Bonavista Energy Trust (TSX:BNP.UN) is pleased to report to unitholders its
interim consolidated financial and operating results for the three and nine
months ended September 30, 2008.
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Highlights
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Three months Nine months
ended September 30, ended September 30,
2008 2007 2008 2007
----------------------------------------------------------------------------
Financial
($ thousands, except per unit)
Production revenues 354,667 219,885 1,102,609 668,985
Funds from operations (1) 173,091 120,382 512,135 375,005
Per unit (1) (2) 1.48 1.14 4.54 3.57
Distributions declared 84,859 76,972 246,716 230,265
Per unit 0.90 0.90 2.70 2.70
Percentage of funds from
operations (1) 49% 64% 48% 61%
Net income 207,594 58,990 309,174 154,556
Per unit (2) 1.77 0.56 2.74 1.47
Total assets 2,488,447 2,188,154
Long-term debt, including
working capital deficiency 648,572 690,093
Long-term debt, net of
adjusted working capital (3) 635,785 683,121
Unitholders' equity 1,361,847 1,072,264
Capital expenditures:
Exploitation and development 89,847 50,889 245,278 209,220
Acquisitions, net 2,743 98,311 176,888 99,121
Weighted average outstanding
equivalent trust units:
(thousands) (2)
Basic 117,032 105,983 112,889 105,132
Diluted 119,439 108,405 115,313 107,729
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Operating
(boe conversion - 6:1 basis)
Production:
Natural gas (mmcf/day) 177 171 176 171
Oil and liquids (bbls/day) 23,912 24,938 23,860 23,784
Total oil equivalent
(boe/day) 53,473 53,382 53,157 52,328
Product prices: (4)
Natural gas ($/mcf) 8.21 5.86 8.56 7.02
Oil and liquids ($/bbl) 80.31 56.36 76.82 53.12
Operating expenses ($/boe) 9.56 8.51 9.30 8.44
General and administrative
expenses ($/boe) 0.73 0.71 0.73 0.68
Cash costs ($/boe) (5) 11.72 11.15 11.86 10.82
Operating netback ($/boe) (6) 37.34 27.16 37.73 28.63
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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
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.
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Three months ended
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Trust Unit Trading September 30, June 30, March 31, December 31,
Statistics 2008 2008 2008 2007
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($ per unit, except volume)
High 37.65 37.64 31.35 31.85
Low 25.01 28.96 24.24 24.14
Close 26.29 37.45 29.85 28.50
Average Daily Volume - Units 273,074 329,638 231,949 275,892
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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 three and nine months ended September 30, 2008. Bonavista has continued
on its course of generating profitable results since commencing operations as an
energy trust in July 2003. The continued execution of Bonavista's proven
strategies in the third quarter of 2008 are a testament to the validity and
effectiveness of an operationally and technically focused energy trust. The
third quarter results for 2008 are also highlighted by an active drilling
program, which has led to continued success in several of our key areas.
Bonavista plans to spend approximately $475 million in 2008 on its conventional
drilling and acquisition programs, drilling approximately 210 wells, and
forecasts production of approximately 53,500 boe per day. In addition, in 2008
Bonavista plans to invest up to $15 million in both resource land purchases and
the application of new technology towards longer term resource play development.
Bonavista is well positioned for the future given our significant financial
flexibility and opportunity rich land base within the Western Canadian
Sedimentary Basin.
Other significant 2008 accomplishments for Bonavista include:
- Operationally, production volumes averaged 53,473 boe per day during the third
quarter of 2008. Production volumes averaged 53,157 boe per day for the nine
months ended September 30, 2008 a 2% increase compared to the 52,328 boe per day
for the same period in 2007;
- Maintained an active capital program during the third quarter of 2008. In the
quarter, Bonavista invested $89.8 million in exploitation and development
activities by drilling 74 wells with an overall 95% success rate. In addition,
Bonavista spent $2.7 million on net acquisitions within our core regions. For
the nine months ended September 30, 2008, Bonavista invested $245.3 million in
exploitation and development activities, drilling 171 wells with an overall 94%
success rate and completed 15 core area acquisitions for $176.9 million;
- Drilled 23 successful horizontal wells, year to date, on the highly
prospective, light oil Bakken trend in our Southeast Saskatchewan area resulting
in production reaching 1,400 bbls per day from 17 completed and producing wells.
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 a $169.0 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 third quarter of
2007 and our pre-existing assets in this area where we have recently experienced
tremendous success utilizing new technology. We now have a concentrated position
in this area with current production of approximately 5,800 boe per day and
numerous exploitation and optimization opportunities to pursue in the future;
- Continued to actively participate at crown land sales and freehold purchases,
investing $22.1 million in land activity, further enhancing our future drilling
prospect inventory to more than three years;
- Generated funds from operations of $173.1 million ($1.48 per unit) in the
third quarter of 2008 and $512.1 million ($4.54 per unit) for the nine months
ended September 30, 2008. Of the total funds from operations generated in the
respective periods, Bonavista distributed 49% of these funds in the third
quarter and 48% of these funds for the nine months ended September 30, 2008 back
to Unitholders with the remaining funds reinvested in the business to continue
growing our production base;
- Continued to record strong profitability in both the third quarter and the
nine months ended September 30, 2008 with a strong average return on equity of
31% and 32% respectively, and a strong net income to funds from operations ratio
in both periods of 57%. The above ratios reflect net income adjusted to negate
the after tax impact of the unrealized gains and losses on financial
instruments;
- As a result of weaker commodity prices and recent global market events,
Bonavista currently has an attractive cash-on-cash yield of 17%. In addition,
since inception as a Trust, Bonavista has delivered cumulative distributions of
$1.4 billion or $18.21 per trust unit. These cumulative distributions are in
excess of our initial closing trading price of $15.85 on the day we became an
energy trust on July 2, 2003;
- On April 29, 2008 Bonavista completed a $214.0 million equity financing which
improves financial flexibility to pursue future growth opportunities through
expansions in our drilling and acquisitions programs. Current third quarter
annualized funds from operations stands at a ratio of 0.9:1 compared to the
quarter end debt level; and
- On August 25, 2008, Bonavista extended its financial covenant-based $1.0
billion syndicated bank loan facility to August 10, 2011. 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.
Strengths of Bonavista Energy Trust
Since restructuring into an energy trust in July 2003, Bonavista has maintained
a high level of investment activity on its asset base, growing production by
over 50% since that time. This activity stems from the operational and technical
focus of our Trust 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 53% in
favour of natural gas and 47% 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.
Bonavista is also pleased to announce the following senior management
appointments with Mr. Jason Skehar, our current Vice President, Production
promoted to President and Chief Operating Officer, Mr. Johannes Thiessen our
current Vice President, Exploration promoted to Senior Vice President,
Exploration and Mr. Thomas Mullane our current Vice President, Engineering
promoted to Senior Vice President, Engineering. Each of Messrs. Skehar,
Thiessen, and Mullane are long serving employees of Bonavista who have
contributed significantly to our success. Mr. Keith MacPhail will remain fully
engaged in the company's activities and continue to provide leadership to
Bonavista in his role as Chairman and Chief Executive Officer.
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 oil and natural gas
operations, corporate governance and 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
November 6, 2008. Our audited consolidated financial statements, Annual Report,
and other disclosure documents for 2007 are available 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 and (ix) interest expense per boe,
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 therefrom. 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 first nine
months of 2008 led to the drilling of 171 wells in our four core regions with an
overall success rate of 94%. This program resulted in 64 natural gas wells, 97
oil wells and 10 dry holes. Bonavista continues to pursue deeper, higher impact
drilling opportunities particularly in the Bakken play in our Southeast
Saskatchewan area and Lower Mannville sands in our Central region in Alberta,
where we have experienced excellent success and attractive finding and
development costs over the past couple of 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 15 complementary acquisitions in its core regions
during the first nine months of 2008.
Production - For the third quarter of 2008, production remained relatively
unchanged at 53,473 boe per day when compared to 53,382 boe per day for the same
period in 2007. Natural gas production increased 4% to 177 mmcf per day in the
third quarter of 2008 from 171 mmcf per day for the same period a year ago,
while total oil and liquids production decreased 4% to 23,912 bbls per day in
the third quarter of 2008 (comprised of 17,237 bbls per day of light and medium
oil and 6,675 bbls per day of heavy oil) from 24,938 bbls per day (comprised of
16,967 bbls per day of light and medium oil and 7,971 bbls per day of heavy oil)
for the same period in 2007. Our current production is approximately 54,500 boe
per day consisting of 53% natural gas, 34% light and medium oil and 13% heavy
oil. Production for the nine months ended September 30, 2008, increased 2% to
53,157 boe per day when compared to 52,328 boe per day for the same period in
2007. Natural gas production increased 3% to 176 mmcf per day in the first nine
months of 2008 from 171 mmcf per day for the same period a year ago, while total
oil and liquids production increased slightly to 23,860 bbls per day in the
first nine months of 2008 (comprised of 17,212 bbls per day of light and medium
oil and 6,648 bbls per day of heavy oil) from 23,784 bbls per day (comprised of
16,372 bbls per day of light and medium oil and 7,412 bbls per day of heavy oil)
for the same period in 2007. Bonavista's diversified commodity investment
approach minimizes our dependence on any one product. We anticipate production
volumes in 2008 to average approximately 53,500 boe per day.
Production revenues - Production revenues for the third quarter of 2008
increased by 61% to $354.7 million when compared to $219.9 million in the third
quarter of 2007, primarily due to higher average commodity prices. In the third
quarter of 2008, natural gas prices increased 47% to $8.33 per mcf, when
compared to $5.68 per mcf realized in the same period in 2007. The average oil
and liquids price increased to $99.48 per bbl (comprised of $99.92 per bbl for
light and medium oil and $98.35 per bbl for heavy oil) in the third quarter of
2008 from $56.97 per bbl (comprised of $61.28 per bbl for light and medium oil
and $47.80 per bbl for heavy oil) for the same period in 2007. Production
revenues, for the nine months ended September 30, 2008 increased by 51% to
$1,012.6 million when compared to $669.0 million for the same period a year ago
due to higher average commodity prices and increased production volumes. For the
nine month period ended September 30, 2008, natural gas prices increased 24% to
$8.62 per mcf, compared to $6.94 per mcf realized in the same period in 2007.
The average oil and liquids price increased 73% to $91.43 per bbl (comprised of
$93.19 per bbl for light and medium oil and $86.87 per bbl for heavy oil) for
the nine month period ended September 30, 2008 from $52.99 per bbl (comprised of
$57.18 per bbl for light and medium oil and $43.73 per bbl for heavy oil) for
the same period in 2007.
The following table highlights Bonavista's realized commodity pricing for the
three and nine months ended September 30:
Three months Nine months
ended September 30, ended September 30,
2008 2007 2008 2007
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Natural gas ($/mcf):
Production revenues $ 8.33 $ 5.68 $ 8.62 $ 6.94
Realized gains (losses) on
financial instruments (0.12) 0.18 (0.06) 0.08
-----------------------------------------
8.21 5.86 8.56 7.02
-----------------------------------------
Light and medium oil ($/bbl):
Production revenues 99.92 61.28 93.19 57.18
Realized gains (losses) on
financial instruments (18.65) (1.01) (14.85) 0.14
-----------------------------------------
81.27 60.27 78.34 57.32
-----------------------------------------
Heavy oil ($/bbl):
Production revenues 98.35 47.80 86.87 43.73
Realized gains (losses) on
financial instruments (20.50) 0.23 (14.00) 0.10
-----------------------------------------
$ 77.85 $ 48.03 $ 72.87 $ 43.83
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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 using costless collars limits Bonavista's exposure to downturns in
commodity prices, while allowing for participation in commodity price increases.
In the third quarter of 2008, our risk management program on financial
instruments resulted in a net gain of $110.4 million, consisting of a realized
loss of $44.1 million and an unrealized gain of $154.5 million. The realized
loss of $44.1 million consisted of a $1.9 million loss on natural gas commodity
derivative contracts and a $42.2 million loss on crude oil commodity derivative
contracts. For the nine months ended September 30, 2008, our risk management
program on financial instruments resulted in a net loss of $71.6 million
consisting of a realized loss of $98.4 million and an unrealized gain of $26.8
million. The realized loss of $98.4 million consisted of a $2.8 million loss on
natural gas commodity derivative contracts and a $95.6 million loss on crude oil
commodity derivative contracts. A summary of commodity price risk management
contracts in place as at September 30, 2008 is included in note 7 of the
consolidated financial statements.
Royalties - For the three months ended September 30, 2008, royalties increased
96% to $69.7 million from $35.5 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 revenue (including realized gains and losses on
financial instruments) for the third quarter of 2008 increased to 22.4% compared
to 16.1% in 2007 for similar reasons discussed above and the result of realized
losses on financial instruments. For the three months ended September 30, 2008,
royalties by product as a percentage of revenues (including realized gains and
losses on financial instruments) were 23.1% for natural gas, 20.7% for light and
medium oil and 25.3% for heavy oil. In the third quarter of 2007, royalties by
product as a percentage of revenue (including realized gains and losses on
financial instruments) were 15.4% for natural gas, 16.6% for light and medium
oil and 16.1% for heavy oil. For the nine months ended September 30, 2008,
royalties also increased significantly by 77% to $200.2 million from $112.8
million for the same period a year ago, for similar reasons discussed above. In
addition, royalties as a percentage of revenue (including realized gains and
losses on financial instruments) for the nine month period also increased from
16.7% in 2007 to 21.9% in 2008, for the same reasons as discussed above. For the
nine months ended September 30, 2008, royalties by product as a percentage of
revenue (including realized gains and losses on financial instruments) were
22.5% for natural gas, 20.8% for light and medium oil and 22.9% for heavy oil.
For the nine months ended September 30, 2007, royalties by product as a
percentage of revenues (including realized gains and losses on financial
instruments) were 17.4% for natural gas, 16.5% for light and medium oil and
15.1% for heavy oil.
On October 25, 2007, the Alberta Government announced the New Royalty Framework
("NRF") which is proposed to take effect on January 1, 2009. The proposed NRF
includes new royalty formulas for conventional oil and natural gas that will
operate on sliding scales that are determined by commodity prices and well
productivity. The Government of Alberta, on April 10, 2008, provided some
further clarification on the NRF and introduced two new royalty programs related
to the development of deep oil and natural gas reserves. The Trust has reviewed
the information that is currently available and has determined that the impact
of these changes may increase our existing average corporate royalty rate up to
5%, based on benchmark pricing as at September 30, 2008.
Operating expenses - Operating expenses for the third quarter of 2008 increased
13% to $47.1 million compared to $41.8 million for the same period a year ago.
Operating costs increased primarily 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
costs increasing by 12% for the three months ended September 30, 2008, to $9.56
per boe from $8.51 per boe in the comparable period of 2007. Operating costs by
product for the third quarter of 2008 were $1.37 per mcf for natural gas, $10.18
per bbl for light and medium oil and $13.93 per bbl for heavy oil compared to
$1.17 per mcf for natural gas, $9.19 per bbl for light and medium oil and $12.39
per bbl for heavy oil for the same period in 2007. For the nine months ended
September 30, 2008 operating expenses increased 12% to $135.5 million compared
to $120.5 million for the same period a year ago. The increase in operating
costs are for similar reasons noted above. Average per unit operating costs
increased 10% for the nine months ended September 30, 2008, to $9.30 per boe
from $8.44 per boe in the comparable period of 2007. Operating costs by product
for the first nine months of 2008 were $1.32 per mcf for natural gas, $9.95 per
bbl for light and medium oil and $13.56 per bbl for heavy oil compared to $1.18
per mcf for natural gas, $9.11 per bbl for light and medium oil and $12.23 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 subside in 2009.
Transportation expenses - For the three months ended September 30, 2008,
transportation expenses decreased 5% to $10.1 million ($2.06 per boe) when
compared to $10.6 million ($2.16 per boe) for the same period last year. The 5%
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. For similar reasons, transportation costs for
the nine months ended September 30, 2008 decreased 6% to $29.2 million ($2.00
per boe) compared to $31.0 million ($2.17 per boe) for the same period a year
ago. Transportation expenses by product for the third quarter of 2008 were $0.39
per mcf for natural gas, $0.85 per bbl for light and medium oil and $3.86 per
bbl for heavy oil compared to $0.44 per mcf for natural gas, $0.87 per bbl for
light and medium oil and $3.14 per bbl for heavy oil for the third quarter of
2007. For the first nine months of 2008 transportation expenses by product were
$0.39 per mcf for natural gas, $0.85 per bbl for light and medium oil and $3.50
per bbl for heavy oil compared to $0.44 per mcf for natural gas, $0.94 per bbl
for light and medium oil and $3.17 per bbl for heavy oil for the same period a
year ago.
General and administrative expenses - General and administrative expenses, after
overhead recoveries, increased 4% to $3.6 million for the three months ended
September 30, 2008 from $3.5 million in the same period in 2007 and increased 9%
to $10.6 million for the nine months ended September 30, 2008 from $9.7 million
in the same period in 2007. On a per boe basis, general and administrative
expenses increased 3% for the three months ended September 30, 2008 to $0.73 per
boe from $0.71 per boe in the same period in 2007 and increased 7% for the nine
months ended September 30, 2008 to $0.73 per boe from $0.68 per boe in the same
period in 2007. These increases are largely due to the higher staffing levels
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 $330,000 for the three
months ended September 30, 2008 as compared to $360,000 in the same period in
2007 and $1.1 million for the nine months ended September 30, 2008 as compared
to $1.0 million for the same period in 2007. The fees charged to NuVista through
the services agreement will decrease in the following quarter as most
administrative services provided to NuVista will cease to exist as of November
1, 2008. In connection with its Trust Unit Incentive Rights Plan, Bonavista also
recorded a unit-based compensation charge of $1.6 million and $6.4 million for
the three and nine months ended September 30, 2008 respectively, compared to
$1.7 million and $4.5 million for the same periods in 2007.
Financing expenses - Financing expenses, which include interest expense on
long-term debt and convertible debentures, decreased 27% to $7.0 million for the
three months ended September 30, 2008, from $9.5 million for the same period in
2007 and on a boe basis, decreased 27% to $1.42 per boe for the three months
ended September 30, 2008 from $1.94 per boe for the same period in 2007. This
decrease in financing expenses is primarily due to the proceeds received from a
$214.0 million equity financing used to reduce long-term debt. For the nine
months ended September 30, 2008, financing expenses increased 10% to $26.8
million from $24.3 million for the same period in 2007 and on a boe basis
increased 8% to $1.84 per boe for the nine months ended September 30, 2008 from
$1.70 per boe in the same period in 2007. This increase is due to increased
average debt levels used to fund Bonavista's capital program. During the third
quarter of 2008, Bonavista paid cash interest of $6.4 million compared to $9.0
million in 2007. For the nine months ended September 30, 2008, Bonavista paid
cash interest of $26.5 million compared to $24.1 million for the same period in
2007.
Depreciation, depletion and accretion expenses - Depreciation, depletion and
accretion expenses increased 13% to $67.9 million for the three months ended
September 30, 2008 from $60.1 million in the same period of 2007. For the nine
months ended September 30, 2008 depreciation, depletion and accretion expenses
also increased 15% to $197.3 million from $172.1 million. Both increases were
due to higher costs of finding and developing reserves and a larger asset base
in 2008. For the three months ended September 30, 2008, the average cost
increased to $13.80 per boe from $12.23 per boe for the same period in 2007 and
for the nine months ended September 30, 2008 the average cost increased to
$13.55 per boe from $12.04 per boe for the same period a year ago. The increase
in depreciation, depletion and accretion expenses are due to increased costs
associated with adding new reserves. Over the past few years our industry has
seen cost escalation in all areas of activities.
Income taxes - For the three months ended September 30, 2008, the provision for
income tax was $50.5 million compared to a reduction of $4.8 million for the
same period in 2007. For the nine months ended September 30, 2008, the provision
for income tax was $26.1 million compared to $30.3 million for the same period
in 2007. Bonavista made no cash payments relating to installments for either of
the three or nine months ended September 30, 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 September 30,
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 three
months ended September 30, 2008, Bonavista experienced a 44% increase in funds
from operations to $173.1 million ($1.48 per unit, basic) from $120.4 million
($1.14 per unit, basic) for the same period in 2007. For the nine month period
ended September 30, 2008, Bonavista experienced a 37% increase in funds from
operations to $512.1 million ($4.54 per unit, basic) from $375.0 million ($3.57
per unit, basic) for the same period in 2007. Funds from operations increased
for the three and nine months ended September 30, 2008 primarily due to higher
commodity prices. Net income for the three months ended September 30, 2008,
increased 252% to $207.6 million ($1.77 per unit, basic) from $59.0 million
($0.56 per unit, basic) for the same period in 2007. For the nine months ended
September 30, 2008, net income increased 100% to $309.2 million ($2.74 per unit,
basic) from $154.6 million ($1.47 per unit, basic) for the same period in 2007.
Other comprehensive income for the three months ended September 30, 2008
included a charge of nil (2007 - $781,000) 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 three months ended September 30, 2008 of $207.6 million (2007 -
$58.2 million). Other comprehensive income for the nine months ended September
30, 2008 included a charge of nil (2007 - $3.5 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 nine months ended September 30, 2008 of $309.2
million (2007 - $151.1 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
September 30,
Calculation of Funds From Operations: 2008 2007
----------------------------------------------------------------------------
(thousands)
Cash flow from operating activities $ 191,437 $ 128,685
Asset retirement expenditures 3,046 2,081
Changes in non-cash working capital (21,392) (10,384)
----------------------------------------------------------------------------
Funds from operations $ 173,091 $ 120,382
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital expenditures - Capital expenditures for the three month period ended
September 30, 2008 were $92.6 million, consisting of $89.8 million on
exploitation and development spending and $2.8 million on net property
acquisitions. For the same period in 2007 capital expenditures were $149.2
million, consisting of $50.9 million on exploitation and development spending
and $98.3 million on net property acquisitions. Capital expenditures for the
nine month period ended September 30, 2008 were $422.2 million, consisting of
$245.3 million on exploitation and development spending and $176.9 million on
net property acquisitions. For the same period in 2007 capital expenditures were
$308.3 million, consisting of $209.2 million on exploitation and development
spending and $99.1 million on net property acquisitions. Our consistent
exploitation and development program continues to generate predictable and
attractive re-investment efficiencies in the current service cost environment.
Liquidity and capital resources - As at September 30, 2008, long-term debt
including working capital (excluding unrealized losses on financial instruments
and related tax impact), was $635.8 million with a debt to 2008 annualized funds
from operations ratio of 0.9:1. Bonavista has significant flexibility to finance
future expansions of its capital programs or acquisition opportunities as they
arise, through the use of its bank credit facility of $1.0 billion of which
$364.2 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 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 credit facility to August 10, 2011 with no principal repayments
required until then. In addition the lenders approved to increase the bank loan
facility by $250 million on the participation of any existing or additional
lenders.
Under the terms of the credit facility, the Trust has provided the covenant that
its consolidated senior debt borrowing will not exceed three times net income
before interest, taxes and depreciation, depletion and accretion; consolidated
total debt will not exceed three and one half times consolidated net income
before interest, taxes and depreciation, depletion and accretion; and
consolidated senior debt borrowing will not exceed one-half of consolidated
total debt plus consolidated unitholders' equity of the Trust.
In 2008, Bonavista plans to invest approximately $490 million on its capital
programs to expand its core regions, which will be financed through a
combination of funds from operations, recent equity issuance and bank debt. The
Trust is committed to the fundamental principle of maintaining financial
flexibility and the prudent use of debt. As such, the 2008 capital expenditure
program is based on using a conservative amount of debt in our financing
structure.
Unitholders' equity - As at September 30, 2008, Bonavista had 117.1 million
equivalent trust units outstanding. This includes 12.0 million exchangeable
shares, which are exchangeable into 22.6 million trust units. The exchange ratio
in effect at September 30, 2008 for exchangeable shares was 1.87946:1. As at
November 6, 2008, Bonavista had 117.3 million equivalent trust units
outstanding. This includes 12.0 million exchangeable shares, which are
exchangeable into 22.7 million trust units. The exchange ratio in effect at
November 6, 2008 for exchangeable shares was 1.90081:1. In addition, Bonavista
has 3.3 million trust unit incentive rights outstanding at November 6, 2008,
with an average exercise price of $26.00 per trust unit.
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 three months ended September 30, 2008 the Trust
declared distributions of $84.9 million ($0.90 per trust unit) compared to $77.0
million ($0.90 per trust unit) in the same period in 2007. For the nine months
ended September 30, 2008 the Trust declared distributions of $246.7 million
($2.70 per trust unit) compared to $230.3 million ($2.70 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 three months ended September 30, 2008, the
non-cash charges resulted in a non-cash add back of $34.5 million compared to a
non-cash charge of $61.4 million for the same period in 2007. For the nine
months ended September 30, 2008, the non-cash charges amounted to $203.0 million
compared to $220.4 million for the same period 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
September 30,
Distribution Analysis 2008 2007
----------------------------------------------------------------------------
(thousands)
Cash flow provided from operating activities $ 191,437 $ 128,685
Net income 207,594 58,990
Distributions declared 84,859 76,972
Excess of cash flow provided from operating activities
over distributions declared 106,578 51,713
Excess (shortfall) of net income over distributions
declared 122,735 (17,982)
----------------------------------------------------------------------------
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 $0.30 per unit. This monthly distribution is comprised of the base
distribution of $0.28 per unit plus a supplementary distribution of $0.02 per
unit, due to the average realized commodity prices in excess of budget prices.
The combined base and supplementary distribution incorporates the withholding of
sufficient funds from operations to fund capital expenditures required to
maintain or modestly grow the current production base and provide sustainable
distributions in the long-term. Our long-term objective is to distribute between
50% and 60% of our funds from operations. Our current distribution rate of $0.30
per unit per month places us slightly below this range for 2008.
Quarterly financial information - The following table highlights Bonavista's
performance for the eight quarterly periods ending on December 31, 2006 to
September 30, 2008:
----------------------------------------------------------------------------
2008
---------------------------------------------------
September 30 June 30 March 31 December 31
-------------- --------- ---------- -------------
($ thousands, except per
unit amounts)
Production revenues 354,667 361,555 296,387 242,361
Net income 207,594 29,282 72,298 63,631
Net income per unit:
Basic 1.77 0.26 0.67 0.60
Diluted 1.75 0.26 0.67 0.59
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007 2006
---------------------------------------------------
September 30 June 30 March 31 December 31
-------------- --------- ---------- -------------
($ thousands, except per
unit amounts)
Production revenues 219,885 223,878 225,222 220,484
Net income 58,990 33,936 61,630 67,635
Net income per unit:
Basic 0.56 0.32 0.59 0.65
Diluted 0.55 0.32 0.59 0.65
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Bonavista has seen growth in its production revenues over the past eight
quarters due largely from increased commodity prices. Specifically in the third
quarter of 2008, revenues were 61% higher than the same period in 2007 as a
result of a 47% increase in natural gas prices and a 75% increase in oil and
liquids prices. 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, unrealized
gains and losses on financial instruments and future income tax recoveries
associated with the reduction in corporate income tax rates. Net income
increased 252% in the third quarter of 2008 as compared to the third quarter of
2007. The increase in net income in the third quarter of 2008 is attributed to a
$110.4 million gain on financial instruments consisting of a $44.1 million
realized loss and an unrealized gain of $154.5 million as compared to a $2.9
million loss consisting of a $1.4 million realized gain and an unrealized loss
of $4.3 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 examined this national instrument and is
implementing procedures to be compliant on the effective date.
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.
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" on January 1, 2009, which
defines the criteria for the recognition of intangible assets.
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 move toward 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 inventory 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. Over the last winter, we
witnessed acquisition prices decreasing to a level that compared favourably with
our cost of adding reserves organically, and we acted on this by completing a
significant, natural gas-weighted, property acquisition in January 2008. 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 elected
to establish a conservative preliminary base budget between $300 and $320
million which, at this time, is being allocated entirely to our exploration and
development program. It is anticipated that this level of capital expenditures
will result in the drilling of between 170 and 190 wells and production levels
increasing modestly over 2008 to between 54,000 and 54,500 boe per day. The
drilling program will consist of approximately 50 horizontal wells,
predominantly in our Southeast Saskatchewan and Central Alberta areas. Although
we have not allocated any budget towards acquisitions in 2009, market conditions
are developing such that companies with financial and operational flexibility
could easily benefit in this environment. We will closely monitor this situation
as we move closer to 2009 and remain opportunistic to further expand our capital
programs on additional property or land acquisitions and/or drilling
opportunities as they present themselves.
We are extremely proud of our achievements over the past eleven years and remain
enthusiastic about the growing opportunities that exist for Bonavista in the
future. We would like to thank our employees for their significant effort and
their continued enthusiasm and excitement as we pursue these opportunities.
Despite the setbacks we have endured over the past couple of years such as the
passage of legislation in the Canadian House of Commons 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 recent market
selloff, 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 company 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.
----------------------------------------------------------------------------
Consolidated Balance Sheets September 30, December 31,
(thousands) 2008 2007
----------------------------------------------------------------------------
(unaudited)
Assets:
Current assets:
Accounts receivable $ 125,297 $ 125,390
Future income tax asset 5,479 13,517
----------------------------------------------------------------------------
130,776 138,907
Oil and natural gas properties and equipment 2,316,350 2,074,993
Goodwill 41,321 41,321
----------------------------------------------------------------------------
$ 2,488,447 $ 2,255,221
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities and Unitholders' Equity:
Current liabilities:
Accounts payable and accrued liabilities $ 167,543 $ 78,469
Distributions payable 28,334 25,729
Unrealized losses on financial instruments 18,266 45,058
----------------------------------------------------------------------------
214,143 149,256
Long-term debt 565,205 712,654
Convertible debentures 43,531 48,830
Asset retirement obligations 121,648 116,893
Future income taxes 182,073 166,621
Unitholders' equity:
Unitholders' capital and debenture conversion
component 1,092,751 851,685
Exchangeable shares 73,546 74,710
Contributed surplus 7,889 9,369
Accumulated earnings 187,661 125,203
----------------------------------------------------------------------------
1,361,847 1,060,967
----------------------------------------------------------------------------
$ 2,488,447 $ 2,255,221
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
Consolidated Statements of Operations, Comprehensive Income and Accumulated
Earnings
(thousands, except per unit Three months Nine months
amounts) ended September 30, ended September 30,
2008 2007 2008 2007
----------------------------------------------------------------------------
(unaudited)
Revenues:
Production $ 354,667 $ 219,885 $1,012,609 $ 668,985
Royalties (69,716) (35,535) (200,166) (112,777)
----------------------------------------------------------------------------
284,951 184,350 812,443 556,208
----------------------------------------------------------------------------
Realized gains (losses) on
financial instruments (44,094) 1,438 (98,344) 4,343
Unrealized gains (losses) on
financial instruments 154,480 (4,373) 26,792 (13,548)
----------------------------------------------------------------------------
110,386 (2,935) (71,552) (9,205)
----------------------------------------------------------------------------
395,337 181,415 740,891 547,003
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Expenses:
Operating 47,050 41,778 135,450 120,504
Transportation 10,112 10,624 29,155 31,033
General and administrative 3,611 3,479 10,585 9,715
Financing 6,993 9,525 26,774 24,294
Unit-based compensation 1,582 1,709 6,355 4,542
Depreciation, depletion and
accretion 67,940 60,070 197,271 172,063
----------------------------------------------------------------------------
137,288 127,185 405,590 362,151
----------------------------------------------------------------------------
Income before taxes 258,049 54,230 335,301 184,852
Income taxes (reductions) 50,455 (4,760) 26,127 30,296
----------------------------------------------------------------------------
Net income 207,594 58,990 309,174 154,556
Changes in comprehensive
income, net of taxes - (781) - (3,482)
----------------------------------------------------------------------------
Comprehensive income 207,594 58,209 309,174 151,074
----------------------------------------------------------------------------
Accumulated earnings,
beginning of period 64,926 156,690 125,203 214,417
Distributions declared (84,859) (76,972) (246,716) (230,265)
----------------------------------------------------------------------------
Accumulated earnings, end of
period $ 187,661 $ 138,708 $ 187,661 $ 138,708
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income per unit - basic $ 1.77 $ 0.56 $ 2.74 $ 1.47
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income per unit - diluted $ 1.75 $ 0.55 $ 2.71 $ 1.47
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
Consolidated Statements of Cash Flows
(thousands) Three months Nine months
ended September 30, ended September 30,
2008 2007 2008 2007
----------------------------------------------------------------------------
(unaudited)
Cash provided by (used in):
Operating Activities:
Net income $ 207,594 $ 58,990 $ 309,174 $ 154,556
Items not requiring cash from
operations:
Depreciation, depletion and
accretion 67,940 60,070 197,271 172,063
Unit-based compensation 1,582 1,709 6,355 4,542
Unrealized (gains) losses on
financial instruments (154,480) 4,373 (26,792) 13,548
Future income taxes (reductions) 50,455 (4,760) 26,127 30,296
Asset retirement expenditures (3,046) (2,081) (10,168) (3,554)
Changes in non-cash working
capital items 21,392 10,384 34,813 6,111
----------------------------------------------------------------------------
191,437 128,685 536,780 377,562
----------------------------------------------------------------------------
Financing Activities:
Issuance of equity, net of issue
costs 3,489 809 222,592 7,180
Distributions (84,768) (76,940) (244,111) (230,046)
Changes in long-term debt (41,927) 96,375 (147,449) 156,627
Changes in non-cash working
capital items 589 512 263 241
----------------------------------------------------------------------------
(122,617) 20,756 (168,705) (65,998)
----------------------------------------------------------------------------
Investing Activities:
Exploitation and development (89,847) (50,889) (245,278) (209,220)
Property acquisitions (8,948) (98,311) (183,776) (99,221)
Property dispositions 6,205 - 6,888 100
Changes in non-cash working
capital items 23,770 (241) 54,091 (3,223)
----------------------------------------------------------------------------
(68,820) (149,441) (368,075) (311,564)
----------------------------------------------------------------------------
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 three and nine months ended September 30, 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.
The unaudited consolidated financial statements include the accounts of the
Trust and its wholly-owned subsidiaries and partnerships, and have been prepared
by management in accordance with Canadian Generally Accepted Accounting
Principles. The interim consolidated financial statements and notes should be
read in conjunction with the consolidated financial statements for the year
ended December 31, 2007. Certain amounts have been reclassified to conform to
the current period's presentation.
1. Changes in accounting policy:
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 that reflects the remaining ongoing services that will be provided by
Bonavista.
For the three months ended September 30, 2008 Bonavista charged NuVista $330,000
(2007 - $360,000) 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 nine
months ended September 30, 2008 Bonavista charged NuVista $1.1 million (2007 -
$1.0 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 $1.0 million (2007 - $1.0 million). NuVista also
credited Bonavista $211,000 (2007 - $638,000) for interest accrued during the
first nine months of 2008, relating to the cash balance within the jointly owned
partnership. As at September 30, 2008, the amount payable to NuVista was
$427,000.
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 $559.2 million (2007 - $506.0 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:
----------------------------------------------------------------------------
Nine months ended
September 30,
2008 2007
----------------------------------------------------------------------------
(thousands)
Balance, beginning of period $ 116,893 $ 96,324
Accretion expense 6,330 5,218
Liabilities incurred 6,106 656
Liabilities acquired 2,487 3,976
Liabilities settled (10,168) (3,554)
----------------------------------------------------------------------------
Balance, end of period $ 121,648 $ 102,620
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 consolidated senior debt borrowing will not exceed three times net income
before interest, taxes and depreciation, depletion and accretion; consolidated
total debt will not exceed three and one half times consolidated net income
before interest, taxes and depreciation, depletion and accretion; and
consolidated senior debt borrowing will not exceed one-half of consolidated
total debt plus consolidated unitholders' equity of the Trust.
Financing expenses for the nine months ended September 30, 2008 include interest
on bank loans of $24.3 million (2007 - $21.6 million) and convertible debentures
of $2.5 million (2007 - $2.7 million). For the nine months ended September 30,
2008, Bonavista paid cash interest of $26.5 million (2007 - $24.1 million). For
the nine months ending September 30, 2008 our effective interest rate was 4.1%
(2007 - 5.1%).
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 and the debt component of the obligation is adjusted for the
amortization as well as for the portion of issue costs relating to conversions.
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 September 30, 2008:
----------------------------------------------------------------------------
Debt Equity
Component Component
----------------------------------------------------------------------------
(thousands)
Balance, December 31, 2007 $ 48,830 $ 1,054
Accretion 45 -
Issue expenses related to conversions to trust
units 43 -
Amortization of issue expenses 515 -
Conversion to trust units (5,902) (121)
----------------------------------------------------------------------------
Balance, September 30, 2008 $ 43,531 $ 933
----------------------------------------------------------------------------
----------------------------------------------------------------------------
6. Unitholders' equity:
a) Authorized:
Unlimited number of voting trust units.
b) Issued and outstanding:
(i) Trust units:
----------------------------------------------------------------------------
Number 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 354 1,164
Issued upon exercise of trust unit incentive rights 1,054 19,455
Conversion of restricted trust units 65 -
Issue costs, related to debenture conversions - (43)
Issue costs, net of future tax benefit - (8,426)
Adjustment to equity component of debenture on
conversion - 121
Unit-based compensation - 8,814
----------------------------------------------------------------------------
Balance, September 30, 2008 94,445 $ 1,091,818
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(ii) Contributed surplus:
----------------------------------------------------------------------------
Amount
----------------------------------------------------------------------------
(thousands)
Balance, December 31, 2007 $ 9,369
Unit-based compensation expense 6,355
Unit-based compensation capitalized 979
Exercise of trust unit incentive rights and
conversion of restricted trust units (8,814)
----------------------------------------------------------------------------
Balance, September 30, 2008 $ 7,889
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(iii) Exchangeable shares:
----------------------------------------------------------------------------
Number Amount
----------------------------------------------------------------------------
(thousands)
Balance, December 31, 2007 12,230 $ 74,710
Exchanged for trust units (190) (1,164)
----------------------------------------------------------------------------
Balance, September 30, 2008 12,040 $ 73,546
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Exchange ratio, September 30, 2008 1.87946 -
----------------------------------------------------------------------------
Trust units issuable on exchange 22,628 $ 73,546
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As a result of minimal conversions of exchangeable shares into trust units over
the last few years, Bonavista has 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. In connection with this redemption, Bonavista has
exercised its overriding "redemption call right" to purchase such exchangeable
shares from holders of record. Each redeemed exchangeable share will be
purchased for trust units of the Trust in accordance with the exchange ratio in
effect at January 16, 2009, rounded to the nearest whole trust unit for each
holder of record. A Notice of Redemption has been mailed to all exchangeable
shareholders outlining the terms of this redemption. Bonavista will also mail a
formal Letter of Transmittal to all exchangeable shareholders of record on
January 16, 2009 to complete this transaction.
c) Long term incentive plans:
For the three months ended September 30, 2008 there were 53,415 restricted trust
units granted and 685,260 trust unit incentive rights issued with an average
exercise price of $35.99 per trust unit and an estimated fair value of $10.56
per trust unit. As at September 30, 2008 there were 146,833 restricted trust
units outstanding and 3,177,940 trust unit rights outstanding with an average
exercise price of $26.59 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 28%; 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 September 30, 2008
----------------------------------------------------------------------------
(thousands)
Trust units 94,223
Exchangeable shares converted at the exchange ratio 22,809
----------------------------------------------------------------------------
Basic equivalent trust units 117,032
Convertible debentures 1,636
Trust unit incentive rights 624
Restricted trust units 147
----------------------------------------------------------------------------
Diluted equivalent trust units 119,439
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 September 30, 2008 the Trust's receivables consisted of $85.7
million of receivables from crude oil and natural gas marketers which has
substantially been collected, $23.8 million from joint venture partners of which
$3.4 million has been subsequently collected, and $15.8 million of Crown
deposits and prepaid expenses. As at September 30, 2008 the Trust has $8.9
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
September 30, 2008 and did not provide for any doubtful accounts nor was it
required to write-off any receivables during the period ended September 30,
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 $29.00 per trust
unit, maturing on June 30, 2010. The Trust may elect to satisfy the principal
obligation of these debentures by issuing trust units to the holders of the
debentures. The Trust also maintains and monitors a certain level of cash flow
which is used to partially finance all operating, investing and capital
expenditures.
(c) Market risk:
Market risk is the risk that changes in market conditions, such as commodity
prices, interest rates, and foreign exchange rates, will affect the Trust's net
income or the value of financial instruments. The objective of market risk
management is to manage and control market risk exposures within acceptable
limits, while maximizing the Trust's returns.
The Trust utilizes both financial derivatives and physical delivery sales
contracts to manage market risks. All such transactions are conducted in
accordance with the Trust's risk management policy that has been approved by the
Board of Directors.
i) Commodity price risk
Commodity price risk is the risk that the fair value of future cash flows will
fluctuate as a result of changes in commodity prices. Commodity prices for crude
oil and natural gas are impacted not only by global economic events that dictate
the levels of supply and demand but also by the relationship between the
Canadian and United States dollar. The Trust has attempted to mitigate a portion
of the commodity price risk through the use of various financial derivative and
physical delivery sales contracts. The Trust's policy is to enter into commodity
price contracts when considered appropriate to a maximum of 60% of forecasted
production volumes.
As at September 30, 2008, the Trust has hedged by way of costless collars to
sell natural gas and crude oil as follows:
----------------------------------------------------------------------------
Volume Average Price Term
----------------------------------------------------------------------------
35,000 gjs/d CDN$ 7.43 - CDN$ 8.77 - AECO October 1, 2008 -
October 31, 2008
10,000 gjs/d CDN$ 9.25 - CDN$ 13.50 - AECO November 1, 2008 -
March 31, 2009
5,000 gjs/d CDN$ 9.00 - CDN$ 12.00 - AECO April 1, 2009 -
October 31, 2009
5,000 mmbtu/d US$ 6.81 - US$ 7.91 - AECO November 1, 2008 -
March 31, 2009
7,000 bbls/d US$ 65.43 - US$ 78.58 - WTI October 1, 2008 -
December 31, 2008
4,000 bbls/d CDN$ 61.75 - CDN$ 70.88 - Bow River October 1, 2008 -
December 31, 2008
1,000 bbls/d CDN$ 70.00 - CDN$ 78.00 - Bow River January 1, 2009 -
December 31, 2009
2,000 bbls/d CDN$ 92.50 - CDN$140.25 - WTI January 1, 2009 -
December 31, 2009
2,000 bbls/d US$ 65.00 - US$ 80.50 - WTI January 1, 2009 -
March 31, 2009
2,000 bbls/d CDN$ 105.00 - CDN$ 169.00 - WTI April 1, 2009 -
December 31, 2009
1,000 bbls/d US$ 85.00 - US$ 105.60 - WTI April 1, 2009 -
December 31, 2009
----------------------------------------------------------------------------
Derivatives are recorded on the 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 statement of operations, comprehensive income and
retained earnings. These contracts had the following reflected in the
consolidated statement of operations, comprehensive income and retained
earnings:
----------------------------------------------------------------------------
Three months
ended September 30,
2008 2007
Realized gains (losses) on financial instruments $ (44,094) $ 1,438
Unrealized gains (losses) on financial instruments 154,480 (4,373)
----------------------------------------------------------------------------
$ 110,386 $ (2,935)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Bonavista mitigates its risk associated with fluctuations in commodity prices by
entering into commodity price contracts. A $0.10 change to the price per
thousand cubic feet of natural gas - AECO and a $1.00 change to the price per
barrel of oil - WTI would have an impact of approximately $290,000 and $1.6
million, respectively, on net income for those commodity price contracts that
were in place as at September 30, 2008.
ii) Physical purchase contracts:
As at September 30, 2008, the Trust has entered into direct sale costless
collars to sell natural gas as follows:
----------------------------------------------------------------------------
Volume Average Price (CDN$ - AECO) Term
----------------------------------------------------------------------------
45,000 gjs/d $ 7.19 - $ 8.36 October 1, 2008 -
October 31, 2008
40,000 gjs/d $ 8.16 - $ 10.69 November 1, 2008 -
March 31, 2009
10,000 gjs/d $ 8.00 - $ 10.84 April 1, 2009 -
October 31, 2009
----------------------------------------------------------------------------
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 September 30, 2008.
iv) Interest rate risk
Interest rate 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 nine months ended September 30, 2008 would have a $1.1 million and $3.9
million impact respectively. For the similar periods in 2007 net income would be
impacted by approximately $1.3 and $3.2 million respectively. The sensitivity
impact is lower for the third quarter of 2008 compared to the same period in
2007 because of both lower weighted average outstanding bank debt and lower
average interest rates. The sensitivity impact is higher for the nine months
ended in 2008 because of higher weighted average bank debt compared to the nine
months ended September 30, 2007, notwithstanding that the weighted average
interest rate is lower in the first nine months of 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 September 30, 2008.
Fair value of financial instruments
The Trust's financial instruments as at September 30, 2008 and December 31, 2007
include accounts receivable, derivative contracts, accounts payable and accrued
liabilities, convertible debentures and bank debt. The fair value of accounts
receivable, accounts payable and accrued liabilities approximate their carrying
amounts due to their short-terms to maturity. The Trust does not hold any
financial assets or liabilities that are held for trading, nor does it have held
to maturity investments or available for sale financial assets.
The fair value of derivative contracts is determined by the financial
intermediary to extinguish all rights or obligations of the financial
instruments. As at September 30, 2008, the market deficit of these derivative
financial instruments was approximately $18.3 million.
Fair market value of the convertible debentures as at September 30, 2008 is
$47.1 million, which has been determined by its most recent closing trading
price during the quarter.
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 September 30, 2008, the Trust's ratio of net debt to annualized funds from
operations was 0.9 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 facts 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 September 30, 2008.
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