Bonavista Energy Trust (TSX:BNP.UN) is pleased to report to unitholders its
interim consolidated financial and operating results for the three months and
year ended December 31, 2008.
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Highlights
----------------------------------------------------------------------------
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Three months ended Years ended
December 31, December 31,
2008 2007 2008 2007
----------------------------------------------------------------------------
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Financial
($ thousands, except per unit)
Production revenues 221,782 242,361 1,234,391 911,346
Funds from operations (1) 131,741 127,778 643,876 502,783
Per unit (1) (2) 1.12 1.20 5.64 4.76
Distributions declared 85,824 77,136 332,540 307,401
Per unit 0.90 0.90 3.60 3.60
Percentage of funds from
operations (1) 65% 60% 52% 61%
Net income 129,192 63,631 438,366 218,187
Per unit (2) 1.09 0.60 3.84 2.07
Total assets 2,543,240 2,242,057
Long-term debt, including working
capital deficiency 600,518 723,003
Long-term debt, net of adjusted
working capital (3) 654,500 691,462
Unitholders' equity 1,411,972 1,060,967
Capital expenditures:
Exploitation and development 60,236 58,440 305,514 267,660
Acquisitions, net (105) (425) 176,783 98,696
Weighted average outstanding equivalent
trust units: (thousands) (2)
Basic 118,065 106,762 114,190 105,543
Diluted 119,905 109,102 116,468 108,075
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Operating
(boe conversion - 6:1 basis)
Production:
Natural gas (mmcf/day) 171 170 175 171
Oil and liquids (bbls/day) 24,733 24,775 24,079 24,034
Total oil equivalent (boe/day) 53,288 53,029 53,190 52,505
Product prices: (4)
Natural gas ($/mcf) 7.52 6.74 8.30 6.95
Oil and liquids ($/bbl) 53.05 58.04 70.68 54.40
Operating expenses ($/boe) 9.91 8.58 9.45 8.47
General and administrative
expenses ($/boe) 0.78 0.74 0.74 0.70
Cash costs ($/boe) (5) 11.87 11.56 11.87 11.01
Operating netback ($/boe) (6) 28.83 29.17 35.49 28.77
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December 31,
Highlights (cont'd) 2008 2007
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Drilling (gross wells) 200 216
Natural gas 84 108
Oil 106 97
Average success rate 95% 95%
Reserves:
Proved:
Natural gas (bcf) 462.6 427.1
Oil and liquids (mbbls) 65,044 63,724
Total oil equivalent (mboe) 142,150 134,911
Proved and probable:
Natural gas (bcf) 613.7 561.0
Oil and liquids (mbbls) 88,817 85,955
Total oil equivalent (mboe) 191,095 179,454
% Proved producing 59% 62%
% Proved 74% 75%
% Probable 26% 25%
Net present value of future cash flow before income
taxes ($ millions):
0% discount rate 7,465 6,116
5% discount rate 4,804 4,116
10% discount rate 3,555 3,154
Reserve life index (years):
Proved 7.4 7.3
Proved and probable 9.4 9.2
Finding, development and acquisition costs - proved
and probable ($/boe):
Including changes in future development
expenditures 19.11 15.91
Excluding changes in future development
expenditures 15.50 14.94
Recycle ratio - proved and probable: (7)
Including changes in future development
expenditures 1.9 1.8
Excluding changes in future development
expenditures 2.3 1.9
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Three months ended
-----------------------------------------------
December 31, September 30, June 30, March 31,
Trust Unit Trading Statistics 2008 2008 2008 2008
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($ per unit, except volume)
High 26.39 37.65 37.64 31.35
Low 14.25 25.01 28.96 24.24
Close 17.00 26.29 37.45 29.85
Average Daily Volume - Units 425,042 273,074 329,638 231,949
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NOTES:
(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) Long-term debt, net of adjusted working capital excludes unrealized
gains or losses on financial instruments and its related tax impact.
(4) Product prices include realized gains or losses on financial
instruments.
(5) Cash costs equal the total of operating, general and administrative,
and financing expenses.
(6) Operating netback equals production revenues including realized gains
or losses on financial instruments, less royalties, transportation and
operating expenses, calculated on a boe basis.
(7) Recycle ratio is calculated using operating netback per boe divided by
finding, development and acquisition 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, 2008. Bonavista has continued on its course of
generating profitable results since commencing operations as an energy trust in
July 2003. The results of 2008 are highlighted with strong operational and
financial results derived from the success in our capital programs during the
year. The continued execution of Bonavista's proven strategies in 2008 and for
the future are a testament to the validity and effectiveness of an operationally
and technically focused energy trust. During these times of global uncertainty
and volatility, these strategies enable Bonavista to be nimble, flexible and
responsive to our changing environment. Bonavista remains consistently focused
on the key aspects of our business through optimizing production and revenues,
reducing the costs of our business, improving reinvestment efficiency and
adjusting our capital programs and distribution policy to maximize value to our
unitholders. Due to the current economic conditions and continued weak commodity
prices, Bonavista has reduced its capital spending projections for 2009 to
between $225 and $250 million. This level of spending will result in the
drilling of approximately 100 to 115 wells, and result in production averaging
between 51,500 and 52,500 boe per day. In addition, effective for our March 2009
production for which distributions are payable on April 15, 2009, Bonavista is
reducing its monthly distribution to unitholders by $0.04 per unit to $0.16 per
unit. Although this revised level of capital spending is down over 50% from 2008
and our distributions will be reduced by 20%, we believe this to be prudent
given the uncertainty surrounding the prevailing economy. Maintaining our
healthy financial position, along with our low costs, and our capital spending
flexibility, positions Bonavista very well to sustain a longer term downturn and
allows us to remain poised to pursue incremental opportunities as they arise.
Accomplishments for Bonavista in 2008 include:
- Operationally, production volumes averaged 53,190 boe per day during 2008, a
record level, versus 52,505 boe per day in 2007 and have increased 54% from
34,600 boe per day since commencement as an energy trust on July 2, 2003.
Bonavista's current production rate is approximately 53,000 boe per day;
- Added 31.1 mmboe of proved and probable reserves during 2008, which replaced
annual production by 1.6 times and improved the Trust's proved and probable
reserve life index to 9.4 years from 9.2 years in 2007. These reserves were
added at a finding, development and acquisition cost, including changes in
future development expenditures, of $22.10 per boe on a proved basis ($18.06 per
boe excluding changes in future development expenditures) and $19.11 per boe on
a proved and probable basis ($15.50 per boe excluding changes in future
development expenditures). A proved and probable recycle ratio of 1.9:1 (1.6:1
proved) was achieved in 2008 as a result of this level of finding, development
and acquisition costs. Overall in 2008, Bonavista increased proved and probable
reserves by 6% to 191.1 mmboe while spending 75% of funds from operations on
exploitation, development and acquisition expenditures;
- Maintained an active capital program in 2008 investing $305.5 million in
exploitation and development activities. Bonavista drilled 200 wells with an
overall 95% success rate, and we spent an additional $176.8 million on 20
synergistic acquisitions within our core regions;
- Drilled 24 successful horizontal wells on the highly prospective, light oil
Bakken trend in our Southeast Saskatchewan area resulting in production reaching
1,300 bbls per day. In addition to our Bakken resource initiatives, we have
identified additional resource plays to pursue in the coming months using
horizontal drilling and multi-stage fracture stimulation technology;
- On January 14, 2008 Bonavista completed the $172.2 million acquisition of
producing and undeveloped oil and natural gas properties (61% natural gas
weighted) in the greater Willesden Green area. This acquisition further
complemented the property acquisition that we completed in the fourth quarter of
2007 and our pre-existing assets in this area where we have recently experienced
tremendous success utilizing the latest horizontal, multi-stage fracture
technology. We now have a concentrated position in this area with current
production of approximately 6,500 boe per day and numerous, low cost
exploitation and optimization opportunities to pursue in the future;
- Continued to actively participate at crown land sales and freehold purchases,
investing $26.2 million in land activity, further enhancing our future drilling
prospect inventory for several years. Bonavista now holds approximately 1.1
million net acres of undeveloped land within its four core regions;
- Generated record funds from operations of $643.9 million ($5.64 per unit) for
the year ended December 31, 2008 and $131.7 million ($1.12 per unit) in the
fourth quarter of 2008. Of the total funds from operations generated in the
respective periods, Bonavista distributed 52% of these funds for the year ended
December 31, 2008 and 65% 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 strong profitability for the year ended December 31, 2008
with a strong return on equity of 23% and a strong net income to funds from
operations ratio of 43%. The above ratios reflect net income adjusted to negate
the after tax impact of the unrealized gains and losses on financial
instruments;
- Since inception as a Trust, Bonavista has delivered cumulative distributions
of $1.5 billion or $19.11 per trust unit. These cumulative distributions are in
excess of our closing price of $16.00 per trust unit on the first trading day
after we became an energy trust on July 2, 2003;
- On April 29, 2008 Bonavista completed a $214.0 million equity financing,
improving financial flexibility to pursue future growth opportunities through
expansions in either our exploitation and development activities or acquisition
programs. The ratio of 2008 year-end debt, net of adjusted working capital to
fourth quarter of 2008 annualized funds from operations is 1.2:1, which is very
attractive in our industry; and
- On August 25, 2008, Bonavista extended the term of its covenant-based $1.0
billion syndicated bank loan facility to August 10, 2011.
Strengths of Bonavista Energy Trust
Upon restructuring from an exploration and production corporation into an energy
trust in July 2003, Bonavista brought forward all of the same attributes that
resulted in the tremendous success of the company between 1997 and 2003. We have
maintained a high level of investment activity on our asset base, increasing
production more than 50% since 2003. This activity stems from the operational
and technical focus of our Trust, the attention to detail, and the ability to
generate economic prospects on our asset base within the Western Canadian
Sedimentary Basin. Our experienced and consistent technical teams have a solid
understanding of our assets and possess the necessary discipline and commitment
to deliver profitable results to our Unitholders for the long term. We actively
participate in undeveloped land acquisitions through Crown land sales, property
purchases or farm-in opportunities, which have all continued to add to our
already extensive low-risk drilling inventory. This has led to low cost reserve
additions, lengthening of our reserve life index, an increase in the quality and
quantity of our drilling inventory and a growing production base. Our production
base is balanced 55% in favour of natural gas and 45% towards oil and liquids
and is geographically focused within select medium depth, multi-zone regions in
Alberta, Saskatchewan and British Columbia. This asset base has a low operating
cost structure resulting in attractive operating netbacks. In addition, these
high working interest assets are predominantly operated by Bonavista, ensuring
that operating and capital cost efficiencies are maintained and that Bonavista
controls the pace of its operations.
Our team brings a successful track record of executing low to medium risk
development programs, including both asset and corporate acquisitions, along
with a record of sound financial management. Unitholders benefit from a fully
internalized, industry leading cost structure, which results in one of the
lowest per unit overhead costs in the energy trust industry. 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
17% of the Trust, 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, 2007. The following MD&A of the
financial condition and results of operations was prepared at, and is dated
March 2, 2009. Our audited consolidated financial statements, Annual Report, and
other disclosure documents for 2008 will be available on or before March 31,
2009 through our filings on SEDAR at www.sedar.com or can be obtained from
Bonavista's website at www.bonavistaenergy.com.
Basis of Presentation - The financial data presented below has been prepared in
accordance with Canadian Generally Accepted Accounting Principles ("GAAP"). The
reporting and the measurement currency is the Canadian dollar. For the purpose
of calculating unit costs, natural gas is converted to a barrel of oil
equivalent ("boe") using six thousand cubic feet of natural gas equal to one
barrel of oil unless otherwise stated. A boe may be misleading, particularly if
used in isolation. A boe conversion of 6 Mcf to one barrel is based on an energy
equivalent conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.
Forward-Looking Statements - Certain information set forth in this document,
including management's assessment of Bonavista's future plans and operations,
contains forward-looking statements including; (i) forecasted capital
expenditures; (ii) exploration, drilling and development plans; (iii)
anticipated production rates; (iv) expected royalty rate; (v) annualized debt to
funds from operations; (vi) funds from operations, (vii) anticipated operating
costs; (viii) expected service agreement fees; (ix) interest expense per boe;
and (x) drilling prospects, 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 exploitation and development program for the year ended
December 31, 2008 led to the drilling of 200 wells in our four core regions with
an overall success rate of 95%. This program resulted in 84 natural gas wells,
106 oil wells and 10 dry holes. Bonavista continues to pursue deeper and higher
impact drilling opportunities particularly in the Lower Mannville sands in our
Central region in Alberta and in the Bakken play in our Southeast Saskatchewan
area, where we have experienced excellent success and attractive finding and
development costs over the past few years. These activities have also continued
to lengthen our reserve life index and the predictability in our overall
production base. In addition to the exploitation and development program,
Bonavista executed 20 complementary acquisitions in its core regions during
2008.
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
Trust's net present value reserves, 84% were evaluated by independent third
party engineers, GLJ Petroleum Consultants Ltd. ("GLJ") and Ryder Scott Company
Canada in their reports dated February 24, 2009 depending on the location of the
property. The balance of approximately 16% of proved and probable net present
value reserves were evaluated internally and reviewed by GLJ. The reserve
estimates contained in the following tables represent Bonavista's interest
reserves before the deduction of royalties:
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Net Present Value @
Natural Oil and Total -----------------------------
Gas Liquids Reserves 0% 5% 10%
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(bcf) (mbbls) (mboe) (millions)
Proved:
Proved producing 376.8 49,802 112,596 $ 4,133 $ 2,945 $ 2,320
Proved
non-producing 33.5 4,500 10,088 304 226 178
Proved undeveloped 52.3 10,742 19,466 794 474 319
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Total proved (1) 462.6 65,044 142,150 5,231 3,645 2,818
Probable 151.0 23,775 48,945 2,234 1,159 737
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Total proved and
probable (1) 613.7 88,817 191,095 $ 7,465 $ 4,804 $ 3,555
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Oil and Total
Natural Gas Liquids Reserves
----------------------------------------------------------------------------
(bcf) (mbbls) (mboe)
Proved:
December 31, 2007 427.1 63,724 134,911
Exploitation and development 58.3 8,219 17,939
Revisions (2) 14.2 (964) 1,399
Acquisitions, net 26.9 2,878 7,369
Production (63.9) (8,813) (19,468)
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December 31, 2008 (1) 462.6 65,044 142,150
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Proved and probable:
December 31, 2007 561.0 85,955 179,454
Exploitation and development 74.4 11,508 23,916
Revisions (2) 4.2 (3,906) (3,211)
Acquisitions, net 38.0 4,073 10,404
Production (63.9) (8,813) (19,468)
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December 31, 2008 (1) 613.7 88,817 191,095
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(1) Numbers may not add due to rounding.
(2) Revisions include economic factors.
Bonavista's 2008 year-end proved reserves totalled 142.2 mmboe, a 5% increase
compared to the 134.9 mmboe at the year-end of 2007. Furthermore, Bonavista's
proved and probable reserves increased by 6% to 191.1 mmboe when compared to the
179.5 mmboe at year-end 2007. Bonavista's proved and probable reserve life index
("RLI") also increased during the year to 9.4 years, with the proved RLI at 7.4
years. Finding, development and acquisition costs in 2008, including changes in
future capital expenditures, amounted to $22.10 per boe ($18.06 per boe before
changes in future capital expenditures) on a proved basis and $19.11 per boe
($15.50 per boe before changes in future capital expenditures) on a proved and
probable basis. The Trust had negative proved plus probable reserve revisions of
3.2 mmboe which were primarily related to performance issues at four heavy oil
properties, a reassessment of waterflood performance at one of our light oil
properties and revisions to a couple of properties in British Columbia. The
aggregate of the exploitation and development costs incurred in the most recent
financial year and the change during the year in estimated future development
costs generally will not reflect total finding and development costs relating to
reserve additions for that year. Bonavista generated attractive recycle ratios
of 1.9:1 for proved and probable reserves and 1.6:1 for proved reserves which
includes revisions and changes in future development expenditures; excluding
changes in future development expenditures, the proved and probable recycle
ratio increased to 2.3:1 and the proved recycle ratio increased to 2.0:1.
Additional reserves disclosure tables, as required under NI 51-101, are
contained in Bonavista's Annual Information Form that will be filed on SEDAR.
Financial and operating highlights - The following is a summary of key financial
and operating results for the respective periods noted:
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Three months ended Years ended
December 31, December 31,
2008 2007 2008 2007
----------------------------------------------------------------------------
($ thousands, except per boe
/Trust Unit Amounts and where noted)
Product prices:
Natural gas ($/mcf) 7.52 6.74 8.30 6.95
Oil and liquids ($/bbl) 53.05 58.04 70.68 54.40
Production:
Natural gas (mmcf/d) 171 170 175 171
Oil and liquids (bbls/d) 24,733 24,775 24,079 24,034
Total production (boe/d) 53,288 53,029 53,190 52,505
Production revenues 221,782 242,361 1,234,391 911,346
per boe 45.24 49.68 63.41 47.55
Royalties 39,801 42,809 239,967 155,586
per boe 8.12 8.77 12.33 8.12
% of Production revenues 17.9% 17.7% 19.4% 17.1%
Operating expenses 48,603 41,867 184,053 162,371
per boe 9.91 8.58 9.45 8.47
Transportation expenses 9,589 10,364 38,744 41,397
per boe 1.96 2.12 1.99 2.16
General and administrative expenses 3,825 3,620 14,410 13,335
per boe 0.78 0.74 0.74 0.70
Financing expenses 5,761 10,915 32,535 35,209
per boe 1.18 2.24 1.67 1.84
Funds from operations 131,741 127,778 643,876 502,783
per boe 26.87 26.19 33.07 26.24
per unit - basic 1.12 1.20 5.64 4.76
Unit-based compensation 4,694 2,809 11,049 7,351
per boe 0.96 0.58 0.57 0.38
Depreciation, depletion and
accretion 69,000 60,659 266,271 232,722
per boe 14.07 12.43 13.68 12.14
Income taxes (reduction) 23,324 (30,831) 49,451 (535)
per boe 4.76 (6.32) 2.54 (0.03)
Net income 129,192 63,631 438,366 218,187
per boe 26.35 13.04 22.52 11.39
per unit - basic 1.09 0.60 3.84 2.07
Distributions declared 85,824 77,136 332,540 307,401
per unit 0.90 0.90 3.60 3.60
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Production - For the year ended December 31, 2008, production increased 1% to
53,190 boe per day when compared to 52,505 boe per day for the same period a
year ago. Specifically, average natural gas production increased 2% to 175 mmcf
per day in 2008 from 171 mmcf per day for the same period a year ago, while
total oil and liquids production increased slightly to 24,079 bbls per day in
2008 (comprised of 17,440 bbls per day of light and medium oil and 6,639 bbls
per day of heavy oil) from 24,034 bbls per day (comprised of 16,486 bbls per day
of light and medium oil and 7,548 bbls per day of heavy oil) for the same period
in 2007. For the fourth quarter of 2008, production increased slightly to 53,288
boe per day when compared to 53,029 boe per day for the same period in 2007.
Natural gas production remained relatively unchanged at 171 mmcf per day in the
fourth quarter of 2008 from 170 mmcf per day for the same period a year ago,
while total oil and liquids production decreased marginally to 24,733 bbls per
day in the fourth quarter of 2008 (comprised of 18,120 bbls per day of light and
medium oil and 6,613 bbls per day of heavy oil) from 24,775 bbls per day
(comprised of 16,825 bbls per day of light and medium oil and 7,950 bbls per day
of heavy oil) for the same period in 2007. Both oil and natural gas volumes were
adversely impacted by approximately 900 boe per day in the quarter due to
unusually cold weather in December and weaker heavy oil prices resulting in some
heavy oil production being shut in. This being said, Bonavista's diversified
commodity investment approach minimizes our dependence on any one product. We
anticipate production volumes in 2009 to average between 51,500 and 52,500 boe
per day. Our current production is approximately 53,000 boe per day consisting
of 55% natural gas, 34% light and medium oil and 11% heavy oil.
Production revenues - Production revenues for the year ended December 31, 2008
increased by 35% to $1,234.4 million when compared to $911.3 million for the
same period a year ago, primarily due to higher average commodity prices. For
the year ended December 31, 2008, natural gas prices increased 19% to $8.30 per
mcf, when compared to $6.95 per mcf realized in the same period in 2007. The
average oil and liquids price also increased 30% to $70.68 per bbl (comprised of
$71.70 per bbl for light and medium oil and $68.01 per bbl for heavy oil) for
the year ended December 31, 2008 from $54.40 per bbl (comprised of $58.61 per
bbl for light and medium oil and $45.20 per bbl for heavy oil) for the same
period in 2007. Production revenues, for the fourth quarter of 2008 decreased by
8% to $221.8 million when compared to $242.4 million for the same period a year
ago due to lower average oil and liquids prices offset somewhat by higher
natural gas prices. In the fourth quarter of 2008, natural gas prices increased
12% to $7.52 per mcf, compared to $6.74 per mcf realized in the same period in
2007, although the average oil and liquids price decreased 9% to $53.05 per bbl
(comprised of $52.90 per bbl for light and medium oil and $53.47 per bbl for
heavy oil) in the fourth quarter of 2008 from $58.04 per bbl (comprised of
$62.32 per bbl for light and medium oil and $48.99 per bbl for heavy oil) for
the same period in 2007.
The following table highlights Bonavista's realized commodity pricing for the
three months and year ended December 31:
Three Months ended Years ended
December 31, December 31,
2008 2007 2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Natural gas ($/mcf):
Production revenues $ 7.30 $ 6.63 $ 8.29 $ 6.87
Realized gains (losses) on
financial instruments 0.22 0.11 0.01 0.08
----------------------------------------
7.52 6.74 8.30 6.95
----------------------------------------
----------------------------------------
Light and medium oil ($/bbl):
Production revenues 48.06 66.98 81.40 59.70
Realized gains (losses) on
financial instruments 4.84 (4.66) (9.70) (1.09)
----------------------------------------
52.90 62.32 71.70 58.61
----------------------------------------
----------------------------------------
Heavy oil ($/bbl):
Production revenues 43.76 48.24 76.08 44.93
Realized gains (losses) on
financial instruments 9.71 0.75 (8.07) 0.27
----------------------------------------
$ 53.47 $ 48.99 $ 68.01 $ 45.20
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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 primarily 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, 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. For the same period in 2007, our risk
management program on financial instruments resulted in a net loss of $45.7
million, consisting of a realized loss of $665,000 and an unrealized loss of
$45.1 million. The realized loss of $665,000 consisted of a $5.2 million gain on
natural gas commodity derivative contracts and a $5.9 million loss on crude oil
commodity derivative contracts. For the three months ended December 31, 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. For the similar period in
2007, our risk management program on financial instruments resulted in a net
loss of $36.5 million consisting of a realized loss of $5.0 million and an
unrealized loss of $31.5 million. The realized loss of $5.0 million consisted of
a $1.7 million gain on natural gas commodity derivative contracts and a $6.7
million loss on crude oil commodity derivative contracts.
Commodity price risk is the risk that the fair value of future cash flows will
fluctuate as a result of changes in commodity prices. Commodity prices for crude
oil and natural gas are impacted not only by global economic events that dictate
the levels of supply and demand but also by the relationship between the
Canadian and United States dollar. The Trust has attempted to mitigate a portion
of the commodity price risk through the use of various financial instruments and
physical delivery sales contracts. The Trust's policy is to enter into commodity
price contracts when considered appropriate to a maximum of 60% of net after
royalty, forecasted production volumes.
i) Financial instruments:
As at December 31, 2008, the Trust has hedged by way of costless collars to sell
natural gas and crude oil as follows:
----------------------------------------------------------------------------
Volume Average Price Term
----------------------------------------------------------------------------
10,000 gjs/d CDN$ 9.25 - CDN$ 13.50 - AECO January 1, 2009 -
March 31, 2009
10,000 gjs/d CDN$ 7.50 - CDN$ 9.50 - AECO April 1, 2009 -
October 31, 2009
5,000 mmbtu/d US$ 6.81 - US$ 7.91 - AECO January 1, 2009 -
March 31, 2009
1,000 bbls/d CDN$ 70.00 - CDN$ 78.00 - Bow River January 1, 2009 -
December 31, 2009
3,000 bbls/d CDN$ 81.67 - CDN$ 121.33 - WTI January 1, 2009 -
December 31, 2009
2,000 bbls/d US$ 65.00 - US$ 80.50 - WTI January 1, 2009 -
March 31, 2009
1,000 bbls/d US$ 85.00 - US$ 105.60 - WTI January 1, 2009 -
December 31, 2009
2,000 bbls/d CDN$ 105.00 - CDN$ 169.00 - WTI April 1, 2009 -
December 31, 2009
----------------------------------------------------------------------------
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, 2008 the fair
market value recorded on the consolidated balance sheet for these financial
instruments was an asset of $76.2 million, compared to a liability of $45.1
million in 2007. These financial instruments had the following gains and losses
reflected in the consolidated statements of operations, comprehensive income and
accumulated earnings:
----------------------------------------------------------------------------
Years ended December 31,
2008 2007
----------------------------------------------------------------------------
Realized gains (losses) on financial instruments $ (80,806) $ (665)
Unrealized gains (losses) on financial instruments 121,261 (45,058)
----------------------------------------------------------------------------
$ 40,455 $ (45,723)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Bonavista mitigates its risk associated with fluctuations in commodity prices by
utilizing financial instruments. A $0.10 increase or a $0.10 decrease to the
price per thousand cubic feet of natural gas - AECO would have an impact of
approximately $5.2 million and $5.4 million respectively, on net income for
those financial instruments that were in place as at December 31, 2008. A $1.00
increase or a $1.00 decrease to the price per barrel of oil - WTI would have an
impact of approximately of $5.1 million and $2.6 million respectively, on net
income for those financial instruments that were in place as at December 31,
2008.
ii) Physical purchase contracts:
As at December 31, 2008, the Trust has entered into direct sale costless collars
to sell natural gas as follows:
----------------------------------------------------------------------------
Volume Average Price (CDN$ - AECO) Term
----------------------------------------------------------------------------
40,000 gjs/d $ 8.16 - $ 10.69 January 1, 2009 - March 31, 2009
10,000 gjs/d $ 8.00 - $ 10.84 April 1, 2009 - October 31, 2009
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Physical purchase contracts are being accounted for as they are settled.
Royalties - For the year ended December 31, 2008, royalties increased 54% to
$240.0 million from $155.6 million for the same period a year ago, largely
attributed to an increase in commodity prices and increased heavy oil royalties
resulting from the payout of two oilsands royalty projects. In addition,
royalties as a percentage of revenues (including realized gains and losses on
financial instruments) for 2008 increased to 20.8% compared to 17.1% in 2007 for
similar reasons discussed above and the impact of realized losses on financial
instruments. For the year ended December 31, 2008, royalties by product as a
percentage of revenues (including realized gains and losses on financial
instruments) were 21.9% for natural gas, 19.3% for light and medium oil and
21.4% for heavy oil. For the year ended December 31, 2007, royalties by product
as a percentage of revenues (including realized gains and losses on financial
instruments) were 17.6% for natural gas, 16.8% for light and medium oil and
16.0% for heavy oil. For the three months ended December 31, 2008, royalties
decreased by 7% to $39.8 million from $42.8 million for the same period a year
ago largely due to declining oil and liquids prices. In addition, royalties as a
percentage of revenues (including realized gains and losses on financial
instruments) for the fourth quarter of 2008 decreased from 18.0% in 2007 to
16.6%, for the same reasons as discussed above and the impact of realized gains
on financial instruments. For the three months ended December 31, 2008,
royalties by product as a percentage of revenues (including realized gains and
losses on financial instruments) were 19.9% for natural gas, 12.8% for light and
medium oil and 15.2% for heavy oil. For the three months ended December 31,
2007, royalties by product as a percentage of revenues (including realized gains
and losses on financial instruments) were 18.1% for natural gas, 17.8% for light
and medium oil and 18.4% for heavy oil.
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. The Trust does not anticipate a significant benefit in
2009 given that its current wells converted to the NRF effective January 1,
2009. The Trust has reviewed the NRF and has determined that its impact will
change the Trust's corporate forecast royalty rate over the life of the reserves
by less than 1% as compared to the royalty rates that would have been calculated
with the royalty regime in place during 2008 based on benchmark pricing as at
December 31, 2008.
Operating expenses - Operating expenses for the year ended December 31, 2008
increased 13% to $184.1 million compared to $162.4 million for the same period a
year ago. Operating expenses for the fourth quarter of 2008 increased 16% to
$48.6 million compared to $41.9 million for the same period a year ago.
Operating expenses increased due to the continuation of industry wide operating
cost pressures, primarily driven by higher fuel, power, trucking, chemical and
labour costs. These factors resulted in average per unit operating expenses
increasing by 12% to $9.45 per boe for the year ended December 31, 2008, from
$8.47 per boe in the comparable period of 2007. For 2008, operating expenses by
product were $1.35 per mcf for natural gas, $10.07 per bbl for light and medium
oil and $13.69 per bbl for heavy oil compared to $1.17 per mcf for natural gas,
$9.16 per bbl for light and medium oil and $12.36 per bbl for heavy oil for the
same period in 2007. For the three months ended December 31, 2008, operating
expenses per boe increased 16% to $9.91 per boe from $8.58 per boe in the
comparable period of 2007. Operating expenses by product for the fourth quarter
of 2008 were $1.44 per mcf for natural gas, $10.38 per bbl for light and medium
oil and $14.07 per bbl for heavy oil compared to $1.16 per mcf for natural gas,
$9.31 per bbl for light and medium oil and $12.72 per bbl for heavy oil for the
same period in 2007. Notwithstanding these cost increases, Bonavista continues
to experience one of the lowest operating costs of any producer in the energy
trust sector and remains optimistic that the recent upward trend in operating
costs will reverse in 2009.
Transportation expenses - For the year ended December 31, 2008, transportation
expenses decreased 6% to $38.7 million ($1.99 per boe) when compared to $41.4
million ($2.16 per boe) for 2007. The 8% decrease in transportation expenses on
a per boe basis was primarily due to a decrease in natural gas transportation
costs because of the expiry of certain firm export service obligations offset by
slightly higher trucking costs for our oil and liquids. For similar reasons,
transportation costs for the three months ended December 31, 2008 decreased 7%
to $9.6 million ($1.96 per boe) compared to $10.4 million ($2.12 per boe) for
the same period a year ago. Transportation expenses by product for the year
ended December 31, 2008 were $0.38 per mcf for natural gas, $0.85 per bbl for
light and medium oil and $3.64 per bbl for heavy oil compared to $0.44 per mcf
for natural gas, $0.92 per bbl for light and medium oil and $3.18 per bbl for
heavy oil for the same period in 2007. For the fourth quarter of 2008
transportation expenses by product were $0.36 per mcf for natural gas, $0.86 per
bbl for light and medium oil and $4.05 per bbl for heavy oil compared to $0.43
per mcf for natural gas, $0.86 per bbl for light and medium oil and $3.19 per
bbl for heavy oil for the same period a year ago.
General and administrative expenses - General and administrative expenses, after
overhead recoveries, increased 8% to $14.4 million for the year ended December
31, 2008 from $13.3 million in the same period in 2007 and increased 6% to $3.8
million for the three months ended December 31, 2008 from $3.6 million in the
same period in 2007. On a per boe basis, general and administrative expenses
increased 6% for the year ended December 31, 2008 to $0.74 per boe from $0.70
per boe in the same period in 2007 and increased 5% for the three months ended
December 31, 2008 to $0.78 per boe from $0.74 per boe in the same period in
2007. These increases are largely due to the higher costs of personnel required
to manage our operations and increasing cost pressures currently experienced
throughout our industry.
In addition, through the services agreement with NuVista Energy Ltd.,
("NuVista") Bonavista provides certain administrative activities. The fee
charged under this agreement was $1.1 million for the year ended December 31,
2008 as compared to $1.4 million in the same period in 2007 and $26,000 for the
three months ended December 31, 2008 as compared to $400,000 for the same period
in 2007. The fees charged to NuVista through the services agreement was
terminated effective November 1, 2008.
In connection with its Trust Unit Incentive Rights and Restricted Trust Unit
Plans, Bonavista recorded a unit-based compensation charge of $11.0 million and
$4.7 million for the year and three months ended December 31, 2008 respectively,
compared to $7.4 million and $2.8 million for the same periods in 2007.
Financing expenses - Financing expenses, which include interest expense on
long-term debt and convertible debentures, decreased 8% to $32.5 million for the
year ended December 31, 2008, from $35.2 million for the same period in 2007 and
on a boe basis, decreased 9% to $1.67 per boe for the year ended December 31,
2008 from $1.84 per boe for the same period in 2007. This decrease is due to
lower average debt levels used to fund Bonavista's capital program, proceeds
received from a $214.0 million equity financing and a declining interest rate
environment. For the three months ended December 31, 2008, financing expenses
decreased 47% to $5.8 million from $10.9 million for the same period in 2007 and
on a boe basis decreased 47% to $1.18 per boe for the three months ended
December 31, 2008 from $2.24 per boe in the same period in 2007 for similar
reasons as discussed above. For the year ended December 31, 2008, Bonavista paid
cash interest of $32.9 million compared to $35.4 million for the same period in
2007. During the fourth quarter of 2008, Bonavista paid cash interest of $6.4
million compared to $11.3 million in 2007. Bonavista's effective interest rate
as at December 31, 2008 was approximately 2% (2007 - 5%).
Depreciation, depletion and accretion expenses - Depreciation, depletion and
accretion expenses increased 14% to $266.3 million for the year ended December
31, 2008 from $232.7 million for the same period of 2007. For the three months
ended December 31, 2008 depreciation, depletion and accretion expenses also
increased 14% to $69.0 million from $60.7 million in the same period in 2007.
Both increases were due to higher costs of finding, developing and acquiring
reserves and a larger asset base in 2008. For the year ended December 31, 2008,
the average cost increased to $13.68 per boe from $12.14 per boe for the same
period in 2007 and for the three months ended December 31, 2008 the average cost
increased to $14.07 per boe from $12.43 per boe for the same period a year ago.
The increase in depreciation, depletion and accretion expenses is due to
increased costs associated with adding new reserves. Over the past few years our
industry has seen cost escalation in all areas of our activities.
Income taxes - For the year ended December 31, 2008, the provision for income
tax was $49.5 million compared to a recovery of $535,000 for the same period in
2007. For the three months ended December 31, 2008, the provision for income tax
was $23.3 million compared to a recovery of $30.8 million for the same period in
2007. Bonavista made no cash payments relating to installments for either of the
year ended and three months ended December 31, 2008, or for the comparative
periods in 2007.
On February 26, 2008, the Federal government announced that the provincial
component of the SIFT tax is to be determined based on the general corporate
provincial tax rate in each province that the Trust has a permanent
establishment. On June 18, 2008, the legislation to re-define the provincial
component of the tax rate was passed. The specific rules governing how the
provincial component is to be calculated was released in draft on July 14, 2008,
however, it is not considered to be substantively enacted as at December 31,
2008. As a result, any changes in the tax rate for the Trust's future income tax
has not been reflected in the Trust's consolidated financial statements.
Funds from operations, net income and comprehensive income - For the year ended
December 31, 2008, Bonavista experienced a 28% increase in funds from operations
to $643.9 million ($5.64 per unit, basic) from $502.8 million ($4.76 per unit,
basic) for the same period in 2007, primarily due to higher commodity prices.
For the three months ended December 31, 2008, Bonavista experienced a 3%
increase in funds from operations to $131.7 million ($1.12 per unit, basic) from
$127.8 million ($1.20 per unit, basic) for the same period in 2007, primarily
due to the impact of realized gains on financial instruments as they offset
declining oil and liquids pricing. Net income for the year ended December 31,
2008, increased 101% to $438.4 million ($3.84 per unit, basic) from $218.2
million ($2.07 per unit, basic) for the same period in 2007. For the three
months ended December 31, 2008, net income increased 103% to $129.2 million
($1.09 per unit, basic) from $63.6 million ($0.60 per unit, basic) for the same
period in 2007.
Other comprehensive income for the year ended December 31, 2008 included a
charge of nil (2007 - $6.0 million) relating to the amortization of the amount
recognized in accumulated other comprehensive income on January 1, 2007 for the
fair value of financial instruments on adoption of the new accounting standards
for financial instruments. This resulted in a total comprehensive income for the
year ended December 31, 2008 of $438.4 million (2007 - $212.2 million). Other
comprehensive income for the three months ended December 31, 2008 included a
charge of nil (2007 - $2.5 million) relating to the amortization of the amount
recognized in accumulated other comprehensive income on January 1, 2007 for the
fair value of financial instruments on adoption of the new accounting standards
for financial instruments. This resulted in total comprehensive income for the
three months ended December 31, 2008 of $129.2 million (2007 - $61.1 million).
The following table is a reconciliation of a non-GAAP measure, funds from
operations, to its nearest measure prescribed by GAAP:
----------------------------------------------------------------------------
Three months ended Years ended
December 31, December 31,
Calculation of Funds From Operations: 2008 2007 2008 2007
----------------------------------------------------------------------------
(thousands)
Cash flow from operating activities $ 141,448 $ 95,459 $678,228 $473,021
Asset retirement expenditures 5,061 4,784 15,229 8,338
Changes in non-cash working capital (14,768) 27,535 (49,581) 21,424
----------------------------------------------------------------------------
Funds from operations $ 131,741 $127,778 $643,876 $502,783
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital expenditures - Capital expenditures for the year ended December 31, 2008
were $482.3 million, consisting of $305.5 million on exploitation and
development spending and $176.8 million on net property acquisitions. For the
same period in 2007 capital expenditures were $366.4 million, consisting of
$267.7 million on exploitation and development spending and $98.7 million on net
property acquisitions. Capital expenditures for the three month period ended
December 31, 2008 were $60.1 million, consisting of $60.2 million on
exploitation and development spending and $105,000 on net property dispositions.
For the same period in 2007 capital expenditures were $58.0 million, consisting
of $58.4 million on exploitation and development spending and $425,000 on net
property dispositions. Our consistent exploitation and development program
continues to generate predictable and attractive re-investment efficiencies
despite the current high cost environment.
The following table outlines capital expenditures by category for the years
ended December 31, 2008 and 2007:
----------------------------------------------------------------------------
Years ended December 31,
2008 2007
----------------------------------------------------------------------------
(thousands)
Land acquisitions $ 26,165 $ 33,211
Geological and geophysical 10,687 9,811
Drilling and completion 176,361 139,578
Production equipment and facilities 91,138 84,444
Other 1,163 616
----------------------------------------------------------------------------
Exploitation and development expenditures 305,514 267,660
Acquisitions 187,023 100,806
Dispositions (10,240) (2,110)
----------------------------------------------------------------------------
Net capital expenditures $ 482,297 $ 366,356
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liquidity and capital resources - As at December 31, 2008, long-term debt
including working capital (excluding unrealized gains on financial instruments
and related tax impact) was $654.5 million with a debt to 2008 annualized fourth
quarter funds from operations ratio of 1.2:1. Bonavista has significant
flexibility to finance future expansions of its capital programs or acquisition
opportunities as they arise, through the use of its bank loan facility of $1.0
billion of which $345.5 million is unused borrowing capability and the use of
its funds from operations, or through a combination of both bank debt and funds
from operations.
Bonavista's bank loan facility is provided by a syndicate of 12 domestic and
international banks. The bank loan facility is a three year revolving facility
and may at the request of the Trust and with the consent of the lenders be
extended on an annual basis. On August 25, 2008, Bonavista and its lenders
agreed to extend its bank loan facility to August 10, 2011 with no principal
repayments required until then. This facility also includes an accordion feature
providing that at any time 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 facility, 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, 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, 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 2009, Bonavista plans to invest between $225 and $250 million on its capital
programs to expand its core regions. Given the current global economic weakness
and the constraints in both the equity and credit environments, the Trust along
with all other oil and gas entities have restricted access to capital and
potentially increased borrowing costs. The Trust intends on financing its 2009
capital program with a combination of funds from operations and to the extent
required, its existing credit facility. The Trust is committed to the
fundamental principle of maintaining financial flexibility and the prudent use
of debt, as such, our 2009 capital program is based upon using a conservative
amount of debt in our financing structure.
Unitholders' equity - As at December 31, 2008, Bonavista had 118.1 million
equivalent trust units outstanding. This includes 11.4 million exchangeable
shares, which are exchangeable into 22.3 million trust units. The exchange ratio
in effect at December 31, 2008 for exchangeable shares was 1.96225:1. As at
March 2, 2009, Bonavista had 118.8 million equivalent trust units outstanding.
This includes 10.2 million exchangeable shares, which are exchangeable into 20.6
million trust units. The exchange ratio in effect at March 2, 2009 for
exchangeable shares was 2.02089:1. In addition, Bonavista has 4.3 million trust
unit incentive rights outstanding at March 2, 2009, with an average exercise
price of $22.52 per trust unit.
As at December 31, 2008, Unitholders' equity included $933,000 for the ascribed
value of the conversion feature of the convertible debentures. This amount was
determined at the time the debentures were issued and was subsequently reduced
by the amounts attributed to debentures that have been converted into trust
units. Of the 100,000, 7.5% convertible debentures issued on January 29, 2004,
there have been 93,401 of these debentures converted into trust units, leaving
6,599 debentures with a principal amount of $6.6 million outstanding as at
December 31, 2008. On December 31, 2004, the Trust issued 135,000, 6.75%
convertible debentures in conjunction with a property acquisition in British
Columbia. The original issue of these debentures had a principal amount of
$135.0 million, and from the date of issuance to December 31, 2008 there have
been 96,433 of these debentures converted into trust units, leaving 38,567
debentures outstanding with a principal amount of $38.6 million.
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 paramount objectives of the Trust is to be a
sustainable entity, which is defined as maintaining both production and reserves
over an extended period of time. 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, 2008 the Trust declared
distributions of $332.5 million ($3.60 per trust unit) compared to $307.4
million ($3.60 per trust unit) in the same period in 2007. For the three months
ended December 31, 2008 the Trust declared distributions of $85.8 million ($0.90
per trust unit) compared to $77.1 million ($0.90 per trust unit) in the same
period in 2007. 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, 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 year and three months ended December 31,
2008, the non-cash charges amounted to $205.5 million and $2.5 million
respectively compared to $284.6 million and $64.1 million for the same periods
in 2007. 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.
----------------------------------------------------------------------------
Three Months ended Years ended
December 31, December 31,
Distribution Analysis 2008 2007 2008 2007
----------------------------------------------------------------------------
(thousands)
Cash flow provided from operating
activities $ 141,448 $ 95,459 $678,228 $ 473,021
Net income 129,192 63,631 438,366 218,187
Distributions declared 85,824 77,136 332,540 307,401
Excess of cash flow provided from
operating activities over
distributions declared 55,624 18,323 345,688 165,620
Excess (shortfall) of net income
over distributions declared 43,368 (13,505) 105,826 (89,214)
----------------------------------------------------------------------------
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 $0.20 per unit, however, due to persistent weak natural gas prices, we
are reducing our monthly distribution policy to $0.16 per unit starting for the
production month of March 2009 and payable on April 15, 2009. Our long-term
objective is to distribute approximately 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 distribution rate of $0.16 per unit per month starting with March production
will place us slightly below this range for 2009, assuming current strip prices
are realized.
Quarterly financial information - The following table highlights Bonavista's
performance for the eight quarterly periods ending on March 31, 2007 to December
31, 2008:
----------------------------------------------------------------------------
2008
-----------------------------------------------------
December 31 September 30 June 30 March 31
-----------------------------------------------------
($ thousands, except
per unit amounts)
Production revenues 221,782 354,667 361,555 296,387
Net income 129,192 207,594 29,282 72,298
Net income per unit:
Basic 1.09 1.77 0.26 0.67
Diluted 1.09 1.75 0.26 0.67
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007
-----------------------------------------------------
December 31 September 30 June 30 March 31
-----------------------------------------------------
($ thousands, except
per unit amounts)
Production revenues 242,361 219,885 223,878 225,222
Net income 63,631 58,990 33,936 61,630
Net income per unit:
Basic 0.60 0.56 0.32 0.59
Diluted 0.59 0.55 0.32 0.59
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Production revenues over the past eight quarters has fluctuated between a low of
$219.9 million in September 2007 to a high of $361.6 million in June 2008,
largely due to the volatility of commodity prices as our volumes have remained
relatively constant throughout the last two years. Net income in the past eight
quarters has fluctuated from a low of $29.3 million in June 2008 to a high of
$207.6 million in September 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 increased 103% in the fourth quarter of
2008 as compared to the fourth quarter of 2007. The increase in net income in
the fourth quarter of 2008 is attributed to a $112.0 million gain on financial
instruments consisting of a $17.5 million realized gain and an unrealized gain
of $94.5 million as compared to a $36.5 million loss consisting of a $5.0
million realized loss and an unrealized loss of $31.5 million in the same period
in 2007. The large decrease in net income in the second quarter of 2007 is
primarily attributable to the non-cash future income tax charge to net income of
$41.0 million to reflect changes to income tax legislation, substantially
enacted in the second quarter of 2007.
Disclosure and internal controls - Disclosure controls and procedures have been
designed to ensure that information required 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 filings, that Bonavista's disclosure controls and procedures are
effectively designed to provide reasonable assurance that material information
related to the issuer is made known to them by others within the Trust. It
should be noted that while the Trust's Chief Executive Officer and Chief
Financial Officer believe that the disclosure controls and procedures provide a
reasonable level of assurance that they are effective, they do not expect that
the disclosure controls and procedures or internal control over financial
reporting will prevent all errors and fraud. A control system, no matter how
well conceived or operated, can provide only reasonable, not absolute, assurance
that the objective of the control system is met.
Update on regulatory and financial reporting matters - On August 15, 2008, the
Canadian Securities Administrators published its final version of National
Instrument 52-109 and is effective for the Trust's 2008 year end reporting. The
national instrument includes the certification of the operating effectiveness of
internal controls over financial reporting ("ICFR"), requires the use of a
control framework to design and evaluate internal controls, provides specific
guidance regarding the documentation, testing and evaluation of controls, and
provides clarification regarding the definition of material weaknesses and
conclusions on disclosure controls and procedures when there is a material
weakness in ICFR. Bonavista has concluded that the Trust's internal controls
over financial reporting was effective as of December 31, 2008.
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"). Canadian generally
accepted accounting principles as we currently know them, will cease to exist
for all publicly reporting entities. Currently, the application of IFRS to the
oil and gas industry in Canada requires considerable clarification. The Canadian
Securities Administrators are in the process of examining changes to securities
rules as a result of this initiative. Bonavista has completed a preliminary
analysis of the accounting differences and has plans in place to perform a
detailed assessment of the impact of IFRS on our results of operations,
financial position and disclosures in 2009.
Effective January 1, 2008, Bonavista adopted Canadian Institute of Chartered
Accountants ("CICA") Section 3862, "Financial Instruments - Disclosures",
Section 3863, "Financial Instruments - Presentation" and Section 1535, "Capital
Disclosure". The first two sections establish standards for the presentation and
disclosure of information that enables users to evaluate the significance of
financial instruments to the entity's financial position, and the nature and
extent of risks arising from financial instruments and how the entity manages
the risks. The last section establishes standards for disclosing information
about an entity's capital and how it is managed. The Trust will also be required
to adopt Section 3064 "Goodwill and Intangible Assets" effective January 1,
2009, which defines the criteria for the recognition of intangible assets.
Environmental matters - On February 19, 2008 the government of British Columbia
introduced a consumer-based carbon tax that became effective on July 1, 2008.
The Trust is required to pay carbon tax on all fuel used in the province of
British Columbia through its normal course of operations. As at December 31,
2008 Bonavista has paid $223,000 with respect to the carbon tax.
OUTLOOK
As we enter our twelfth year since restructuring the Company in 1997, and our
sixth year since converting to an energy trust, we continue to benefit from all
of the same qualities that drove the success of Bonavista as a public company
and an energy trust. We apply a similar proven strategy and execute this
strategy in a disciplined and cost-effective manner much the same as in 1997
when we started on our mission of creating value for our investors. The
foundation of this strategy is to actively pursue low to medium risk drilling
opportunities on our extensive undeveloped land base within geographically
concentrated areas of operations. Despite a very active exploitation and
development program over the past few years, the quality and quantity of our
drilling opportunities continues to improve as we enter 2009. Bonavista has
currently identified approximately 700 drilling prospects on its land base and
remains flexible to consider accelerating or decelerating the capital program
depending on market conditions. This steady increase in our quality of prospects
generated over the past several years can be directly attributed to the detailed
and tireless work of our talented technical team, who possess a strong
commitment and a solid understanding of the Western Canadian Sedimentary Basin.
We also continue to search and have been successful in strategic acquisition
opportunities where we can add value utilizing our own technical expertise. Our
timely and prudent approach to capital investments has been very effective in
the past, and together with our steadfast commitment to adding Unitholder value
and attention to detail, will continue to provide the foundation for the future
success of the Trust. Today our activity, efficiency, productivity and
profitability remain among the strongest levels in our eleven year history.
For 2009, given the current instability of commodity prices and the developments
in the global economies stemming from the credit crisis, Bonavista has revised
its capital budget to between $225 and $250 million, to be invested in our
exploitation, development and acquisition programs. It is anticipated that this
level of capital expenditures will result in the drilling of between 100 and 115
wells and production levels to average between 51,500 and 52,500 boe per day,
which is a modest decrease compared to 2008. Our development program includes
the drilling of 50 high-impact horizontal wells with multi-stage fracs targeted
in the Bakken, Glauconite, Viking and Notikewin formations. Bonavista believes
that recent new drilling and completion technologies will have a significant
impact on our vast land holdings in our core regions and will lead to the
development of several resource-type plays. We will closely monitor our capital
programs and remain opportunistic to reallocate or expand our capital program on
additional property or land acquisitions and/or drilling opportunities as
conditions evolve. In the meantime, our conservative approach to spending and
distributions will preserve our financial strength and should serve our
unitholders well in this uncertain environment.
We are extremely proud of our achievements over the past eleven years and
despite some short term commodity weakness, we remain enthusiastic about the
future and the growing opportunities that exist for Bonavista. We would like to
thank our employees for their significant effort and their continued enthusiasm
and perseverance as we pursue these opportunities in this uncertain economic
environment. Despite the setbacks we have endured over the past couple of years,
such as 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 market,
Bonavista's commitment and value creation process has not changed. Throughout
many business cycles and changes in the business environment, Bonavista has
converted adversity into opportunity and has emerged an even stronger entity as
a result of this attitude. Our success is based on the consistent application of
our core philosophy and operating strategies. Our legal structure may ultimately
change by 2011 when the new tax laws become effective, but our steadfast
commitment to creating shareholder value will not change in any environment. Our
team remains committed to this over the long term, regardless of the changing
landscape.
BONAVISTA ENERGY TRUST
Consolidated Balance Sheets
----------------------------------------------------------------------------
----------------------------------------------------------------------------
December 31, December 31,
(thousands) 2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(unaudited)
Assets:
Current assets:
Accounts receivable $ 106,116 $ 112,226
Unrealized gains on financial instruments 76,203 -
Future income tax asset - 13,517
----------------------------------------------------------------------------
182,319 125,743
Oil and natural gas properties and equipment 2,319,600 2,074,993
Goodwill 41,321 41,321
----------------------------------------------------------------------------
$ 2,543,240 $ 2,242,057
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities and Unitholders' Equity:
Current liabilities:
Accounts payable and accrued liabilities $ 143,093 $ 65,305
Distributions payable 28,731 25,729
Unrealized losses on financial instruments - 45,058
Future income tax 22,221 -
----------------------------------------------------------------------------
194,045 136,092
Long-term debt 588,792 712,654
Convertible debentures 43,711 48,830
Asset retirement obligations 127,467 116,893
Future income taxes 177,253 166,621
Unitholders' equity:
Unitholders' capital and debenture
conversion component 1,100,768 851,685
Exchangeable shares 69,488 74,710
Contributed surplus 10,687 9,369
Accumulated earnings 231,029 125,203
----------------------------------------------------------------------------
1,411,972 1,060,967
----------------------------------------------------------------------------
$ 2,543,240 $ 2,242,057
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
BONAVISTA ENERGY TRUST
Consolidated Statements of Operations, Comprehensive Income and Accumulated
Earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(thousands, except per unit Three months ended Years ended
amounts) December 31, December 31,
2008 2007 2008 2007
----------------------------------------------------------------------------
(unaudited)
Revenues:
Production $ 221,782 $242,361 $1,234,391 $ 911,346
Royalties (39,801) (42,809) (239,967) (155,586)
----------------------------------------------------------------------------
181,981 199,552 994,424 755,760
----------------------------------------------------------------------------
Realized gains (losses) on
financial instruments 17,538 (5,008) (80,806) (665)
Unrealized gains (losses) on
financial instruments 94,469 (31,510) 121,261 (45,058)
----------------------------------------------------------------------------
293,988 163,034 1,034,879 710,037
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Expenses:
Operating 48,603 41,867 184,053 162,371
Transportation 9,589 10,364 38,744 41,397
General and administrative 3,825 3,620 14,410 13,335
Financing 5,761 10,915 32,535 35,209
Unit-based compensation 4,694 2,809 11,049 7,351
Depreciation, depletion and
accretion 69,000 60,659 266,271 232,722
----------------------------------------------------------------------------
141,472 130,234 547,062 492,385
----------------------------------------------------------------------------
Income before taxes 152,516 32,800 487,817 217,652
Income taxes (reductions) 23,324 (30,831) 49,451 (535)
----------------------------------------------------------------------------
Net income 129,192 63,631 438,366 218,187
Changes in comprehensive
income, net of taxes - (2,512) - (5,994)
----------------------------------------------------------------------------
Comprehensive income 129,192 61,119 438,366 212,193
----------------------------------------------------------------------------
Accumulated earnings, beginning
of period 187,661 138,708 125,203 214,417
Distributions declared (85,824) (77,136) (332,540) (307,401)
----------------------------------------------------------------------------
Accumulated earnings, end of
period $ 231,029 $125,203 $ 231,029 $ 125,203
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income per unit - basic $ 1.09 $ 0.60 $ 3.84 $ 2.07
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income per unit - diluted $ 1.09 $ 0.59 $ 3.80 $ 2.06
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
BONAVISTA ENERGY TRUST
Consolidated Statements of Cash Flows
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(thousands, except per unit Three months ended Years ended
amounts) December 31, December 31,
2008 2007 2008 2007
----------------------------------------------------------------------------
(unaudited)
Cash provided by (used in):
Operating Activities:
Net income $ 129,192 $ 63,631 $ 438,366 $218,187
Items not requiring cash from
operations:
Depreciation, depletion and
accretion 69,000 60,659 266,271 232,722
Unit-based compensation 4,694 2,809 11,049 7,351
Unrealized (gains) losses on
financial instruments (94,469) 31,510 (121,261) 45,058
Future income taxes (reductions) 23,324 (30,831) 49,451 (535)
Asset retirement expenditures (5,061) (4,784) (15,229) (8,338)
Changes in non-cash working
capital items 14,768 (27,535) 49,581 (21,424)
----------------------------------------------------------------------------
141,448 95,459 678,228 473,021
----------------------------------------------------------------------------
Financing Activities:
Issuance of equity, net of issue
costs 560 964 223,152 8,144
Distributions (85,427) (77,079) (329,538) (307,125)
Changes in long-term debt 23,587 43,704 (123,862) 200,331
Changes in non-cash working
capital items (607) (405) (344) (164)
----------------------------------------------------------------------------
(61,887) (32,816) (230,592) (98,814)
----------------------------------------------------------------------------
Investing Activities:
Exploitation and development (60,236) (58,440) (305,514) (267,660)
Property acquisitions (3,247) (1,585) (187,023) (100,806)
Property dispositions 3,352 2,010 10,240 2,110
Changes in non-cash working
capital items (19,430) (4,628) 34,661 (7,851)
----------------------------------------------------------------------------
(79,561) (62,643) (447,636) (374,207)
----------------------------------------------------------------------------
Change in cash - - - -
Cash, beginning of period - - - -
----------------------------------------------------------------------------
Cash, end of period $ - $ - $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
BONAVISTA ENERGY TRUST
Notes to Consolidated Financial Statements
For the year ended December 31, 2008 (unaudited)
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
6) 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. Changes in accounting policies:
a) Financial instruments:
On January 1, 2008, the Trust adopted CICA Handbook Section 3862, "Financial
Instruments - Disclosures", and Section 3863, "Financial Instruments -
Presentation". Section 3862 and 3863 establish standards for the presentation
and disclosure of information that enable users to evaluate the significance of
financial instruments to the entity's financial position, and the nature and
extent of risks arising from financial instruments and how the entity manages
these risks. The implementation of these standards did not impact the Trust's
financial results, however it did result in additional disclosure presented in
note 7 of the Trust's notes to the consolidated financial statements.
b) Capital disclosures:
On January 1, 2008, the Trust adopted CICA Handbook Section 1535 "Capital
Disclosures". Section 1535 establishes standards for disclosing information
about an entity's capital and how it is managed. This section specifies
disclosure about objectives, policies and processes for managing capital,
quantitative data about what an entity regards as capital, whether an entity has
complied with all capital requirements, and if it has not complied, the
consequences of such non-compliances. The implementation of this standard did
not impact the Trust's financial results, however it did result in additional
disclosure presented in note 8 of the Trust's notes to the consolidated
financial statements.
c) Goodwill:
As of January 1, 2009, the Trust will be required to adopt CICA Handbook Section
3064 "Goodwill and Intangible Assets", which defines the criteria for the
recognition of intangible assets. This new standard is not expected to have a
material impact on the Trust's consolidated financial statements.
d) 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 has plans in place to perform a detailed assessment
of the impact of IFRS on our results of operations, financial position and
disclosures.
2. 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 are also officers of Bonavista.
Pursuant to the Plan of Arrangement, Bonavista entered into a Technical Services
Agreement ("TSA") with NuVista, whereby, Bonavista received payment for certain
technical and administrative services provided by it to NuVista on a cost
recovery basis. Effective January 1, 2007 the terms of the TSA were amended to
reflect the reduced level of services provided by Bonavista and subsequently on
August 31, 2007 the TSA was terminated and replaced with a new services
agreement. This new services agreement was subsequently terminated as of
November 1, 2008.
For the three months ended December 31, 2008, Bonavista charged NuVista $26,000
(2007 - $400,000) in fees relating to general and administrative services
provided to NuVista, in addition, NuVista charged Bonavista management fees for
a jointly owned partnership totaling $337,500 (2007 - $337,500). For the year
ended December 31, 2008 Bonavista charged NuVista $1.1 million (2007 - $1.4
million) in fees relating to general and administrative services provided to
NuVista, in addition NuVista charged Bonavista management fees for a jointly
owned partnership totaling $1.4 million (2007 - $1.4 million). For the year
ended December 31, 2008, NuVista also credited Bonavista $209,000 (2007 -
$618,000) for interest, relating to the cash balance within the jointly owned
partnership. As at December 31, 2008, the amount payable to NuVista was $1.2
million, as at December 31, 2007 the amount receivable from NuVista was
$703,000.
3. 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 $587.0 million (2007 - $540.9 million) which will be incurred over
the next 51 years. The majority of the costs will be incurred between 2010 and
2037. A credit-adjusted risk-free rate of 7.5% (2007 - 7.5%) and an inflation
rate of 2% (2007 - 2%) were used to calculate the fair value of the asset
retirement obligations.
A reconciliation of the asset retirement obligations is provided below:
----------------------------------------------------------------------------
Years ended December 31,
2008 2007
----------------------------------------------------------------------------
(thousands)
Balance, beginning of year $ 116,893 $ 96,324
Accretion expense 8,577 7,333
Liabilities incurred 9,177 1,629
Liabilities acquired 2,746 3,976
Liabilities settled (15,229) (8,338)
Change in assumptions 5,303 15,969
----------------------------------------------------------------------------
Balance, end of year $ 127,467 $ 116,893
----------------------------------------------------------------------------
----------------------------------------------------------------------------
4. Long-term debt:
The Trust has a $1.0 billion credit facility with a syndicate of chartered
banks. This facility is an unsecured, covenant-based, extendible revolving
facility and includes a $50 million working capital facility. The facility
provides that advances may be made by way of prime rate loans, bankers'
acceptances and/or US dollar LIBOR advances. These advances bear interest at the
banks' prime rate and/or at money market rates plus a stamping fee. The facility
is a three year revolving credit and may, at the request of the Trust with the
consent of the lenders, be extended on an annual basis. On August 25, 2008 the
facility was extended to August 10, 2011 with no principal payments required
until then. This facility also includes 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 facility, 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, 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, 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, 2008 include interest on bank
loans of $29.3 million (2007 - $31.6 million) and convertible debentures of $3.2
million (2007 - $3.6 million). For the year ended December 31, 2008, Bonavista
paid cash interest of $32.9 million (2007 - $35.4 million). For the year ending
December 31, 2008 our effective interest rate was 3.9% (2007 - 5.3%).
5. 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. The
following table sets out the convertible debenture activities to December 31,
2008:
----------------------------------------------------------------------------
Debt Equity
Component Component
----------------------------------------------------------------------------
(thousands)
Balance, December 31, 2007 $ 48,830 $ 1,054
Accretion 57 -
Issue expenses related to conversions to trust
units 42 -
Amortization of issue expenses 684 -
Conversion to trust units (5,902) (121)
----------------------------------------------------------------------------
Balance, December 31, 2008 $ 43,711 $ 933
----------------------------------------------------------------------------
----------------------------------------------------------------------------
6. Unitholders' equity:
a) Authorized:
Unlimited number of voting trust units.
b) Issued and outstanding:
(i) Trust units:
----------------------------------------------------------------------------
Number of
Units Amount
----------------------------------------------------------------------------
(thousands)
Balance, December 31, 2007 85,757 $ 850,631
Issued for cash 7,000 214,200
Issued on conversion of convertible debentures 215 5,902
Issued on conversion of exchangeable shares 1,632 5,222
Issued upon exercise of trust unit incentive
rights 1,099 19,958
Conversion of restricted trust units 67 -
Issue costs, related to debenture conversions - (43)
Issue costs, net of future tax benefit - (7,924)
Adjustment to equity component of debenture on
conversion - 121
Unit-based compensation - 11,768
----------------------------------------------------------------------------
Balance, December 31, 2008 95,770 $ 1,099,835
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(ii) Contributed surplus:
----------------------------------------------------------------------------
Amount
----------------------------------------------------------------------------
(thousands)
Balance, December 31, 2007 $ 9,369
Unit-based compensation expense 11,049
Unit-based compensation capitalized 2,037
Exercise of trust unit incentive rights and conversion of
restricted trust units (11,768)
----------------------------------------------------------------------------
Balance, December 31, 2008 $ 10,687
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(iii) Exchangeable shares:
----------------------------------------------------------------------------
Number Amount
----------------------------------------------------------------------------
(thousands)
Balance, December 31, 2007 12,230 $ 74,710
Exchanged for trust units (855) (5,222)
----------------------------------------------------------------------------
Balance, December 31, 2008 11,375 $ 69,488
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Exchange ratio, December 31, 2008 1.96225 -
----------------------------------------------------------------------------
Trust units issuable on exchange 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 will allow 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.
c) Long term incentive plans:
For the three months ended December 31, 2008 there were 8,740 restricted trust
units granted and 116,980 trust unit incentive rights issued with an average
exercise price of $26.41 per trust unit and an estimated fair value of $9.07 per
trust unit. As at December 31, 2008 there were 150,573 restricted units
outstanding and 3,208,795 trust unit rights outstanding with an average exercise
price of $25.88 per trust unit. 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%; volatility of 35%; a forfeiture rate of 10% and an expected life of
4.5 years.
d) 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:
----------------------------------------------------------------------------
Three months ended
December 31, 2008
----------------------------------------------------------------------------
(thousands)
Trust units 95,033
Exchangeable shares converted at the exchange ratio 23,032
----------------------------------------------------------------------------
Basic equivalent trust units 118,065
Convertible debentures 1,617
Trust unit incentive rights 73
Restricted trust units 150
----------------------------------------------------------------------------
Diluted equivalent trust units 119,905
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the purposes of calculating net income per trust unit on a diluted basis,
the net income has been increased by $1.0 million (2007 - $1.1 million) with
respect to the accretion, amortization and interest expense on the convertible
debentures.
7. 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.
The Board of Directors has overall responsibility for the establishment and
oversight of the Trust's risk management framework. The Board has implemented
and monitors compliance with risk management policies. The Trust's risk
management policies are established to identify and analyze the risks faced by
the Trust, to set appropriate risk limits and controls, and to monitor risks and
adherence to market conditions and the Trust's activities.
(a) Credit risk:
Credit risk is the risk of financial loss to the Trust if a customer or
counterparty to a financial instrument fails to meet its contractual
obligations. The Trust is exposed to credit risk with respect to its accounts
receivable and commodity price risk contracts. A majority of the Trusts accounts
receivable relate to oil and natural gas sales which are exposed to typical
industry credit risks. The Trust manages this risk by entering into sales
contracts with established creditworthy entities along with reviewing our
exposure to these entities on a quarterly basis. The Trust also reduces its
credit risk of commodity prices risk contracts by entering into agreements with
counterparties that are either i) part of our existing banking syndicate or ii)
have an investment grade rating.
Substantially all of the Trust's crude oil and natural gas production is
marketed under standard industry terms. Receivables from crude oil and natural
gas marketers are normally collected on the 25th day of the month following
production. The Trust's policy to mitigate credit risk associated with these
balances is to establish marketing relationships with large credit worthy
purchasers and to sell through multiple purchasers. The Trust historically has
not experienced any collection issues with its crude oil and natural gas
marketers. Joint venture receivables are typically collected within three months
of the joint venture bill being issued to the partner. The Trust attempts to
mitigate the risk from joint venture receivables by obtaining partner approval
of significant capital expenditures prior to the expenditure. However, the
receivables are from participants in the crude oil and natural gas sector, and
collection of the outstanding balances can be impacted by industry factors such
as commodity price fluctuations, limited capital availability and unsuccessful
drilling programs. The Trust does not typically obtain collateral from crude oil
and natural gas marketers or joint venture partners; however the Trust does have
the ability in most cases to withhold production from joint venture partners in
the event of non-payment.
The carrying amount of accounts receivable represents the maximum credit
exposure. As at December 31, 2008 the Trust's receivables consisted of $65.1
million of receivables from crude oil and natural gas marketers which has
substantially been collected, $23.8 million from joint venture partners of which
$6.3 million has been subsequently collected, and $17.2 million of Crown
deposits and prepaid expenses. As at December 31, 2008 the Trust has $9.8
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, 2008 and did not provide for any doubtful accounts nor was it
required to write-off any receivables during the period ended December 31, 2008.
(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 4, which may, at the request of
the Trust with the consent of the lenders, be extended on an annual basis. The
Trust also has two series of convertible debentures outstanding. The 7.5%
debentures have a conversion price of $23.00 per trust unit, maturing on June
30, 2009 and the 6.75% debentures have a conversion price of $29.00 per trust
unit, maturing on June 30, 2010. The Trust may elect to satisfy the principal
obligation of these debentures by issuing trust units to the holders of the
debentures. The Trust also maintains and monitors a certain level of cash flow
which is used to partially finance all operating, investing and capital
expenditures.
(c) Market risk:
Market risk is the risk that changes in market conditions, such as commodity
prices, interest rates, and foreign exchange rates, will affect the Trust's net
income or the value of financial instruments. The objective of market risk
management is to manage and control market risk exposures within acceptable
limits, while maximizing the Trust's returns.
The Trust utilizes both financial instruments and physical delivery sales
contracts to manage market risks. All such transactions are conducted in
accordance with the Trust's risk management policy that has been approved by the
Board of Directors.
Commodity price risk is the risk that the fair value of future cash flows will
fluctuate as a result of changes in commodity prices. Commodity prices for crude
oil and natural gas are impacted not only by global economic events that dictate
the levels of supply and demand but also by the relationship between the
Canadian and United States dollar. The Trust has attempted to mitigate a portion
of the commodity price risk through the use of various financial instruments and
physical delivery sales contracts. The Trust's policy is to enter into commodity
price contracts when considered appropriate to a maximum of 60% of net after
royalty, forecasted production volumes.
i) Financial instruments:
As at December 31, 2008, the Trust has hedged by way of costless collars to sell
natural gas and crude oil as follows:
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Volume Average Price Term
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10,000 gjs/d CDN$ 9.25 - CDN$ 13.50 - AECO January 1, 2009 -
March 31, 2009
10,000 gjs/d CDN$ 7.50 - CDN$ 9.50 - AECO April 1, 2009 -
October 31, 2009
5,000 mmbtu/d US$ 6.81 - US$ 7.91 - AECO January 1, 2009 -
March 31, 2009
1,000 bbls/d CDN$ 70.00 - CDN$ 78.00 - Bow River January 1, 2009 -
December 31, 2009
3,000 bbls/d CDN$ 81.67 - CDN$ 121.33 - WTI January 1, 2009 -
December 31, 2009
2,000 bbls/d US$ 65.00 - US$ 80.50 - WTI January 1, 2009 -
March 31, 2009
1,000 bbls/d US$ 85.00 - US$ 105.60 - WTI January 1, 2009 -
December 31, 2009
2,000 bbls/d CDN$ 105.00 - CDN$ 169.00 - WTI April 1, 2009 -
December 31, 2009
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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, 2008 the fair
market value recorded on the consolidated balance sheet for these financial
instruments was an asset of $76.2 million, compared to a liability of $45.1
million in 2007. These financial instruments had the following gains and losses
reflected in the consolidated statements of operations, comprehensive income and
accumulated earnings:
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Years ended December 31,
2008 2007
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Realized gains (losses) on financial instruments $ (80,806) $ (665)
Unrealized gains (losses) on financial instruments 121,261 (45,058)
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$ 40,455 $ (45,723)
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Bonavista mitigates its risk associated with fluctuations in commodity prices by
utilizing financial instruments. A $0.10 increase or a $0.10 decrease to the
price per thousand cubic feet of natural gas - AECO would have an impact of
approximately $5.2 million and $5.4 million respectively, on net income for
those financial instruments that were in place as at December 31, 2008. A $1.00
increase or a $1.00 decrease to the price per barrel of oil - WTI would have an
impact of approximately of $5.1 million and $2.6 million respectively, on net
income for those financial instruments that were in place as at December 31,
2008.
ii) Physical purchase contracts:
As at December 31, 2008, the Trust has entered into direct sale costless collars
to sell natural gas as follows:
----------------------------------------------------------------------------
Volume Average Price (CDN$ - AECO) Term
----------------------------------------------------------------------------
40,000 gjs/d $ 8.16 - $ 10.69 January 1, 2009 - March 31, 2009
10,000 gjs/d $ 8.00 - $ 10.84 April 1, 2009 - October 31, 2009
----------------------------------------------------------------------------
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, 2008.
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 three
and twelve months ended December 31, 2008 would have a $1.1 million and $5.0
million impact respectively. For similar periods in 2007 net income would be
impacted by approximately $1.3 million and $4.6 million respectively. The
sensitivity impact is higher for the year ended in 2008 because of higher
weighted average bank debt compared to the year ended December 31, 2007,
notwithstanding that the weighted average interest rate is lower in 2008
compared to the same period in 2007. The Trust had no interest rate swap or
financial contracts in place as at or during the period ended December 31, 2008.
Fair value of financial instruments
The Trust's financial instruments as at December 31, 2008 and December 31, 2007
include accounts receivable, derivative contracts, accounts payable,
distributions payable and accrued liabilities, convertible debentures and bank
debt. The fair value of accounts receivable, accounts payable, distributions
payable and accrued liabilities approximate their carrying amounts due to their
short-terms to maturity.
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, 2008, the fair market value of these financial
instruments was a gain of approximately $76.2 million. For the similar period in
2007 the fair market value of these financial instruments was a deficiency of
$45.1 million.
Fair market value of the convertible debentures as at December 31, 2008 is $44.4
million (2007 - $52.5 million), as determined by its most recent closing trading
price.
Bank debt bears interest at a floating market rate and accordingly the fair
market value approximates the carrying value.
8. 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 no more 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, 2008, the Trust's ratio of net debt to annualized funds from
operations was 1.2 to 1 (2007 -1.4 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 4 of the consolidated
financial statements.
There has been no change in the Trust's approach to capital management during
the period ended December 31, 2008.
INVESTOR INFORMATION
Bonavista Energy Trust is a natural gas weighted energy trust which is committed
to maintaining its emphasis on operating high quality oil and natural gas
properties, delivering consistent distributions to unitholders and ensuring
financial strength and sustainability.
Corporate information provided herein contains forward-looking information. The
reader is cautioned that assumptions used in the preparation of such
information, particularly those pertaining to cash distributions, production
volumes, commodity prices, operating costs and drilling results, which are
considered reasonable by Bonavista at the time of preparation, may be proven to
be incorrect. Actual results achieved during the forecast period will vary from
the information provided herein and the variations may be material. There is no
representation by Bonavista that actual results achieved during the forecast
period will be the same in whole or in part as those forecast.
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