
306,299
1,035,487
Light and
Medium Oil
(Mbbls)
Heavy Oil
(Mbbls)
Natural Gas
Liquids
(Mbbls)
Total
Reserves(2)
(Mboe)
25,185
1,009
6,031
32,225
10,386
42,611
5,436
1,865
302
7,604
3,098
10,701
18,774
1,346
11,708
31,828
14,192
46,019
125,103
10,613
57,471
193,187
78,725
271,913
8.6
11.5
(1)
(2)
(3)
Trust working interest reserves before royalties, boe (6:1), based on the February 23, 2010, GLJ reserve estimates based on forecast prices and costs as of January 1, 2010.
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 2010 production forecast.
Reserve Reconciliation:
Balance, December 31, 2008
Extensions and improved recovery
Technical revisions
Acquisitions
Dispositions
Economic factors
Production
Balance, December 31, 2009
Proved
(Mboe)
141,441
15,061
295
60,249
(3,517)
(190)
(20,152)
193,187
Probable
(Mboe)
48,799
6,738
(4,098)
29,421
(2,066)
(68)
-
78,726
Proved
and
Probable
Mboe)
190,240
21,799
(3,803)
89,670
(5,583)
(258)
(20,152)
271,913
Bonavista’s 2009 year-end proved reserves totalled 193.2 mmboe, a 37% increase compared to the 141.4 mmboe at the
year-end of 2008. Furthermore, Bonavista’s proved and probable reserves increased by 43% to 271.9 mmboe when
compared to the 190.2 mmboe at year-end 2008. The Trust had proved and probable negative reserve revisions of
3.8 mmboe which were primarily related to performance issues at four properties in British Columbia and three heavy oil
properties in Alberta.
Proved and Probable Finding, Development and Acquisition Costs (1):
Total capital expenditures ($ millions)
Total capital expenditures plus change
2009
833.84
2008
482.30
2007
366.36
in forecast future development costs ($ millions)
1,221.78
594.41
390.27
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)
190,240
21,799
84,087
(4,061)
(20,152)
178,575
23,861
10,373
(3,410)
(19,159)
173,959
15,798
8,211
(272)
(19,121)
271,913
190,240
178,575
12.01
15.68
19.11
16.77
15.91
14.78
(1)
(2)
The aggregate of the exploration, development and acquisition 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 reserves additions for that year.
Amounts are calculated including the change in future development costs.
Finding, development and acquisition costs in 2009, including changes in future capital expenditures, amounted to
$15.83 per boe ($11.62 per boe before changes in future capital expenditures) on a proved basis and $12.01 per boe
($8.20 per boe before changes in future capital expenditures) on a proved and probable basis.
Capital Efficiency:
Operating netback ($/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)
2009
23.77
8.20
2.9
12.01
2.0
2008
35.49
15.50
2.3
19.11
1.9
2007
28.77
14.94
1.9
15.91
1.8
Three-Year
Average
29.34
12.88
2.3
15.68
1.9
(1) Operating netback is calculated using production revenues including realized gains or losses on financial instruments 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 attractive recycle ratios of 2.0:1 for proved and probable reserves and 1.5:1 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 2.9:1 and the proved recycle ratio improved to 2.0:1.
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/Trust Unit Amounts and where noted)
Three months
ended December 31,
2008
2009
Years
ended December 31,
2008
2009
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
Funds from operations
per boe
per unit – basic
Unit-based compensation
per boe
Depreciation, depletion and accretion
per boe
Income taxes (reduction)
per boe
Net income
per boe
per unit – basic
Distributions declared
per unit
4.84
62.79
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
135,534
23.83
0.93
2,939
0.52
85,229
14.99
(15,825)
(2.78)
39,647
6.97
0.27
59,783
0.48
7.52
53.05
171
24,733
53,288
221,782
45.24
39,801
8.12
17.9%
48,603
9.91
9,589
1.96
3,825
0.78
5,761
1.18
131,741
26.87
1.12
4,694
0.96
69,000
14.07
23,324
4.76
129,192
26.35
1.09
85,824
0.90
4.78
58.18
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
447,743
22.18
3.46
11,386
0.56
295,296
14.63
(52,627)
(2.61)
106,606
5.28
0.82
217,965
2.00
8.30
70.68
175
24,079
53,190
1,234,391
63.41
239,967
12.33
19.4%
184,053
9.45
38,744
1.99
14,410
0.74
32,535
1.67
643,876
33.07
5.64
11,049
0.57
266,271
13.68
49,451
2.54
438,366
22.52
3.84
332,540
3.60
Production - For the year ended December 31, 2009, production increased 4% to 55,299 boe per day when compared
to 53,190 boe per day for the same period a year ago. Natural gas production increased 9% to 191 mmcf per day in
2009 from 175 mmcf per day for the same period a year ago, while total oil and liquids production decreased 2% to
23,484 bbls per day in 2009 from 24,079 bbls per day for the same period in 2008. For the fourth quarter of 2009,
production increased 16% to a record 61,832 boe per day when compared to 53,288 boe per day for the same period a
year ago. Natural gas production increased 30% to 222 mmcf per day in the fourth quarter of 2009 from 171 mmcf per
day for the same period a year ago, while total oil and liquids production increased slightly to 24,849 bbls per day in the
fourth quarter of 2009 from 24,733 bbls per day for the same period in 2008.
The following table highlights Bonavista's production by product for the three months and year 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,
2008
2009
Year
ended December 31,
2008
2009
222
171
191
175
19,864
4,985
24,849
61,832
18,120
6,613
24,733
53,288
18,037
5,447
23,484
55,299
17,440
6,639
24,079
53,190
Bonavista's balanced commodity investment approach minimizes our dependence on any one product and has
generated consistent results during the year and in the quarter. Our current production is approximately 62,500 boe per
day consisting of 61% natural gas, 31% light and medium oil and 8% heavy oil.
Production revenues - Production revenues for the year ended December 31, 2009 decreased 38% to $759.4 million
when compared to $1,234.4 million for the same period a year ago, primarily due to lower average commodity prices.
For the year ended December 31, 2009, natural gas prices decreased 42% to $4.78 per mcf, when compared to
$8.30 per mcf realized in the same period in 2008. The average oil and liquids price also decreased 18% to
$58.18 per bbl for the year ended December 31, 2009 from $70.68 per bbl for the same period in 2008. Production
revenues for the fourth quarter of 2009 increased 5% to $232.9 million when compared to $221.8 million for the same
period a year ago, primarily due to higher production volumes. In the fourth quarter of 2009, natural gas prices
decreased 36% to $4.84 per mcf, when compared to $7.52 per mcf realized in the same period in 2008. The average oil
and liquids price increased 18% to $62.79 per bbl in the fourth quarter of 2009 from $53.05 per bbl for the same period in
2008.
The following table highlights Bonavista's realized commodity pricing for the three months and year ended December 31:
Natural gas ($/mcf):
Production revenues
Realized gains on financial instruments
Light and medium oil ($/bbl):
Production revenues
Realized gains (losses) on financial instruments
Heavy oil ($/bbl):
Production revenues
Realized gains (losses) on financial instruments
Three months
ended December 31,
2008
2009
Years
ended December 31,
2008
2009
$ 4.72
0.12
4.84
$ 7.30
0.22
7.52
$ 4.48
0.30
4.78
$ 8.29
0.01
8.30
58.35
3.70
62.05
65.16
0.54
$ 65.70
48.06
4.84
52.90
43.76
9.71
$ 53.47
51.67
7.22
58.89
53.74
2.08
$ 55.82
81.40
(9.70)
71.70
76.08
(8.07)
$ 68.01
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 and protect acquisition economics. 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, 2009, our risk management program on financial instruments 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 same period in 2008, our risk management program on financial
instruments resulted in a net gain of $40.5 million, consisting of a realized loss of $80.8 million and an unrealized gain of
$121.3 million. The realized loss of $80.8 million consisted of a $744,000 gain on natural gas commodity derivative
contracts and an $81.5 million loss on crude oil commodity derivative contracts. In the fourth quarter of 2009, our risk
management program on financial instruments 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. For the
same period in 2008, our risk management program on financial instruments resulted in a net gain of $112.0 million
consisting of a realized gain of $17.5 million and an unrealized gain of $94.5 million. The realized gain of $17.5 million
consisted of a $3.6 million gain on natural gas commodity derivative contracts and a $13.9 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. The Trust has
attempted to mitigate a portion of the commodity price risk through the use of various financial instruments and physical
delivery sales contracts.
i) Financial instruments:
As at December 31, 2009, the Trust has hedged by way of costless collars to sell natural gas and crude oil as
follows:
Volume
Average Price
Term
5,000 gjs/d
15,000 gjs/d
5,000 gjs/d
20,000 gjs/d
10,000 gjs/d
9,000 bbls/d
1,000 bbls/d
CDN$5.00 - CDN$6.50 - AECO
CDN$4.75 - CDN$6.45 - AECO
CDN$4.50 - CDN$5.50 - AECO
CDN$4.56 - CDN$6.12 - AECO
CDN$5.25 - CDN$7.20 - AECO
CDN$68.06 - CDN$92.83 - WTI
CDN$80.00 - CDN$95.25 - WTI
January 1, 2010 – March 31, 2010
April 1, 2010 - October 31, 2010
January 1, 2010 - March 31, 2010
January 1, 2010 - December 31, 2010
January 1, 2011 - December 31, 2011
January 1, 2010 - December 31, 2010
January 1, 2011 - December 31, 2011
As at December 31, 2009, the Trust has limited its downside exposure to natural gas prices by purchasing a put
option. The Trust has also hedged its exposure to electricity pricing by entering into a swap which determines a fixed
price paid throughout the term of the contract. These financial instruments are outlined below:
Volume
Price
Contract
Term
5,000 gjs/d
1 mw/h
CDN $4.50
CDN$55.00 Swap - AESO
Purchased Put - AECO
April 1, 2010 - October 31, 2010
January 1, 2010 - December 31, 2010
Financial instruments 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, 2009 the fair market value recorded on the
consolidated balance sheet for these financial instruments was a net liability of $9.5 million, compared to an asset of
$76.2 million in 2008. These financial instruments had the following gains and losses reflected in the consolidated
statements of operations, comprehensive income and accumulated earnings:
Realized gains (losses) on financial instruments
Unrealized gains (losses) on financial instruments
Years
ended December 31,
2008
2009
(80,806)
121,261
$
$ 72,100
(85,746)
Bonavista mitigates its risk associated with fluctuations in commodity prices by utilizing financial instruments. A
$0.10 change in the price per thousand cubic feet of natural gas @ AECO would have an impact of approximately
$2.7 million on net income for those financial instruments that were in place as at December 31, 2009. A $1.00
change in the price per barrel of oil - WTI would have an impact of approximately of $1.4 million on net income for
those financial instruments that were in place as at December 31, 2009.
$
(13,646)
$ 40,455
Subsequent to December 31, 2009 the Trust has hedged by way of costless collars to sell natural gas and crude oil
as follows:
Volume
Average Price
Term
5,000
gjs/d
10,000 gjs/d
gjs/d
10,000
5,000 gjs/d
1,000 bbls/d
1,000 bbls/d
1,500 bbls/d
CDN$4.50 - CDN$7.24 - AECO
CDN$4.50 - CDN$6.50 - AECO
CDN$5.00 - CDN$7.45 - AECO
CDN$5.00 - CDN$6.50 - AECO
CDN$75.00 - CDN$92.38 - WTI
CDN$75.00 - CDN$91.03 - WTI
CDN$80.00 - CDN$98.40 - WTI
ii) Physical purchase contracts:
March 1, 2010 - October 31, 2011
April 1, 2010 - October 31, 2010
November 1, 2010 - March 31, 2011
April 1, 2011 - October 31, 2011
January 1, 2010 - December 31, 2010
July 1, 2010 - September 30, 2010
January 1, 2011 - December 31, 2011
As at December 31, 2009, the Trust has entered into direct sale costless collars to sell natural gas as follows:
Volume
Average Price
Term
10,000 gjs/d
5,000 gjs/d
5,000 gjs/d
10,000 gjs/d
5,000 gjs/d
CDN$5.25 - CDN$6.53 - AECO
CDN$5.25 - CDN$7.00 - AECO
CDN$5.00 - CDN$6.60 - AECO
CDN$5.13 - CDN$6.99 - AECO
CDN$5.25 - CDN$8.18 - AECO
January 1, 2010 - March 31, 2010
April 1, 2010 - October 31, 2010
January 1, 2010 - December 31, 2010
January 1, 2011 - December 31, 2011
November 1, 2010 - March 31, 2011
As at December 31, 2009, the Trust has entered into physical swap contracts to sell natural gas and to purchase
electricity as follows:
Volume
Average Price
Term
5,000 gjs/d
4 mw/h
2 mw/h
CDN $5.06 - AECO
CDN$50.54 - AESO
CDN$55.03 - AESO
January 1, 2010 - December 31, 2010
January 1, 2010 - December 31, 2010
January 1, 2011 - December 31, 2011
Subsequent to December 31, 2009 the Trust has entered into direct sale costless collars to sell natural gas as
follows:
Volume
Average Price
Term
10,000 gjs/d
5,000 gjs/d
CDN$4.50 - CDN$6.11 - AECO
CDN$5.00 - CDN$7.10 - AECO
April 1, 2010 - October 31, 2010
November 1, 2010 - March 31, 2011
Physical purchase contracts are being accounted for as they are settled.
Royalties - For the year ended December 31, 2009, royalties decreased by 51% to $117.2 million from $240.0 million for
the same period a year ago, largely attributed to a decrease in commodity prices. In addition, royalties as a percentage
of revenues (including realized gains and losses on financial instruments) for the year ended 2009 decreased to 14.1%
compared to 20.8% in 2008 for similar reasons discussed above and the impact of realized gains on financial
instruments compared to realized losses on financial instruments in the comparable period of 2008. For the three
months ended December 31, 2009, royalties decreased 8.7% to $36.3 million from $39.8 million for the same period a
year ago, mainly due to a decrease in commodity prices. In addition, royalties as a percentage of revenue (including
realized gains and losses on financial instruments) for the fourth quarter of 2009 also decreased from 16.6% in 2008 to
15.0% in 2009, for the same reasons as discussed above.
The following table highlights Bonavista's royalties by product for the three months and year ended December 31:
Natural gas ($/mcf):
Royalties
% of revenues (1)
Light and medium oil ($/bbl):
Royalties
% of revenues (1)
Heavy oil ($/bbl):
Royalties
% of revenues (1)
(1) % of revenues include realized gains and losses on financial instruments
Three months
ended December 31,
2008
2009
Years
ended December 31,
2008
2009
0.51
10.5%
11.59
18.7%
10.54
16.0%
1.50
19.9%
6.76
12.8%
8.12
15.2%
0.59
12.3%
9.05
15.4%
8.47
15.2%
1.82
21.9%
13.82
19.3%
14.55
21.4%
On October 25, 2007, the Alberta Government announced the New Royalty Framework (“NRF”) which was subsequently
revised on April 10, 2008 to provide further clarification on the NRF as well as to introduce two new royalty programs
related to the development of deep oil and natural gas reserves. The NRF was legislated in November 2008 and took
effect on January 1, 2009. Subsequent to legislation of the NRF, the Government of Alberta introduced the Transitional
Royalty Plan (“TRP”) in response to the decrease in development activity in Alberta resulting from declining commodity
prices and the global economic downturn. The TRP offers reduced royalty rates for new wells drilled on or after
November 19, 2008 that meet certain depth requirements. An election must be filed on an individual well basis in order
to qualify for the TRP. The TRP is in place for a maximum of 5 years to December 31, 2013. All wells drilled between
2009 and 2013 that adopt the transitional rates will be required to shift to the NRF on January 1, 2014. On
March 3, 2009, the Alberta Government announced a further royalty incentive program consisting of a three-point
incentive program to stimulate new and continued economic activity in Alberta which includes a drilling royalty credit for
new conventional oil and natural gas wells and a new royalty incentive program. The net effect of these programs added
approximately $12.0 million of royalty and drilling credits in 2009. It is also expected that the Alberta Government will
release the findings of their Royalty Competiveness Review in the first quarter of 2010.
Operating expenses - Operating expenses for the year ended December 31, 2009 increased 7% to $197.8 million
compared to $184.1 million for the same period a year ago, mainly due to higher production volumes. Operating
expenses for the fourth quarter of 2009 increased 6% to $51.4 million compared to $48.6 million for the same period a
year ago, again largely due to increased production volumes offset somewhat by lower per boe operating expenses in the
period. In the last half of 2009, Bonavista experienced operating cost reductions in many areas of its operations however
operating expenses still rose slightly on a per boe basis increasing 4% for the year ended December 31, 2009 to
$9.80 per boe, from $9.45 per boe in the comparable period of 2008. However, for the three months ended December
31, 2009 operating expenses per unit of production decreased 9% to $9.04 per boe, from $9.91 per boe in the
comparable period of 2008. Bonavista anticipates that operating costs on a per boe basis will decrease in 2010 as
compared to 2009. The following table highlights Bonavista's operating expenses by product for the three months and
year ended December 31:
Natural gas ($/mcf)
Light and medium oil ($/bbl)
Heavy oil ($/bbl)
Total ($/boe)
Three months
ended December 31,
2008
2009
Year
ended December 31,
2008
2009
$ 1.29
10.05
14.44
$ 9.04
$ 1.44
10.38
14.07
$ 9.91
$ 1.41
10.66
14.94
$ 9.80
$ 1.35
10.07
13.69
$ 9.45
Transportation expenses - For the year ended December 31, 2009, transportation expenses decreased 5% to
$36.8 million ($1.82 per boe) when compared to $38.7 million ($1.99 per boe) for the same period in 2008. For the three
months ended December 31, 2009, transportation expenses decreased 2% to $9.4 million ($1.66 per boe) when
compared to $9.6 million ($1.96 per boe) for 2008. For the year ended December 31, 2009 transportation expenses by
product were $0.33 per mcf for natural gas, $0.92 per bbl for light and medium oil and $3.83 per bbl for heavy oil
compared to $0.38 per mcf for natural gas, $0.85 per bbl for light and medium oil and $3.64 per bbl for heavy oil for the
same period in 2008. Transportation expenses by product for the fourth quarter of 2009 were $0.30 per mcf for natural
gas, $0.94 per bbl for light and medium oil and $3.53 per bbl for heavy oil compared to $0.36 per mcf for natural gas,
$0.86 per bbl for light and medium oil and $4.05 per bbl for heavy oil for the same period in 2008.
General and administrative expenses - General and administrative expenses, after overhead recoveries, increased
24% to $17.9 million for the year ended December 31, 2009 from $14.4 million in the same period in 2008 and increased
37% to $5.2 million for the three months ended December 31, 2009 from $3.8 million in the same period in 2008. On a
per boe basis, general and administrative expenses increased 20% for the year ended December 31, 2009 to
$0.89 per boe from $0.74 per boe in the same period in 2008 and increased 18% for the three months ended December
31, 2009 to $0.92 per boe from $0.78 per boe in the same period in 2008. These increases are largely due to higher
costs of personnel required to manage our growing operations and the termination of general and administrative cost
recoveries under the services agreement with NuVista Energy Ltd. Our current level of general and administrative
expenses remains among the lowest in our sector.
In connection with its Trust Unit Incentive Rights and Restricted Trust Unit Plans, Bonavista recorded a unit-based
compensation charge of $2.9 million and $11.4 million for the three months and year ended December 31, 2009
respectively, compared to $4.7 million and $11.0 million for the same periods in 2008.
Financing expenses - Financing expenses, which include interest expense on long-term debt and convertible
debentures, decreased 57% to $14.0 million for the year ended December 31, 2009, from $32.5 million for the same
period in 2008 and on a per boe basis, decreased 58% to $0.70 per boe for the year ended December 31, 2009 from
$1.67 per boe for the same period in 2008. For the three months ended December 31, 2009 financing expenses
decreased 23% to $4.5 million from $5.8 million for the same period in 2008 and on a per boe basis, decreased 34% to
$0.78 per boe for the three months ended December 31, 2009 from $1.18 per boe for the same period in 2008. This
decrease is due largely to a declining interest rate environment. For the year ended December 31, 2009, Bonavista paid
cash interest of $14.4 million compared to $32.9 million for the same period in 2008. During the fourth quarter of 2009,
Bonavista paid cash interest of $5.1 million compared to $6.4 million in 2008. Bonavista's effective interest rate as at
December 31, 2009 was approximately 1.5% (2008 – 2%).
Depreciation, depletion and accretion expenses - Depreciation, depletion and accretion expenses increased 11% to
$295.3 million for the year ended December 31, 2009 from $266.3 million for the same period of 2008. For the three
months ended December 31, 2009, depreciation, depletion and accretion expenses increased by 24% to $85.2 million
from $69.0 million for the same period in 2008. These increases are due to higher costs of finding, developing and
acquiring reserves and a larger asset base in 2009. For the year ended December 31, 2009, the average cost increased
to $14.63 per boe from $13.68 per boe for the same period in 2008 and for the three months ended December 31, 2009,
the average cost increased to $14.99 per boe from $14.07 per boe for the same period a year ago.
Income taxes - For the year ended December 31, 2009, the reduction of income taxes was $52.6 million compared to a
provision of $49.5 million for the same period in 2008. For the three months ended December 31, 2009, the reduction of
income tax was $15.8 million compared to a provision of $23.3 million for the same period in 2008. The current year
losses
income
(2008 - $34 million gains) and $3.8 million (2008 - nil) related to the rate reduction in the provincial component of the
Specified Investment Flow-Through ("SIFT") tax rate enacted in the first quarter of 2009. Bonavista made no cash
payments on tax installments for either the three months or year ended December 31, 2009, or for the comparative
periods in 2008.
included approximately $22 million
risk management
to unrealized
reduction
related
tax
Funds from operations, net income and comprehensive income - For the year ended December 31, 2009, Bonavista
experienced a 30% decrease in funds from operations to $447.7 million ($3.46 per unit, basic) from $643.9 million
($5.64 per unit, basic) for the same period in 2008. For the three months ended December 31, 2009, Bonavista
experienced a 3% increase in funds from operations to $135.5 million ($0.93 per unit, basic) from $131.7 million
($1.12 per unit, basic) for the same period in 2008. Funds from operations decreased for the year ended
December 31, 2009 primarily due to lower commodity prices partially offset by the impact of realized gains on financial
instruments and slightly higher production volumes. For the three months ended December 31, 2009, funds from
operations increased largely due to increased production volumes offset by lower overall commodity prices. Net income
and comprehensive
to $106.6 million
($0.82 per unit, basic) from $438.4 million ($3.84 per unit, basic) for the same period in 2008. For the three months
ended December 31, 2009, net
to $39.6 million
($0.27 per unit, basic) from $129.2 million ($1.09 per unit, basic) for the same period in 2008.
the year ended December 31, 2009, decreased 76%
income and comprehensive
income decreased 69%
income
for
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,
2008
2009
Years
ended December 31,
2008
2009
$ 154,758
3,440
(22,664)
$ 141,448
5,061
(14,768)
$ 423,933
12,036
11,774
$ 678,228
15,229
(49,581)
Funds from operations
$ 135,534
$ 131,741
$ 447,743
$ 643,876
Capital expenditures - Capital expenditures for the year ended December 31, 2009 were $833.8 million, consisting of
$203.8 million spent on exploration and development activities and $630.0 million spent on property acquisitions, net of
dispositions. For the same period in 2008, capital expenditures were $482.3 million, consisting of $305.5 million on
exploration and development spending and $176.8 million on property acquisitions, net of dispositions. Capital
expenditures for the three months ended December 31, 2009 were $75.2 million, consisting of $62.0 million on
exploration and development spending and $13.2 million on property acquisitions, net of dispositions. For the same
period in 2008 capital expenditures were $60.1 million, consisting of $60.2 million on exploration and development
spending and $105,000 on net property dispositions. While we saw considerable downward movement in service costs
throughout 2009, we anticipate service costs to stabilize at current levels for 2010. This attractive level will allow
Bonavista to continue to generate attractive returns with its exploration and development program despite relatively weak
commodity prices.
The following table outlines capital expenditures by category for the years ended December 31, 2009 and 2008:
(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,
2009
2008
$
20,385
6,829
133,811
41,704
1,116
203,845
737,117
(107,118)
$
26,165
10,687
176,361
91,138
1,163
305,514
187,023
(10,240)
$
833,844
$
482,297
Liquidity and capital resources - As at December 31, 2009, long-term debt including working capital (excluding
unrealized losses on financial instruments, its related tax impact and convertible debentures) was $874.4 million with a
debt to fourth quarter 2009 annualized funds from operations ratio of 1.6:1. Bonavista has significant flexibility to finance
future expansions of its capital programs, through the use of its current funds generated from operations and our bank
loan facilities of $1.4 billion, of which $525.6 million is unused borrowing capability.
Bonavista has two bank loan facilities totalling $1.4 billion provided by a syndicate of 12 domestic and international
banks. Both facilities have a maturity date of August 10, 2011 and may, at the request of the Trust and with the consent
of the lenders be extended on an annual basis.
Under the terms of both credit facilities, the Trust 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 instruments 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 instruments 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 unitholders’ equity of the Trust, in all cases
calculated based on a rolling prior four quarters.
In 2010, Bonavista plans to invest between $300 and $330 million on its capital programs to expand its core regions.
The Trust intends on financing its 2010 capital program with a combination of funds from operations, and to the extent
required, its existing credit facility. Going forward, the Trust remains committed to the fundamental principle of
maintaining financial flexibility and the prudent use of debt.
Unitholders’ equity - As at December 31, 2009, Bonavista had 146.1 million equivalent trust units outstanding. This
includes 9.7 million exchangeable shares, which are exchangeable into 21.5 million trust units. The exchange ratio in
effect at December 31, 2009 for exchangeable shares was 2.21352:1. As at March 4, 2010, Bonavista had 146.5 million
equivalent trust units outstanding. This includes 9.5 million exchangeable shares, which are exchangeable into
21.3 million trust units. The exchange ratio in effect at March 4, 2010 for exchangeable shares was 2.24429:1. In
addition, Bonavista has 4.2 million trust unit incentive rights outstanding at March 4, 2010, with an average exercise price
of $25.65 per trust unit.
Contractual obligations - The following is a summary of the Trust’s contractual obligations and commitments as at
December 31, 2009:
(thousands)
Long-term debt repayments (1)
Convertible debentures (2)
Transportation expenses
Office premises
Total
2010
2011
2012
2013
2014 and
thereafter
Payments Due by Period
$ 832,138
38,567
51,417
1,708
$
-
38,567
16,114
1,412
$832,138
-
11,570
296
$
-
-
8,314
-
$
-
-
6,665
-
$
-
-
8,754
-
Total contractual obligations
$ 923,830
$ 56,093
$844,004
$ 8,314
$ 6,665
$ 8,754
(1)
(2)
Based on the existing terms of the revolving credit facility, the amounts owing under this facility are required to be paid in 2011. However, it is expected that the revolving credit facility will be
extended and no repayments will be required in the near term.
The Trust may at its option redeem the principal amount of, and premiums (if any) on the Debentures that have matured by either the issuance of trust units or the cash equivalent to the holders of
the Debentures.
Distributions - Bonavista's distribution policy is constantly monitored and is dependent upon its forecasted operations,
funds from operations, debt levels and capital expenditures. One of the main objectives of the Trust is to maintain
sustainability, which is defined as maintaining both production and reserves over an extended period of time with a
minimum amount of capital. This is accomplished by retaining sufficient funds from operations to replace the reserves
that have been produced. With these considerations, for the year ended December 31, 2009 the Trust declared
distributions of $218.0 million ($2.00 per unit) compared to $332.5 million ($3.60 per unit) in the same period in 2008.
For the three months ended December 31, 2009 the Trust declared distributions of $59.8 million ($0.48 per unit)
compared to $85.8 million ($0.90 per unit) in the same period in 2008. We continuously monitor all the factors
influencing our distribution rate and the necessity to adjust the monthly distribution in the future.
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 instruments and marketable securities,
fluctuations in future income taxes due to changes in tax rates and tax rules. 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 and year ended December 31, 2009, the non-cash charges amounted to $95.9 million and
$341.1 million respectively compared to $2.5 million and $205.5 million for the same periods in 2008. In instances where
distributions exceed net income, a portion of the cash distribution paid to Unitholders may be considered an economic
return of Unitholders' capital.
Distribution Analysis
(thousands)
Cash flow provided from operating activities
Net income
Distributions declared
Excess of cash flow provided from operating
activities over distributions declared
Excess (shortfall) of net income over distributions
declared
Three months
ended December 31,
Years
ended December 31,
2009
2008
2009
2008
$ 154,758
39,647
59,783
$ 141,448
129,192
85,824
$ 423,933
106,606
217,965
$ 678,228
438,366
332,540
94,975
55,624
205,968
345,688
(20,136)
43,368
(111,359)
105,826
Bonavista announces its distribution policy on a quarterly basis. Distributions are determined by the Board of Directors
and are dependent upon the commodity price environment, production levels, and the amount of capital expenditures to
be financed from funds from operations. Bonavista’s current monthly distribution rate is $0.16 per unit, down from
$0.20 per unit at the same time last year. For 2010, our objective is to distribute up to 50% of our funds from operations,
which allows us to withhold sufficient funds to finance capital expenditures required to maintain or modestly grow our
production base over a longer period of time. Our current distribution rate of $0.16 per unit per month will place us within
this targeted level for the year assuming current strip prices are realized.
Annual financial information - The following table highlights selected annual financial information for each of the three
years ended December 31, 2009, 2008 and 2007:
Years ended December 31,
(thousands, except per unit amounts)
Consolidated Statement of Operations Information:
Production revenues, net of royalties
Funds from operations
Per unit – basic
Per unit – diluted
Net income
Per unit – basic
Per unit – diluted
Consolidated Balance Sheet Information:
Total capital expenditures
Total assets
Working capital (deficiency)
Long-term debt
Unitholders’ equity
Distributions declared
2009
2008
2007
$ 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
$ 755,760
502,783
4.76
4.69
218,187
2.07
2.06
$ 366,356
2,242,057
(10,349)
712,654
1,060,967
307,401
Quarterly financial information - The following table highlights Bonavista’s performance for the eight quarterly periods
ending on March 31, 2008 to December 31, 2009:
December 31 September 30
June 30
March 31
December 31 September 30
June 30
March 31
2009
2008
($ thousands, except per unit amounts)
Production revenues
Net income
Net income per unit:
Basic
Diluted
232,870
39,647
180,977
33,339
166,430
661
179,146
32,959
221,782
129,192
354,667
207,594
361,555
29,282
296,387
72,298
0.27
0.27
0.25
0.25
0.01
0.01
0.28
0.28
1.09
1.09
1.77
1.75
0.26
0.26
0.67
0.67
Production revenues over the past eight quarters have fluctuated between a low of $166.4 million in the second quarter
of 2009 to a high of $361.6 million in the second quarter of 2008, largely due to the volatility of commodity prices. 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
$207.6 million in the third quarter of 2008. These fluctuations are primarily influenced by commodity prices, realized and
unrealized gains and losses on financial instruments and future income tax recoveries associated with the reduction in
corporate income tax rates. Net income decreased 69% in the fourth quarter of 2009 as compared to the fourth quarter
of 2008. The decrease in net income in the fourth quarter of 2009 is largely attributed to lower overall commodity prices
and the impact of the unrealized losses on financial instruments offset however by an increase in production volumes as
compared to the same period in 2008.
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 know to them by others within the Trust.
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, 2009. There were no material changes
to the internal controls over financial reporting during the year ended December 31, 2009.
the effectiveness of Bonavista’s
control over
financial
internal
Update on SIFT tax and corporate conversion - Bonavista is currently reviewing alternative legal structures for post
December 31, 2010. Although we believe a conversion back to a corporate structure is the most likely scenario when the
SIFT tax rules come into effect, we have not finalized this decision at this time. The form of legal structure and the timing
of such conversion are dependent on many factors such as the strength of commodity prices and equity markets,
operating performance, tax regulations and Bonavista’s continued success in developing its inventory of prospects. If
there is a conversion to a corporation, total shareholder return is still expected to have a component of both growth and
yield.
Update on financial reporting matters - On February 13, 2008, Canada’s Accounting standards Board confirmed
January 1, 2011 as the effective date for complete convergence of Canadian GAAP to International Financial Reporting
Standards (“IFRS”). There are significant differences that exist under the IFRS framework compared to Canadian GAAP
in the areas of accounting policy choices and increased disclosure requirements. In July 2009, the International
Accounting Standards Board (“IASB”) issued amendments to IFRS 1, “First Time Adoption of IFRS” allowing an entity that
used full cost accounting under its previous GAAP to elect, at its time of adoption, to measure exploration and evaluation
assets at the amount determined under the entity’s previous GAAP and to measure oil and natural gas assets in the
development or production phases by allocating the amount determined under the entity’s previous GAAP for those assets
to the underlying assets pro rata using reserve volumes or reserve values as of that date. Bonavista is currently planning
to adopt this exemption.
In 2009, Bonavista completed a preliminary analysis of the accounting differences between Canadian GAAP and IFRS.
The Trust then moved into the impact analysis and evaluation phase which focused on the determination of cash
generating units and accounting policy choices. There are currently numerous significant accounting differences between
our current accounting policies under Canadian GAAP and IFRS. We are currently in the process of evaluating the
impact these different accounting policy choices have on the results of operations, financial position and disclosures.
Once concluded the audit committee will review and approve all accounting policy choices as proposed by management.
Effective January 1, 2009, Bonavista adopted Canadian Institute of Chartered Accountants ("CICA") Section 3064,
“Goodwill and Intangible Assets”, which defines the criteria for the recognition of intangible assets. The adoption of this
standard did not impact the Trust's consolidated financial statements.
Effective December 31, 2009, Bonavista adopted CICA issued amendments to Section 3862, "Financial Instruments -
Disclosures". The amendments include enhanced disclosures relating to the fair value of financial instruments and
liquidity risk associated with financial instruments. The adoption of these amendments did not have a material impact on
our results of operations, financial position and disclosures. The impact of this amendment has been disclosed within
note 11 of the Notes to the Consolidated Financial Statements.
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 the Trust’s development plans. The effect of changes in proved oil and natural gas reserves on the
financial results and position of the Trust 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 the Trust'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 the business of the Trust. These risks are similar to those affecting
others in the conventional energy trust sector. The Trust’s financial position, results of operations and distributions to
Unitholders 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 distributions;
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 and the income trust sector;
9) potential risk of liability to Unitholders resident in jurisdictions where there is no statutory protection for
Unitholders from liabilities of the Trust;
10) continued participation of the Trust’s lenders;
11) counterparty risk with respect to non-performance by counterparties to financial derivative contracts; and
12) financial risk associated with domestic and international debt and equity markets.
The Trust 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 the Trust’s 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 navigate through our thirteenth year since restructuring Bonavista in 1997, and our seventh year since converting
to an energy trust, we continue to benefit from the same qualities that drove the success of Bonavista both as a
corporation and an energy trust. We continue to apply the same proven strategy and execute this strategy in a
disciplined and cost-effective manner, much the same way we did in 1997 when we started on our journey of creating
value for our investors. The foundation of this strategy is to actively pursue low to medium-risk drilling opportunities on
our extensive land base within geographically concentrated areas of operations. Even with a very active exploration and
development program over the past several years, the quality and quantity of our inventory of opportunities continues to
improve each and every year. Our consistent strategy also involves a component of strategic and timely acquisitions
where we can add value utilizing our own technical expertise. In the third quarter of 2009 we closed the most significant
acquisition in our history. This acquisition grew our prospect inventory by 25% to approximately 860 locations, adding
high quality and low cost drilling prospects to our previous healthy inventory of opportunities. This is truly a
transformational transaction for Bonavista and will lead to several years of drilling and tuck-in acquisition opportunities in
an area where we have established a dominant presence of operations. Our timely and prudent approach to capital
investments has been very effective in the past, and our attention to detail together with our steadfast commitment to
adding Unitholder value, will continue to provide the foundation for the future success of our organization. Today our
efficiency, productivity, and confidence remains among the strongest levels in our twelve year history.
As we approach the spring of 2010 we are continuing to monitor natural gas fundamentals very closely and remain
optimistic that the current North American oversupply situation will ultimately balance itself. A reduced amount of capital
expenditures being directed towards natural gas projects within North America is resulting in a slow and steady decline in
supply which, when coupled with stabilizing or modestly increasing industrial demand, should result in stabilizing or
improving natural gas prices throughout the year. With this in mind, Bonavista will continue to maintain maximum
flexibility with its capital spending program by directing capital to the most profitable opportunities. We have established a
capital spending program of between $300 and $330 million, which at this time, will be entirely directed toward our
exploration and development program. Approximately two-thirds of the expenditures will be devoted to our Western
Region development initiatives with the remaining one-third directed towards our Eastern and Northern Regions. In total
for 2010, we expect to drill between 120 and 130 wells, of which 60% to 70% will be high-impact horizontal wells focusing
on multi-stage stimulation within large tight reservoirs. This activity should lead to production levels averaging between
62,000 and 63,000 boe per day in 2010. As always, we will continue to closely monitor the economic climate together
with our drilling results and remain flexible to adjust the level of spending depending on the circumstances. In particular,
an unprecedented amount of Crown land and property acquisition opportunities are being brought to the market in 2010.
As a result, we are exercising extra diligence when considering these incremental investment opportunities. As in the
past, our objective will be to invest in those projects that will maximize value both in the short and long term.
We are extremely proud of what our team has accomplished over the past year and despite some short term commodity
weakness, our enthusiasm and confidence about our future is greater than it has ever been. We would like to thank our
employees for their significant effort and their continued perseverance as we position our company for the future.
Although we have endured some setbacks over the past couple of years, including the passage of federal legislation on
the taxation of distributions from certain publicly traded Canadian trusts, the introduction of the New Royalty Framework
by the Government of Alberta, and the volatile capital and commodity markets, Bonavista's commitment and value
creation process has not waivered. We remain confident that our operating philosophy works well in any environment.
Throughout many business cycles and changes in the business environment, Bonavista has converted adversity into
opportunity, pursued counter-cyclical strategies and has emerged an even stronger entity as a result of this approach.
Ultimately our legal structure may change back to a corporation in 2011, but our primary focus of executing a proven
strategy that has worked so well over twelve years will remain unchanged. 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 4, 2010
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 unitholders. The auditors have considered, for the
purposes of determining the nature, timing and extent of their audit procedures, the Trust’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 4, 2010
Calgary, Alberta
AUDITORS' REPORT TO THE UNITHOLDERS
We have audited the consolidated balance sheets of Bonavista Energy Trust as at December 31, 2009 and 2008 and the
consolidated statements of operations, comprehensive income and accumulated earnings and cash flows for the years
then ended. These financial statements are the responsibility of the Trust's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require
that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the
Trust as at December 31, 2009 and 2008 and the results of its operations and its cash flows for the years then ended in
accordance with Canadian generally accepted accounting principles.
Chartered Accountants
Calgary, Canada
March 4, 2010, except as to note 14 which is as of March 26, 2010
BONAVISTA ENERGY TRUST
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 Unitholders’ Equity:
Current liabilities:
2009
2008
$ 128,363
$
106,116
6,322
5,626
4,424
-
76,203
-
144,735
182,319
2,906,073
2,319,600
41,321
41,321
$ 3,092,129
$ 2,543,240
Accounts payable and accrued liabilities
$ 157,019
$ 143,093
Distributions payable
Financial instrument contracts (note 11)
Convertible debentures (note 8)
Future income tax (note 10)
Long-term debt (note 7)
Convertible debentures (note 8)
Asset retirement obligations (note 4)
Future income taxes (note 10)
Unitholders’ equity:
19,937
15,169
38,093
1,641
231,859
832,138
-
160,314
144,235
28,731
-
-
22,221
194,045
588,792
43,711
127,467
177,253
Unitholders’ capital and debenture conversion component (notes 8 and 9)
1,531,299
1,100,768
Exchangeable shares (note 9)
Contributed surplus (note 9)
Accumulated earnings
Commitments (note 13)
59,295
13,319
119,670
69,488
10,687
231,029
1,723,583
1,411,972
$ 3,092,129
$ 2,543,240
See accompanying notes to the consolidated financial statements.
Approved on behalf of Bonavista Energy Trust, by Bonavista Petroleum Ltd. as administrator:
Ian S. Brown, Director
Michael M. Kanovsky, Director
BONAVISTA ENERGY TRUST
Consolidated Statements of Operations, Comprehensive Income and Accumulated Earnings
Years ended December 31,
(thousands, except per unit amounts)
Revenues:
Production
Royalties
Realized gains (losses) on financial instruments (note 11)
Unrealized gains (losses) on financial instruments (note 11)
Expenses:
Operating
Transportation
General and administrative
Financing
Unrealized loss on marketable securities
Unit-based compensation
Depreciation, depletion and accretion
Income before taxes
Income taxes (reductions) (note 10)
Net income and comprehensive income
Accumulated earnings, beginning of year
Distributions declared
Accumulated earnings, end of year
Net income per unit – basic
Net income per unit – diluted
See accompanying notes to the consolidated financial statements.
2009
2008
$ 759,423
$ 1,234,391
(117,217)
(239,967)
642,206
994,424
72,100
(85,746)
(80,806)
121,261
(13,646)
40,455
628,560
1,034,879
197,795
184,053
36,833
17,900
14,035
1,336
11,386
295,296
38,744
14,410
32,535
-
11,049
266,271
574,581
547,062
53,979
(52,627)
487,817
49,451
106,606
438,366
231,029
125,203
(217,965)
(332,540)
$ 119,670
$ 231,029
$
$
0.82
$
3.84
0.81
$
3.80
BONAVISTA ENERGY TRUST
Consolidated Statements of Cash Flows
Years ended December 31,
(thousands, except per unit amounts)
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
Unrealized loss on marketable securities
Future income tax (reductions)
Asset retirement expenditures
Changes in non-cash working capital items
Financing Activities:
Issuance of equity, net of issue costs
Distributions
Changes in long-term debt
Repayment of convertible debentures
Changes in non-cash working capital items
Investing Activities:
Exploration and development
Property acquisitions
Property dispositions
Changes in non-cash working capital items
Change in cash
Cash, beginning of year
Cash, end of year
See accompanying notes to the consolidated financial statements.
2009
2008
$ 106,606
$ 438,366
295,296
11,386
85,746
1,336
(52,627)
(12,036)
(11,774)
266,271
11,049
(121,261)
-
49,451
(15,229)
49,581
423,933
678,228
404,115
(226,759)
243,346
(6,586)
(349)
223,152
(329,538)
(123,862)
-
(344)
413,767
(230,592)
(203,845)
(737,117)
107,118
(3,856)
(305,514)
(187,023)
10,240
34,661
(837,700)
(447,636)
-
-
-
$
-
-
-
$
BONAVISTA ENERGY TRUST
Notes to Consolidated Financial Statements
Years ended December 31, 2009 and 2008
Structure of the Trust and Basis of Presentation:
Bonavista Energy Trust (“Bonavista” or the “Trust”) is an open-ended unincorporated investment trust governed by the laws of the
Province of Alberta. The Trust was established on July 2, 2003 under a Plan of Arrangement entered into by the Trust, Bonavista
Petroleum Ltd. (“BPL”) and its subsidiaries and partnerships and NuVista Energy Ltd. (“NuVista”). Under the Plan of Arrangement, a
wholly-owned subsidiary of the Trust amalgamated with BPL and became the successor company. The Trust has two significant
subsidiaries in which it owns 100% of the common shares of BPL (excluding the exchangeable shares – see note 9) and 100% of the
units of Bonavista Trust (2003) (“BT”). The activities of these entities are financed through interest bearing notes from the Trust and
third party debt as described in the notes to the consolidated financial statements. The business of the Trust is carried on through the
entities owned by the subsidiaries of the Trust, Bonavista Petroleum, a general partnership (“BP”) and Bonavista Energy Limited
Partnership (“BELP”). The net income of the Trust is generated from interest on notes advanced to its subsidiaries, royalty payments
on oil and natural gas assets owned by BP, as well as any dividends or distributions paid by its subsidiaries. The Trustee must
declare payable to the Trust Unitholders all of the taxable income 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 judgment.
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 measurement uncertainty 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 Trust and its wholly-owned subsidiaries, trusts and
proportionate share of its partnerships. All inter-entity transactions have been eliminated.
b) Oil and natural gas properties and equipment:
The Trust 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
proven reserves, are depreciated and depleted using the unit-of-production method which is based on gross production and
estimated proven 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
Trust 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 bank debt are classified as other
liabilities which are measured at amortized cost, which is determined using the effective interest 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 Trust 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 Trust to reduce its
exposure to fluctuations in commodity prices, foreign exchange rates, and interest rates. The Trust does not use these
derivative instruments for trading or speculative purposes. The Trust considers all of these transactions to be economic
hedges; however, the majority of the Trust’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 Trust 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 Trust 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 bank debt is presented
net of deferred interest payments, with interest recognized in net income on an effective interest basis.
h) Unit-based compensation:
Bonavista has an equity incentive plan, which is described in note 9. The trust unit incentive right compensation plan for
employees do not involve the direct award of trust units, or call for the settlement in cash or other assets. Bonavista uses the
fair value method for valuing the granting of trust unit incentive rights. Under this method, the compensation cost attributable
to all the trust unit 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 trust unit rights, consideration received together with
the amount previously recognized in contributed surplus is recorded as an increase to Unitholders’ equity.
i) Restricted trust unit incentive plan:
Bonavista has established a Restricted Trust Unit Incentive Plan (the "RTU Plan") for our employees as described in note 9.
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, at the discretion of Trust, the holder will receive for each unit award, including distributions
made on the trust units from the date of the grant to and including the vesting date, net of statutory withholding tax, either: (i)
equivalent trust units; or (ii) the cash equivalent. Trust units may be issued from treasury or purchased on the open market.
The Trust has not incorporated an estimated forfeiture rate for Restricted Trust Units that will not vest, rather the Trust
accounts for actual forfeitures as they occur.
j)
Income taxes:
Bonavista is a taxable entity under the Canadian Income Tax Act and until 2011 is taxable only on income that is not
distributed or distributable to its unitholders. Commencing in 2011, distributions paid to unitholders will not be deductible for
tax and Bonavista will be taxed on its income similar to corporations. The Trust follows the asset and liability method of
accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax
consequences attributable to differences between the amounts reported in the financial statements of BPL and its
subsidiaries and their respective tax basis, using substantively enacted income tax rates expected to be in effect when the
temporary differences are anticipated to reverse. In addition, income tax liabilities and assets are recognized for the
estimated tax consequences of temporary differences arising in the Trust that reverse after 2011. The effect of a change in
income tax rates on future income tax liabilities and assets is recognized in net income in the period that the change occurs.
k) Per unit amounts:
Diluted per unit amounts reflect the potential dilution that could occur if securities or other contracts to issue trust units were
exercised or converted to trust units. The treasury stock method is used to determine the dilutive effect of unit incentive
rights and other dilutive instruments.
l) Comparative figures:
The comparative figures have been reclassified to reflect the current year presentation.
2. Changes in accounting policies:
a) Goodwill:
On January 1, 2009, the Trust adopted CICA Handbook Section 3064 "Goodwill and Intangible Assets", which defines the
criteria for the recognition of intangible assets. The adoption of this standard did not impact the Trust's consolidated financial
statements.
b) Financial Instruments - Disclosures:
Effective December 31, 2009, Bonavista adopted CICA issued amendments to Section 3862, "Financial Instruments -
Disclosures", the amendment outlines a hierarchy of methods to be used to determine the fair value of financial instruments
on the balance sheet date. The adoption of these amendments did not have a material impact on our results of operations,
financial position and disclosures.
c)
International Financial Reporting Standards:
On February 13, 2008, Canada's Accounting Standards Board confirmed January 1, 2011 as the effective date for the
convergence of Canadian GAAP to International Financial Reporting Standards ("IFRS"). The Canadian Securities
Administrators are in the process of examining the changes to securities rules as a result of this initiative. Bonavista has
completed a preliminary analysis of the accounting differences and is in the process of performing a detailed assessment of
the impact of IFRS on our results of operations, financial position and disclosures.
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 and an officer of NuVista is also an officer of Bonavista.
For the year ended December 31, 2009, Bonavista charged NuVista no fees (2008 - $1.1 million) relating to general and
administrative services provided to NuVista. NuVista charged Bonavista management fees for a jointly owned partnership totaling
$1.2 million (2008 - $1.4 million). As at December 31, 2009, the amount payable to NuVista was $343,000.
4. Asset retirement obligations:
The Trust’s asset retirement obligations result from net ownership interests in oil and natural gas assets including well sites,
gathering systems and processing facilities. The Trust estimates the total undiscounted amount of expenditures required to settle
its asset retirement obligations is approximately $753.5 million (2008 - $587.0 million) which will be incurred over the next
51 years. The majority of the costs will be incurred between 2011 and 2038. A credit-adjusted risk-free rate of 7.5%
(2008 - 7.5%) and an inflation rate of 2% (2008 - 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,
2009
2008
$ 127,467
$ 116,893
10,033
3,195
31,234
(12,036)
421
8,577
9,177
2,746
(15,229)
5,303
$ 160,314
$ 127,467
On August 20, 2009, Bonavista acquired certain long-life natural gas weighted properties located in its Western Region for a cash
purchase price of approximately $698 million.
6. Oil and natural gas properties and equipment:
December 31, 2009
(thousands)
Oil and natural gas properties
Facilities
Office equipment
December 31, 2008
(thousands)
Oil and natural gas properties
Facilities
Office equipment
Cost
$
$
3,667,533
842,307
8,378
4,518,218
Cost
Accumulated
depreciation and
depletion
$
$
1,423,169
183,886
5,090
1,612,145
Accumulated
depreciation and
depletion
$
$
2,966,957
673,240
7,262
3,647,459
$
$
1,174,448
149,143
4,268
1,327,859
Net book value
$ 2,244,364
658,421
3,288
$ 2,906,073
Net book value
$ 1,792,509
524,097
2,994
$ 2,319,600
Unproved property costs of $179.7 million as at December 31, 2009 (2008 - $161.8 million) were excluded from the depreciation
and depletion calculation. Future development costs of $587.0 million (2008 - $241.8 million) were included in the depreciation
and depletion calculation.
Bonavista has calculated the ceiling test as of December 31, 2009. Based on the calculation, the present value of future net
revenues from the Trust’s proved reserves exceeds the carrying value of the Trust’s oil and natural gas properties and equipment
at December 31, 2009. The benchmark reference prices, as provided by our independent engineering consultants, used in the
calculation and adjusted for commodity differentials specific to Bonavista are as follows.
Benchmark Reference Price Forecasts:
Year
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
Remainder (1)
(1) Escalated at 2% per year thereafter
7. Long-term debt:
WTI Oil
(US$/bbl)
80.00
83.00
86.00
89.00
92.00
93.84
95.72
97.64
99.59
101.58
2.0%
AECO Gas
(Cdn$/mmbtu)
5.96
6.79
6.89
6.95
7.05
7.16
7.42
7.95
8.52
8.69
2.0%
USD/CAD
Exchange Rates
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
0.95
The Trust has two bank loan facilities totaling $1.4 billion with a syndicate of chartered banks. These combined facilities are
unsecured, covenant-based, extendible revolving facilities and include a $50 million working capital facility. The facilities provide
that advances may be made by way of prime rate loans, bankers' acceptances and/or US dollar LIBOR advances. These
advances bear interest at the banks' prime rate and/or at money market rates plus a stamping fee. The facilities are revolving
credit and may, at the request of the Trust with the consent of the lenders, be extended on an annual basis. The facilities have a
maturity of August 10, 2011 with no principal payments required until then. There is an accordion feature providing that at anytime
during the term, on participation of any existing or additional lenders, we can increase the facility by $250 million.
Under the terms of the credit facilities, the Trust 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 instruments 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 instruments 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 unitholders’ equity of the Trust, in all cases calculated based on a rolling prior four quarters.
Financing expenses for the year ended December 31, 2009 include interest on bank loans of $11.2 million (2008 – $29.3 million)
and convertible debentures of $2.8 million (2008 – $3.2 million). For the year ended December 31, 2009, Bonavista paid cash
interest of $14.4 million (2008 – $32.9 million). For the year ending December 31, 2009 our effective interest rate was
approximately 1.5% (2008 – 3.9%).
8. Convertible debentures:
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 Unitholders’ equity at the date of issue was $4.7 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. On June 30, 2009, the 7.5% convertible debentures
matured and were cash settled. The following table sets out the convertible debenture activities to December 31, 2009:
Debt
Component
Equity
Component
(thousands)
Balance, December 31, 2007
Accretion
Issue expenses related to conversions to trust units
Amortization of issue expenses
Conversion to trust units
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
9. Unitholders’ equity:
a) Authorized:
Unlimited number of voting trust units.
b)
Issued and outstanding:
(i) Trust units:
(thousands)
Balance, December 31, 2007
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, 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
$
$
48,830
57
42
684
(5,902)
43,711
452
2
525
(6,586)
(11)
$
38,093
Number of
Units
85,757
7,000
215
1,632
1,099
67
-
-
-
-
95,770
25,000
1
3,380
335
118
-
-
-
-
124,604
$
$
$
1,054
-
-
-
(121)
933
-
-
-
(123)
(2)
808
Amount
850,631
214,200
5,902
5,222
19,957
-
(42)
(7,924)
121
11,768
1,099,835
421,250
11
10,193
4,478
-
(2)
(16,218)
2
10,942
$ 1,530,491
Redemption right:
Unitholders may redeem their Trust Units at any time by delivering their Unit Certificates to the Trustee, together with a
properly completed notice requesting redemption. The redemption amount per Trust Unit will be the lesser of 90% of the
weighted average trading price of the Trust Units on the principal market on which they are traded for the 10 day period after
the Trust Units have been validly tendered for redemption and the “closing market price” of the Trust Units. The redemption
amount will be payable on the last day of the following calendar month. The “closing market price” will be the closing price of
the Trust Units on the principal market in which they are traded on the date on which they were validly tendered for
redemption, or, if there was no trade of the Trust Units on that date, the average of the last bid and ask prices of the Trust
Units on that date. Cash payments for Units tendered for redemption are limited to $250,000 per month with redemption
requests in excess of this amount, eligible to receive a note from BPL.
(ii) Contributed surplus:
(thousands)
Balance, December 31, 2007
Unit-based compensation expense
Unit-based compensation capitalized
Exercise of trust unit incentive rights and conversion of restricted trust units
Balance, December 31, 2008
Unit-based compensation expense
Unit-based compensation capitalized
Adjustment to equity component of debenture on repayment
Exercise of trust unit incentive rights and conversion of restricted trust units
Balance, December 31, 2009
(iii) Exchangeable shares:
Amount
$
9,369
11,049
2,037
(11,768)
10,687
11,386
2,065
123
(10,942)
$
13,319
Pursuant to the Plan of Arrangement, 15,999,999 exchangeable shares were authorized and issued. The exchangeable
shares of BPL are exchangeable only into trust units based on the exchange ratio, which is adjusted monthly, to reflect the
distribution paid on the trust units. As a result distributions are not paid on the exchangeable shares.
(thousands)
Balance, beginning of year
Exchanged for trust units
Balance, end of year
Years ended December 31,
2009
2008
Number
Amount
Number
Amount
11,375
(1,668)
$ 69,488
(10,193)
12,230
(855)
$ 74,710
(5,222)
9,707
$ 59,295
11,375
$ 69,488
Exchange ratio, end of year
2.21352
-
1.96225
-
Trust units issuable on exchange
21,486
$ 59,295
22,321
$ 69,488
As a result of minimal conversions of exchangeable shares into trust units over the last few years, Bonavista elected to
redeem 10% of its exchangeable shares outstanding on January 16, 2009. This redemption allows Bonavista to manage the
dilution created by the compounding effect of the exchangeable shares, maintain an optimal capital and tax efficient trust
structure for the Trust and its unitholders. On January 16, 2009, 1.1 million exchangeable shares were redeemed for
2.3 million trust units.
On July 2, 2013, subject to extension of such date by the Board of Directors of BPL, the Exchangeable Shares will be
redeemed for Trust Units at a price equal to the value of that number of Trust Units based on the exchange ratio as at the last
business day prior to the redemption date. BPL may redeem all but not less than all of the outstanding Exchangeable Shares
at any time when the aggregate number of issued and outstanding Exchangeable Shares is less than 1,000,000. BPL will, at
least 90 days prior to any redemption date, provide the registered holders with written notice of the prospective redemption.
The redemption price is equal to that described previously.
c) Trust unit incentive rights plan:
The Trust has a unit incentive rights plan that allows the Trust to issue rights to acquire trust units to directors, officers,
employees and service providers. The number of trust unit rights available under both long-term incentive plans shall be
limited to 5% of the aggregate number of issued and outstanding trust units of the Trust. Trust unit incentive right exercise
prices are equal to the market price for the trust units on the date that the unit rights are granted. If certain conditions are
met, the exercise price per unit may be calculated by deducting from the grant price the aggregate of all distributions, on a
per unit basis, made by the Trust after the grant date. The trust unit incentive rights granted under the plan vest over a
four-year period and expire two years after each vesting date.
Balance, December 31, 2007
Granted
Exercised
Expired and forfeited
Reduction in exercise price
Balance, December 31, 2008
Granted
Exercised
Expired and forfeited
Reduction in exercise price
Balance, December 31, 2009
Exercisable, December 31, 2009
Number of Trust
Unit Incentive Rights
Weighted Average
Exercise
Price
3,726,125
960,840
(1,099,250)
(378,920)
-
3,208,795
1,616,820
(335,410)
(673,963)
-
3,816,242
993,960
$
24.76
33.68
(18.16)
(26.54)
(3.60)
25.88
16.57
(13.35)
(22.62)
(1.80)
$
$
21.28
22.63
The following table summarizes trust unit incentive rights outstanding and exercisable under the plan at December 31, 2009:
Range of
exercise
prices
$
11.01 - 15.71
15.72 - 22.82
22.83 - 38.23
$ 11.01 - 38.23
Number
outstanding
at year-end
1,303,914
1,118,873
1,393,455
3,816,242
d) Unit-based compensation:
Trust Unit Incentive
Rights Outstanding
Weighted
average
remaining
contractual
life
Trust Unit Incentive
Rights Exercisable
Weighted
average
exercise
price
Number
exercisable at
year-end
Weighted
average
exercise
price
3.5
1.6
2.4
2.5
$ 14.29
21.16
27.92
$ 21.28
145,955
465,565
382,440
993,960
$
14.19
21.33
27.42
$
22.63
The Trust uses the fair value based method for the determination of the unit-based compensation costs. The fair value of
each 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% (2008 - 3.5%); average volatility of 66% (2008 - 32%); a forfeiture rate of
10% (2008 - 10%) and an expected life of 4.5 years. The fair value of the options granted in 2009 average $9.76
(2008 - $9.05) per incentive right.
e) Restricted trust unit incentive plan:
The Trust has a Restricted Trust Unit Incentive Plan that allows the Trust to award trust units to directors, officers, employees
and service providers. The number of restricted trust units available under both long-term incentive plans shall be limited to
5% of the aggregate number of issued and outstanding units of the Trust. 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, at the discretion
of Trust, the holder will receive for each unit award, including distributions made on the trust units from the date of the grant
to and including the vesting date, net of statutory withholding tax, either: (i) equivalent trust units; or (ii) the cash equivalent.
The following table summarizes the restricted trust unit's outstanding under the plan at December 31, 2009:
Balance, December 31, 2008
Granted
Forfeited
Conversion of restricted trust units
Balance, December 31, 2009
150,573
171,450
(16,971)
(107,156)
197,896
For the year ended December 31, 2009, the Trust expensed $2.2 million (2008 – $3.7 million) relating to the Restricted Trust
Unit Incentive Plan.
f) Per unit amounts:
The following table summarizes the weighted average trust units, exchangeable shares and convertible debentures used in
calculating net income per trust unit:
(thousands)
Trust units
Exchangeable shares converted at the exchange ratio
Basic equivalent trust units
Convertible debentures
Trust unit incentive rights
Restricted trust units
Diluted equivalent trust units
Years ended December 31,
2009
108,029
21,234
129,263
1,471
281
218
131,233
2008
91,703
22,487
114,190
1,713
435
130
116,468
For the purposes of calculating net income per trust unit on a diluted basis, the net income has been increased by
$3.8 million (2008 - $4.0 million) with respect to the accretion, amortization and interest expense on the convertible
debentures. For the year ended December 31, 2009 the Trust excluded 3.5 million (2008 - 2.8 million) weighted average
trust unit incentive rights from the diluted 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
Provision for income taxes (reduction)
The provision for income taxes consists of:
Current
Future (reduction)
Provision for income taxes (reduction)
$
$
$
$
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 & Other
Future income taxes
Years ended December 31,
2008
2009
29.2%
29.8%
15,762
$
145,436
(8,949)
(63,701)
4,261
(52,627)
-
(52,627)
(52,627)
2009
146,547
36,135
(38,354)
(2,876)
$
$
$
$
(761)
(99,142)
3,918
49,451
-
49,451
49,451
2008
167,146
41,214
(31,107)
22,221
$
$
141,452
$
199,474
For the years ended December 31, 2009 and 2008 Bonavista paid no tax installments.
11. Financial instruments:
The Trust has exposure to credit, liquidity and market risks from its use of financial instruments. This note provides information
about the Trust's exposure to each of these risks, the Trust's objectives, policies and processes for measuring and managing risk.
Further quantitative disclosures are included throughout these financial statements.
a) Credit risk:
The carrying amount of accounts receivable represents the maximum credit exposure. As at December 31, 2009 the Trust's
receivables consisted of $83.8 million of receivables from crude oil and natural gas marketers which has substantially been
collected, subsequent to December 31, 2009, $19.6 million from joint venture partners of which $5.2 million has been
subsequently collected, and $25.0 million of Crown deposits and prepaid expenses. As at December 31, 2009 the Trust has
$10.7 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. The Trust does not have an allowance for doubtful accounts as
at December 31, 2009 and did not provide for any doubtful accounts nor was it required to write-off any receivables during
the year ended December 31, 2009.
b) Liquidity risk:
Liquidity risk is the risk that the Trust will encounter difficulty in meeting obligations associated with the financial liabilities. The
Trust's financial liabilities consist of accounts payable and accrued liabilities, financial instruments, bank debt and convertible
debentures. Accounts payable consists of invoices payable to trade suppliers for office, field operating activities, capital
expenditures, and distributions payable. The Trust processes invoices within a normal payment period.
Accounts payable and financial instruments have contractual maturities of less than one year. The Trust maintains a three
year revolving credit facility, as outlined in note 7, which may, at the request of the Trust with the consent of the lenders, be
extended on an annual basis. The Trust also has a series of convertible debentures outstanding. The 6.75% debentures
have a conversion price of $29.00 per trust unit, maturing on June 30, 2010. The Trust may elect to satisfy the principal
obligation of this debenture by issuing trust units to the holders of the debentures. The Trust 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 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. The Trust has attempted
to mitigate a portion of the commodity price risk through the use of various financial instruments and physical delivery sales
contracts. The Trust'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 instruments:
As at December 31, 2009, the Trust has hedged by way of costless collars to sell natural gas and crude oil as follows:
Volume
Average Price
Term
5,000
15,000
5,000
20,000
10,000
9,000
1,000
gjs/d CDN$5.00 - CDN$6.50 - AECO
gjs/d CDN$4.75 - CDN$6.45 - AECO
gjs/d CDN$4.50 - CDN$5.50 - AECO
gjs/d CDN$4.56 - CDN$6.12 - AECO
gjs/d CDN$5.25 - CDN$7.20 - AECO
bbls/d CDN$68.06 - CDN$92.83 - WTI
bbls/d CDN$80.00 - CDN$95.25 - WTI
January 1, 2010 – March 31, 2010
April 1, 2010 - October 31, 2010
January 1, 2010 - March 31, 2010
January 1, 2010 - December 31, 2010
January 1, 2011 - December 31, 2011
January 1, 2010 - December 31, 2010
January 1, 2011 - December 31, 2011
As at December 31, 2009, the Trust has limited its downside exposure to natural gas prices by purchasing a put option.
The Trust has also hedged its exposure to electricity pricing by entering into a swap which determines a fixed price paid
throughout the term of the contract. These financial instruments are outlined below:
Volume
Price
Contract
Term
5,000
1
gjs/d CDN $4.50
mw/h CDN$55.00
Purchased Put - AECO
Swap - AESO
April 1, 2010 - October 31, 2010
January 1, 2010 - December 31, 2010
Financial instruments 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, 2009 the fair market value recorded on the
consolidated balance sheet for these financial instruments was a net liability of $9.5 million, compared to an asset of
$76.2 million in 2008. These financial instruments had the following gains and losses reflected in the consolidated
statements of operations, comprehensive income and accumulated earnings:
Realized gains (losses) on financial instruments
Unrealized gains (losses) on financial instruments
Years
ended December 31,
2009
72,100
(85,746)
$
2008
(80,806)
121,261
$
$
(13,646)
$
40,455
Bonavista mitigates its risk associated with fluctuations in commodity prices by utilizing financial instruments. A $0.10
change in the price per thousand cubic feet of natural gas @ AECO would have an impact of approximately $2.7 million
on net income for those financial instruments that were in place as at December 31, 2009. A $1.00 change in the price
per barrel of oil – WTI would have an impact of approximately $1.4 million on net income for those financial instruments
that were in place as at December 31, 2009.
Subsequent to December 31, 2009 the Trust has hedged by way of costless collars to sell natural gas and crude oil as
follows:
Volume
Average Price
Term
5,000
10,000
10,000
5,000
1,000
1,000
1,500
gjs/d CDN$4.50 - CDN$7.24 - AECO
gjs/d CDN$4.50 - CDN$6.50 - AECO
gjs/d CDN$5.00 - CDN$7.45 - AECO
gjs/d CDN$5.00 - CDN$6.50 - AECO
bbls/d CDN$75.00 - CDN$92.38 - WTI
bbls/d CDN$75.00 - CDN$91.03 - WTI
bbls/d CDN$80.00 - CDN$98.40 - WTI
ii) Physical purchase contracts:
March 1, 2010 - October 31, 2011
April 1, 2010 - October 31, 2010
November 1, 2010 - March 31, 2011
April 1, 2011 - October 31, 2011
January 1, 2010 - December 31, 2010
July 1, 2010 - September 30, 2010
January 1, 2011 - December 31, 2011
As at December 31, 2009, the Trust has entered into direct sale costless collars to sell natural gas as follows:
Volume
Average Price
Term
10,000
5,000
5,000
10,000
5,000
gjs/d CDN$5.25 - CDN$6.53 - AECO
gjs/d CDN$5.25 - CDN$7.00 - AECO
gjs/d CDN$5.00 - CDN$6.60 - AECO
gjs/d CDN$5.13 - CDN$6.99 - AECO
gjs/d CDN$5.25 - CDN$8.18 - AECO
January 1, 2010 - March 31, 2010
April 1, 2010 - October 31, 2010
January 1, 2010 - December 31, 2010
January 1, 2011 - December 31, 2011
November 1, 2010 - March 31, 2011
As at December 31, 2009, the Trust has entered into physical swap contracts to sell natural gas and to purchase
electricity as follows:
Volume
Average Price
Term
5,000
4
2
gjs/d CDN $5.06 - AECO
mw/h CDN$50.54 - AESO
mw/h CDN$55.03 - AESO
January 1, 2010 - December 31, 2010
January 1, 2010 - December 31, 2010
January 1, 2011 - December 31, 2011
Subsequent to December 31, 2009 the Trust has entered into direct sale costless collars to sell natural gas as follows:
Volume
10,000
5,000
Average Price
Term
gjs/d CDN$4.50 - CDN$6.11 - AECO
gjs/d CDN$5.00 - CDN$7.10 - AECO
April 1, 2010 - October 31, 2010
November 1, 2010 - March 31, 2011
Physical purchase contracts are being accounted for as they are settled.
iii) Foreign currency exchange rate risk:
Foreign currency exchange rate risk is the risk that the fair value of future cash flows will fluctuate as a result of changes
in foreign exchange rates. The Trust sells crude oil and natural gas that is denominated in both US and Canadian
dollars. Canadian commodity prices are influenced by fluctuations in the Canadian to U.S. dollar exchange rate. The
Trust had no forward exchange rate contracts in place as at or during the period ended December 31, 2009.
iv)
Interest rate risk:
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Trust
is exposed to interest rate fluctuations on its bank debt which bears a floating rate of interest. If the interest rates
applicable to Bonavista’s bank debt were to change by 100 basis points and assuming that the changes in bank debt are
consistent with what actually occurred in the period, we would estimate that net income for the year ended
December 31, 2009 would have a $5.5 million (2008 - $5.0 million) impact. The sensitivity impact is higher for the year
ended in 2009 because of higher weighted average bank debt compared to the year ended December 31, 2008,
notwithstanding that the weighted average interest rate is lower in 2009 compared to the same period in 2008. The Trust
had no interest rate swap or financial contracts in place as at or during the period ended December 31, 2009.
Fair value of financial instruments:
The financial instruments carried on the Trust’s consolidated balance sheet have been assessed on the fair value hierarchy set
out under amended Section 3862, "Financial Instruments – Disclosures". The Trust has classified the fair value of these
transactions 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.
All of the Trust’s financial contracts, marketable securities, convertible debentures and bank debt have been fair valued based on
the policy outlined above. The Trust’s marketable securities and convertible debentures have been classified as Level 1, the
financial contracts are classified as Level 2 and bank debt is classified as Level 3.
The fair value of financial instruments is determined by the financial intermediary to extinguish all rights or obligations of the
financial instruments. As at December 31, 2009, the fair market value of these financial instruments was a net liability of
approximately $9.5 million (2008 - $76.2 million asset).
Fair market value of the convertible debentures as at December 31, 2009 is $38.9 million (2008 - $44.4 million), as determined by
its most recent closing trading price.
Fair market value of marketable securities as at December 31, 2009 is $6.3 million (2008 - nil), as determined by the closing price
of common shares of Legacy Oil and Gas Inc.
Bank debt bears interest at a floating market rate and accordingly the fair market value approximates the carrying value.
12. Capital management:
The Trust'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 unitholders with stable distributions and rates of return.
The Trust considers its capital structure to include working capital (excluding unrealized gains and losses on financial
instruments), convertible debentures, bank debt, and unitholders' equity. The Trust 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 plus or minus net working capital, divided by funds from operations for the most recent calendar quarter,
annualized (multiplied by four). The Trust'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 the Trust's credit facility. This ratio may increase at certain times as a result of
acquisitions or low commodity prices. As at December 31, 2009, the Trust's ratio of net debt to fourth quarter annualized funds
from operations was 1.6 to 1 (2008 – 1.2 to 1), which is within the acceptable range established by the Trust.
In order to facilitate the management of this ratio, the Trust prepares annual funds from operations and capital expenditure
budgets, which are updated as necessary, and are reviewed and periodically approved by the Trust's Board of Directors. The
Trust manages its capital structure and makes adjustments by continually monitoring its business conditions, including; the
current economic conditions; the risk characteristics of the Trust's crude 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, the Trust 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 Trust's lenders; the level of bank credit that may be attainable from its lenders as a result of
crude oil and natural gas reserves; 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 distributions payable to its unitholders. The Trust's unitholder's capital is not subject to external restrictions,
however the Trust's credit facility does contain financial covenants that are outlined in note 7 of the consolidated financial
statements.
There has been no change in the Trust's approach to capital management during the year ended December 31, 2009.
13. Commitments:
The following is a summary of the Trust’s commitments as at December 31, 2009:
(thousands)
Transportation expenses
Office premises
Total
2010
2011
2012
2013
2014 and
thereafter
Payments Due by Period
$ 51,417
1,708
$ 16,114
1,412
$ 11,570
296
$ 8,314
-
$ 6,665
-
$ 8,754
-
Total commitments
$ 53,125
$ 17,526
$ 11,866
$ 8,314
$ 6,665
$ 8,754
14. Subsequent events:
a) Property acquisitions:
On March 24, 2010, the Trust announced that it had entered into an agreement to acquire certain long-life natural gas
weighted properties located adjacent to our Whitecourt property in west central Alberta. The acquisition has an effective date
of January 1, 2010 and is expected to close on or about May 31, 2010 for a cash purchase price, at closing, of approximately
$228 million.
b) Financing:
In conjunction with the acquisition, Bonavista has entered into an agreement to sell, on a bought deal basis, 7.5 million Trust
Units at a price of $23.60 per Trust Unit for gross proceeds of approximately $177 million to a syndicate of underwriters.
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, Engineering
Johannes H. Thiessen,
Senior Vice President, Exploration
Scott H. Hanson,
Vice President, Production
Orest G. Humeniuk,
Vice President, Land
Dean M. Kobelka,
Vice President, Finance
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
Union Bank of California, N.A. (Canada Branch)
Fortis Capital (Canada) Ltd.
HSBC Bank Canada
Société Générale (Canada 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.UN and “BNP.DB.A”
HEAD OFFICE
700, 311 – 6 t h Avenue SW
Calgary, Alberta T2P 3H2
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
Ronald J. Poelzer
Executive Vice President
(403) 213-4308
or
Glenn A. Hamilton
Senior Vice President and CFO
(403) 213-4302