Bonavista Energy Trust (TSX:BNP.UN) is pleased to report to unitholders its
interim consolidated financial and operating results for the three and six
months ended June 30, 2008.
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Highlights
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Three Months Six Months
ended June 30, ended June 30,
2008 2007 2008 2007
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Financial
($ thousands, except per
unit)
Production revenues 361,555 223,878 657,942 449,100
Funds from operations (1) 183,912 126,111 339,044 254,623
Per unit (1) (2) 1.62 1.20 3.06 2.43
Distributions declared 84,282 76,757 161,857 153,293
Per unit 0.90 0.90 1.80 1.80
Percentage of funds from
operations (1) 46% 61% 48% 60%
Net income 29,282 33,936 101,580 95,566
Per unit (2) 0.26 0.32 0.92 0.91
Total assets 2,512,365 2,115,759
Long-term debt, including
working capital deficiency 752,792 577,409
Long-term debt, net of
adjusted working capital (3) 631,871 572,937
Unitholders' equity 1,232,554 1,087,869
Capital expenditures:
Exploitation and development 62,166 67,715 155,431 158,331
Acquisitions, net 4,771 (155) 174,145 810
Weighted average outstanding
equivalent trust units:
(thousands) (2)
Basic 113,713 105,087 110,795 104,699
Diluted 116,292 107,701 113,228 107,385
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Operating
(boe conversion - 6:1 basis)
Production:
Natural gas (mmcf/day) 172 171 175 172
Oil and liquids (bbls/day) 22,974 22,964 23,834 23,198
Total oil equivalent (boe/day) 51,598 51,533 52,998 51,792
Product prices: (4)
Natural gas ($/mcf) 9.62 7.35 8.73 7.61
Oil and liquids ($/bbl) 81.94 52.66 75.05 51.34
Operating expenses ($/boe) 9.37 8.46 9.16 8.40
General and administrative expenses
($/boe) 0.74 0.68 0.72 0.67
Cash costs ($/boe) (5) 11.86 10.68 11.94 10.64
Operating netback ($/boe) (6) 41.66 29.11 37.92 29.40
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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
-----------------------------------------------
June 30, March 31, December 31, September 30,
Trust Unit Trading Statistics 2008 2008 2007 2007
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($ per unit, except volume)
High 37.64 31.35 31.85 31.38
Low 28.96 24.24 24.14 27.25
Close 37.45 29.85 28.50 29.02
Average Daily Volume 329,638 231,949 275,892 177,752
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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 six months ended June 30, 2008. The results for the second
quarter of 2008 represents twenty consecutive quarters of profitability for
Bonavista since commencing operations as an energy trust in July 2003. The
continued execution of Bonavista's proven strategies in the first half of 2008
are a testament to the validity and effectiveness of an operationally and
technically focused energy trust. The first half results for 2008 are also
highlighted by an active and successful drilling and acquisitions program, which
has led to increased production and attractive reserve addition costs. In 2008,
Bonavista plans to spend approximately $475 million on its conventional drilling
and acquisition programs, drilling 220 to 230 wells, and forecasted production
of approximately 54,300 boe per day. In addition, for the remainder of the year
Bonavista plans to invest up to $20 million in resource land purchases and
applying new technology towards resource play development. The current dynamic
environment continues to benefit Bonavista, given our significant financial
flexibility and opportunity rich land base within the Western Canadian
Sedimentary Basin.
Other significant accomplishments for Bonavista in the first half of 2008 include:
- Operationally, production volumes averaged 51,598 boe per day during the
second quarter of 2008, despite experiencing significant downtime from plant
turnarounds which impacted production volumes by approximately 2,800 boe per
day. Production volumes averaged 52,998 boe per day for the first half of 2008;
- Maintained an active capital program during both the second quarter of 2008
and first half of 2008. In the second quarter of 2008 Bonavista invested $62.2
million in exploitation and development activities by drilling 28 wells with an
overall 96% success rate. In addition, Bonavista spent $4.8 million on
synergistic acquisitions within our core regions. For the first six months of
2008, Bonavista invested $155.4 million in exploitation and development
activities, drilling 97 wells with an overall 94% success rate and completed
seven acquisitions for $174.1 million;
- Drilled 12 successful horizontal wells, year to date, on the highly
prospective, light oil Bakken trend in our Southeast Saskatchewan area with very
favourable results. In addition to our Bakken resource initiatives, we have
identified several 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 $171 million acquisition of
producing and undeveloped oil and natural gas properties (61% natural gas
weighted) in the greater Willesden Green area. This acquisition further
complements the property acquisition that we completed in the third quarter of
2007 and our pre-existing assets in this area. We now have a concentrated
position in this area with current production over 5,500 boe per day. There is
also significant exploitation and optimization opportunities remaining to be
developed on these lands;
- Continued to actively participate at crown land sales and freehold purchases,
investing $11.7 million in land activity during the first half of 2008, further
enhancing our future drilling prospect inventory to more than three years;
- Generated record funds from operations of $183.9 million ($1.62 per unit) in
the second quarter of 2008 and $339.0 million ($3.06 per unit) in the first half
of 2008. Of the total funds from operations generated in the respective periods,
Bonavista distributed 46% of these funds in the second quarter and 48% of these
funds for the first half of 2008 to Unitholders with the remaining funds
reinvested in the business to continue growing our production base;
- Continued to record strong profitability in both the second quarter and first
half of 2008 with a strong average return on equity of 35% and 32% respectively,
and a strong net income to funds from operations ratio of 57% and 56%
respectively. The above ratios reflect net income adjusted to negate the after
tax impact of the unrealized gains and losses on financial instruments;
- Within the energy trust industry, Bonavista delivered attractive total returns
of 38% to our Unitholders in the first half of 2008 and currently has a
cash-on-cash yield of 11%. In addition, Bonavista has delivered cumulative
distributions of $1.3 billion or $17.31 per trust unit since the inception of
our Trust. 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;
and
- 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.
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, and a growing production base. Our production base is
balanced 54% in favour of natural gas and 46% towards oil and liquids and is
geographically focused within select medium depth, multi-zone regions in
Alberta, Saskatchewan and British Columbia. This base has one of the lowest
operating cost structures in the oil and natural gas trust sector. 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. Combined, all of these attributes
result in attractive operating netbacks for Bonavista.
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. The management
team, together with a strong Board of Directors, possess extensive experience in
oil and natural gas operations, corporate governance and financial management.
Directors, management and employees also own approximately 18% of the Trust,
resulting in an 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
August 7, 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; and (viii) 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 six
months of 2008 led to the drilling of 97 wells in our four core regions with an
overall success rate of 94%. This program resulted in 34 natural gas wells, 57
oil wells and six dry holes. Bonavista continues to emphasize higher impact
drilling opportunities particularly in the Bakken play in our Southeast
Saskatchewan area and our South Central core 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 seven
complementary acquisitions in its core regions during the first half of 2008.
Production - For the second quarter of 2008, production increased to 51,598 boe
per day when compared to 51,533 boe per day for the same period in 2007.
Production in the second quarter exceeded initial expectations but was curtailed
by approximately 2,800 boe per day primarily due to two significant planned
turnarounds at third party gas facilities and normal spring breakup conditions.
Natural gas production increased to 172 mmcf per day in the second quarter of
2008 from 171 mmcf per day for the same period a year ago, while total oil and
liquids production increased to 22,974 bbls per day in the second quarter of
2008 (comprised of 16,659 bbls per day of light and medium oil and 6,315 bbls
per day of heavy oil) from 22,964 bbls per day (comprised of 15,868 bbls per day
of light and medium oil and 7,096 bbls per day of heavy oil) for the same period
in 2007. Our current production is approximately 54,000 boe per day consisting
of 54% natural gas, 33% light and medium oil and 13% heavy oil. Production for
the six months ended June 30, 2008, increased 2% to 52,998 boe per day when
compared to 51,792 boe per day for the same period in 2007. Natural gas
production increased 2% to 175 mmcf per day in the first six months of 2008 from
172 mmcf per day for the same period a year ago, while total oil and liquids
production increased 3% to 23,834 bbls per day in the first six months of 2008
(comprised of 17,199 bbls per day of light and medium oil and 6,635 bbls per day
of heavy oil) from 23,198 bbls per day (comprised of 16,070 bbls per day of
light and medium oil and 7,128 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 54,300 boe per day.
Revenues - Revenues, excluding gains and losses on financial instruments, for
the second quarter of 2008 increased by 62% to $361.6 million when compared to
$223.9 million in the second quarter of 2007 primarily due to higher average
commodity prices. In the second quarter of 2008, natural gas prices increased
31% to $9.62 per mcf, when compared to $7.35 per mcf realized in the same period
in 2007. The average oil and liquids price increased 56% to $81.94 per bbl
(comprised of $84.26 per bbl for light and medium oil and $75.83 per bbl for
heavy oil) in the second quarter of 2008 from $52.66 per bbl (comprised of
$57.38 per bbl for light and medium oil and $42.09 per bbl for heavy oil) for
the same period in 2007. Revenues, excluding gains and losses on financial
instruments, for the six months ended June 30, 2008 increased by 47% to $657.9
million when compared to $449.1 million for the same period a year ago due to
higher average commodity prices and increased production volumes. In the first
half of 2008, natural gas prices increased 15% to $8.73 per mcf, compared to
$7.61 per mcf realized in the same period in 2007. The average oil and liquids
price increased 46% to $75.05 per bbl (comprised of $76.86 per bbl for light and
medium oil and $70.34 per bbl for heavy oil) in the first half of 2008 from
$51.34 per bbl (comprised of $55.74 per bbl for light and medium oil and $41.44
per bbl for heavy oil) for the same period in 2007.
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
unpredictable 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 second quarter of 2008, our risk management program on financial
instruments resulted in a net loss of $148.2 million, consisting of a realized
loss of $40.0 million and an unrealized loss of $108.2 million. The realized
loss of $40.0 million consisted of a $1.2 million loss on natural gas commodity
derivative contracts and a $38.8 million loss on crude oil commodity derivative
contracts. For the six months ended June 30, 2008, our risk management program
on financial instruments resulted in a net loss of $181.9 million consisting of
a realized loss of $54.2 million and an unrealized loss of $127.7 million. The
realized loss consisted of a $887,000 loss on natural gas commodity derivative
contracts and a $53.3 million loss on crude oil commodity derivative contracts.
A summary of commodity price risk management contracts in place as at June 30,
2008 and subsequent to June 30 2008, is included in note 7 of the consolidated
financial statements.
Royalties - For the three months ended June 30, 2008, royalties increased 91% to
$73.0 million from $38.2 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 oil sand royalty projects. In addition,
royalties as a percentage of revenue (including realized gains and losses on
financial instruments) for the second quarter of 2008 increased to 22.7%
compared to 17.0% in 2007 for similar reasons discussed above and the result of
realized losses on financial instruments. For the three months ended June 30,
2008, royalties by product as a percentage of revenues (including realized gains
and losses on financial instruments) were 23.4% for natural gas, 21.6% for light
and medium oil and 23.6% for heavy oil. In the second quarter of 2007, royalties
by product, as a percentage of revenue (including realized gains and losses on
financial instruments) were 17.8% for natural gas, 16.5% for light and medium
oil and 15.4% for heavy oil. For the six months ended June 30, 2008, royalties
also increased significantly by 69% to $130.5 million from $77.2 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 six month period also increased from 17.1% in
2007 to 21.6% in 2008, for the same reasons as discussed above. For the six
months ended June 30, 2008, royalties by product as a percentage of revenue
(including realized gains and losses on financial instruments) were 22.2% for
natural gas, 20.9% for light and medium oil and 21.6% for heavy oil. For the six
months ended June 30, 2007, royalties by product, as a percentage of revenues
including realized gains and losses on financial instruments were 18.2% for
natural gas, 16.4% for light and medium oil and 14.4% 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 by
approximately 3% to 4%. Bonavista will continue to assess the impact that the
NRF will have on existing operations when legislation is finalized or as more
information becomes available.
Operating expenses - Operating expenses for the second quarter of 2008 increased
11% to $44.0 million compared to $39.7 million for the same period a year ago.
Operating costs increased primarily due to spring breakup conditions, two
significant planned turnarounds at third party gas facilities and the
continuation of industry wide operating cost increases, primarily driven by
higher fuel, power, chemical and labour costs. These factors resulted in average
per unit operating costs increasing by 11% for the three months ended June 30,
2008, to $9.37 per boe from $8.46 per boe in the comparable period of 2007.
Operating costs by product for the second quarter of 2008 were $1.36 per mcf for
natural gas, $9.93 per bbl for light and medium oil and $13.35 per bbl for heavy
oil compared to $1.21 per mcf for natural gas, $9.14 per bbl for light and
medium oil and $12.28 per bbl for heavy oil for the same period in 2007.
Operating expenses for the first half of 2008 increased 12% to $88.4 million
compared to $78.7 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 9% for the six months ended June 30, 2008, to $9.16 per boe from
$8.40 per boe in the comparable period of 2007. Operating costs by product for
the first half of 2008 were $1.30 per mcf for natural gas, $9.84 per bbl for
light and medium oil and $13.37 per bbl for heavy oil compared to $1.18 per mcf
for natural gas, $9.06 per bbl for light and medium oil and $12.14 per bbl for
heavy oil for the same period in 2007. As a result of the increasing cost
pressures noted in the first half of 2008, we anticipate our operating costs
will average approximately $9.20 per boe in 2008. Notwithstanding these cost
increases, Bonavista continues to experience one of the lowest operating costs
of any producer in the energy trust sector and continues to look for innovative
ways to reduce costs in the future.
Transportation expenses - For the three months ended June 30, 2008,
transportation expenses decreased 13% to $9.0 million ($1.91 per boe) when
compared to $10.3 million ($2.19 per boe) for the same period last year. The 13%
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 six months ended June 30, 2008 decreased 7% to $19.0 million ($1.97 per boe)
compared to $20.4 million ($2.18 per boe) for the same period a year ago.
Transportation expenses by product for the second quarter of 2008 were $0.37 per
mcf for natural gas, $0.86 per bbl for light and medium oil and $3.31 per bbl
for heavy oil compared to $0.44 per mcf for natural gas, $0.99 per bbl for light
and medium oil and $3.16 per bbl for heavy oil for the second quarter of 2007.
For the first half of 2008 transportation expenses by product were $0.39 per mcf
for natural gas, $0.85 per bbl for light and medium oil and $3.32 per bbl for
heavy oil compared to $0.43 per mcf for natural gas, $0.97 per bbl for light and
medium oil and $3.19 per bbl for heavy oil for the same period a year ago.
General and administrative expenses - General and administrative expenses, after
overhead recoveries, increased 9% to $3.5 million for the three months ended
June 30, 2008 from $3.2 million in the same period in 2007 and increased 12% to
$7.0 million for the six months ended June 30, 2008 from $6.2 million in the
same period in 2007. On a per boe basis, general and administrative expenses
increased 9% for the three months ended June 30, 2008 to $0.74 per boe from
$0.68 per boe in the same period in 2007 and increased 7% for the six months
ended June 30, 2008 to $0.72 per boe from $0.67 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., Bonavista provides certain administrative activities. The
fee charged under this agreement was $373,000 for the three months ended June
30, 2008 as compared to $370,000 in the same period in 2007 and $786,000 for the
six months ended June 30, 2008 as compared to $712,000 for the same period in
2007. In connection with its Trust Unit Incentive Rights Plan, Bonavista also
recorded a unit-based compensation charge of $2.5 million and $4.8 million for
the three and six months ended June 30, 2008 respectively, compared to $1.4
million and $2.8 million for the same periods in 2007.
Financing expenses - Financing expenses, which include interest expense on
long-term debt and convertible debentures, increased 14% to $8.2 million for the
three months ended June 30, 2008, from $7.2 million for the same period in 2007
and, on a boe basis, increased 14% to $1.75 per boe for the three months ended
June 30, 2008 from $1.54 per boe for the same period in 2007. For the six months
ended June 30, 2008, financing expenses increased 34% to $19.8 million from
$14.8 million for the same period in 2007 and on a boe basis increased to $2.05
per boe for the first half of 2008 from $1.58 per boe in the same period in
2007. These increases are due to increased debt levels used to fund Bonavista's
capital program. With the impact of Bonavista's recently completed equity
financing, we expect the interest expense to decrease on a per boe basis during
the last half of 2008. During the second quarter of 2008, Bonavista paid cash
interest of $9.2 million compared to $7.8 million in 2007. For the six months
ended June 30, 2008, Bonavista paid cash interest of $20.1 million compared to
$15.0 million for the same period in 2007.
Depreciation, depletion and accretion expenses - Depreciation, depletion and
accretion expenses increased 13% to $64.0 million for the three months ended
June 30, 2008 from $56.6 million in the same period of 2007. For the six months
ended June 30, 2008 depreciation, depletion and accretion expenses also
increased 15% to $129.3 million from $112.0 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 June 30, 2008, the average cost increased to $13.62
per boe from $12.06 per boe for the same period in 2007 and for the six months
ended June 30, 2008 the average cost increased to $13.41 per boe from $11.95 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 June 30, 2008, the provision for
income tax was a recovery of $20.0 million compared to a $38.0 million provision
for the same period in 2007. For the six months ended June 30, 2008, the
provision for income tax was a recovery of $24.3 million compared to $35.1
million for the same period in 2007. Bonavista made no cash payments relating to
installments for either of the three or six months ended June 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. However, the specific rules governing how
the provincial component is to be calculated was released in draft on July 14,
2008 and is therefore not considered to be substantively enacted as at June 30,
2008. As a result, any changes in the tax rate for the Trust's future income tax
has not been reflected in these financial statements.
Funds from operations, net income and comprehensive income - For the three
months ended June 30, 2008, Bonavista experienced a 46% increase in funds from
operations to $183.9 million ($1.62 per unit, basic) from $126.1 million ($1.20
per unit, basic) for the same period in 2007. For the six month period ended
June 30, 2008, Bonavista experienced a 33% increase in funds from operations to
$339.0 million ($3.06 per unit, basic) from $254.6 million ($2.43 per unit,
basic) for the same period in 2007. Funds from operations increased for the
three and six months ended June 30, 2008 primarily due to higher commodity
prices. Net income for the three months ended June 30, 2008, decreased 14% to
$29.3 million ($0.26 per unit, basic) from $33.9 million ($0.32 per unit, basic)
for the same period in 2007. For the six months ended June 30, 3008, net income
increased 6% to $101.6 million ($0.92 per unit, basic) from $95.6 million ($0.91
per unit, basic) in the first half of 2007. Other comprehensive income for the
three months ended June 30, 2008 included a charge of nil (2007 - $1.3 million)
relating to the amortization of the amount recognized in accumulated other
comprehensive income 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 June 30,
2008 of $29.3 million (2007 - $32.7 million). Other comprehensive income for the
six months ended June 30, 2008 included a charge of nil (2007 - $2.7 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 in the first half of
2008 of $101.6 million (2007 - $92.9 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 June 30,
Calculation of Funds From Operations: 2008 2007
----------------------------------------------------------------------------
(thousands)
Cash flow from operating activities $ 183,912 $ 126,111
Asset retirement expenditures (4,204) (1,093)
Changes in non-cash working capital 986 (8,008)
----------------------------------------------------------------------------
Funds from operations $ 180,694 $ 117,010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital expenditures - Capital expenditures for the three month period ended
June 30, 2008 were $66.9 million, consisting of $62.2 million on exploitation
and development spending and $4.7 million on net property acquisitions. For the
same period in 2007 capital expenditures were $67.6 million, consisting of $67.7
million on exploitation and development spending and $155,000 of net property
dispositions. Capital expenditures for the six month period ended June 30, 2008
were $329.6 million, consisting of $155.4 million on exploitation and
development spending and $174.2 million on property acquisitions. For the same
period in 2007 capital expenditures were $159.1 million, consisting of $158.3
million on exploitation and development spending and $810,000 on net
acquisitions. With the industry experiencing cost reductions in many of its
services due to lower industry activity levels in the first half of 2008,
Bonavista too benefited with its active drilling program which is generating
production addition costs at attractive levels of less than $35,000 boe/d. In
2008 we continue to generate favourable economic returns from our capital
expenditure program as a direct result of relatively stable service costs
coupled with strong commodity prices.
Liquidity and capital resources - As at June 30, 2008, long-term debt including
working capital (excluding unrealized losses on financial instruments and
related tax impact), was $631.9 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
$368.1 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.
In 2008, Bonavista plans to invest approximately $475 million on its
conventional 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.
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.
Unitholders' equity - As at June 30, 2008, Bonavista had 116.3 million
equivalent trust units outstanding. This includes 12.2 million exchangeable
shares, which are exchangeable into 22.3 million trust units. The exchange ratio
in effect at June 30, 2008 for exchangeable shares was 1.82966:1. As at August
7, 2008, Bonavista had 116.6 million equivalent trust units outstanding. This
includes 12.2 million exchangeable shares, which are exchangeable into 22.4
million trust units. The exchange ratio in effect at August 7, 2008 for
exchangeable shares was 1.84491:1. In addition, Bonavista has 3.2 million trust
unit incentive rights outstanding at August 7, 2008, with an average exercise
price of $27.10 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 June 30, 2008 the Trust
declared distributions of $84.3 million ($0.90 per trust unit) compared to $76.8
million ($0.90 per trust unit) in the same period in 2007. For the six months
ended June 30, 2008 the Trust declared distributions of $161.9 million ($1.80
per trust unit) compared to $153.3 million ($1.80 per trust unit) in the same
period in 2007. Due to recent price volatility, coupled with a slight expansion
to our capital program targeting unconventional resource potential, we have
elected to maintain our current monthly distribution. We will 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 that do
not impact cash flow. For the three months ended June 30, 2008, the non-cash
charges amounted to $154.6 million compared to $92.2 million for the same period
in 2007. For the six months ended June 30, 2008, the non-cash charges amounted
to $237.5 million compared to $159.1 million for the same period in 2007. Net
income also includes fluctuations in future income taxes due to changes in tax
rates and tax rules. In addition, other non-cash charges, such as depreciation,
depletion and accretion and unrealized gains and losses on financial
instruments, do not represent the actual cost of maintaining our productive
capacity given the natural declines associated with oil and natural gas assets.
In these 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 June 30,
Distribution Analysis 2008 2007
----------------------------------------------------------------------------
(thousands)
Cash flow provided from operating activities $ 183,912 $ 126,111
Net income 29,282 33,936
Distributions declared 84,282 76,757
Excess of cash flow provided from operating
activities over distributions declared 99,630 49,354
Excess (shortfall) of net income over
distributions declared (55,000) (42,821)
----------------------------------------------------------------------------
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 $0.30
per unit per month places us slightly below this range for 2008, based on the
current market of commodity price futures.
Quarterly financial information - The following table highlights Bonavista's
performance for the eight quarterly periods ending on September 30, 2006 to June
30, 2008:
----------------------------------------------------------------------------
2008 2007
-------------------------------------------------
June 30 March 31 December 31 September 30
-------------------------------------------------
($ thousands, except
per unit amounts)
Production revenues 361,555 296,387 242,361 219,885
Net income 29,282 72,298 63,631 58,990
Net income per unit:
Basic 0.26 0.67 0.60 0.56
Diluted 0.26 0.67 0.59 0.55
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007 2006
-------------------------------------------------
June 30 March 31 December 31 September 30
-------------------------------------------------
($ thousands, except
per unit amounts)
Production revenues 223,878 225,222 220,484 227,270
Net income 33,936 61,630 67,635 70,800
Net income per unit:
Basic 0.32 0.59 0.65 0.69
Diluted 0.32 0.59 0.65 0.68
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Production revenue, excluding gains and losses on financial instruments was 62%
higher in the second quarter of 2008 versus the second quarter of 2007,
primarily due to higher average product prices. Net income decreased 14% in the
second quarter of 2008 as compared to the second quarter of 2007. The decrease
in net income in the second quarter of 2008 is attributed to a $148.2 million
loss on financial instruments consisting of a $40.0 million realized loss and an
unrealized loss of $108.2 million as compared to a $4.7 million gain consisting
of a $834,000 realized gain and an unrealized gain of $3.9 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 April 18, 2008, the
Canadian Securities Administrators published the notice and request for comments
for the proposed repeal and replacement of Multilateral Instrument 52-109
Certification of Disclosure in Issuers' Annual and Interim filings. The proposed
changes would include the requirement to provide certification of internal
controls over financial reporting for years ending after December 15, 2008.
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.
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"). The Trust will continue to
monitor and assess the impact of the planned convergence of Canadian GAAP with
IFRS and is implementing plans for transition.
OUTLOOK
As we enter into our eleventh 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 stakeholders. 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 increase as we progress through 2008. This
increase in inventory 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. Since
that time, natural gas prices have improved substantially. 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 ten and a half year history.
For 2008, Bonavista is planning to invest $475 million into its conventional
capital programs. The focus of this capital program will be directed to
Bonavista's exploration, exploitation and development programs which include
drilling approximately 220 to 230 wells, along with strategic property
acquisitions, the majority of which have already been completed. In addition,
Bonavista plans to invest up to $20 million in undeveloped land with future
resource potential and applying new technology towards resource play
development. Bonavista has currently identified approximately 700 drilling
prospects on its current land base and remains flexible to consider accelerating
the drilling of some of these prospects in the latter part of 2008 should
commodity prices stabilize at attractive levels. It is anticipated that this
capital program should result in Bonavista's 2008 production volumes averaging
approximately 54,300 boe per day. This level of production factors in
significant downtime experienced in the second and third quarters, primarily due
to major third party plant turnarounds and normal spring break-up curtailments.
Assuming commodity prices of CDN$8.30 per GJ of natural gas (AECO), US$120.00
per bbl of crude oil (WTI) and CDN$/US$ exchange rate of $0.987, Bonavista now
anticipates 2008 funds from operations to increase to approximately $730 to $740
million. Bonavista will continue to conduct its operations prudently and remain
opportunistic to further expand its 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 ten and a half 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 passage of legislation in the Canadian House of Commons on the
taxation of distributions from certain publicly traded Canadian trusts and the
introduction of the NRF by the Government of Alberta, Bonavista's value creation
process has not changed. Throughout many business cycles and changes in the
business environment, Bonavista has thrived. 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 proven strategy will not change under this new tax regime nor
the provincial government's new royalty regime. Our team remains dedicated to
add Unitholder value in the oil and natural gas business, regardless of the
changing landscape.
----------------------------------------------------------------------------
Consolidated Balance Sheets June 30, December 31,
(thousands) 2008 2007
----------------------------------------------------------------------------
(unaudited)
Assets:
Current assets:
Accounts receivable $ 131,633 $ 125,390
Future income tax asset 51,824 13,517
----------------------------------------------------------------------------
183,457 138,907
Oil and natural gas properties and equipment 2,287,587 2,074,993
Goodwill 41,321 41,321
----------------------------------------------------------------------------
$ 2,512,365 $ 2,255,221
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities and Unitholders' Equity:
Current liabilities:
Accounts payable and accrued liabilities $ 128,129 $ 78,469
Distributions payable 28,243 25,729
Unrealized losses on financial instruments 172,745 45,058
----------------------------------------------------------------------------
329,117 149,256
Long-term debt 607,132 712,654
Convertible debentures 44,469 48,830
Asset retirement obligations 121,130 116,893
Future income taxes 177,963 166,621
Unitholders' equity:
Unitholders' capital and debenture conversion
component 1,085,535 851,685
Exchangeable shares 74,381 74,710
Contributed surplus 7,712 9,369
Accumulated earnings 64,926 125,203
----------------------------------------------------------------------------
1,232,554 1,060,967
----------------------------------------------------------------------------
$ 2,512,365 $ 2,255,221
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
----------------------------------------------------------------------------
Consolidated Statements of Operations, Comprehensive Income and Accumulated
Earnings
(thousands, except per unit amounts) Three Months Six Months
ended June 30, ended June 30,
2008 2007 2008 2007
----------------------------------------------------------------------------
(unaudited)
Revenues:
Production $ 361,555 $223,878 $ 657,942 $ 449,100
Royalties (72,999) (38,227) (130,450) (77,242)
----------------------------------------------------------------------------
288,556 185,651 527,492 371,858
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Realized gains (losses) on
financial instruments (39,967) 834 (54,250) 2,905
Unrealized gains (losses) on
financial instruments (108,224) 3,830 (127,688) (9,175)
----------------------------------------------------------------------------
(148,191) 4,664 (181,938) (6,270)
----------------------------------------------------------------------------
140,365 190,315 345,554 365,588
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Expenses:
Operating 44,005 39,683 88,400 78,726
Transportation 8,977 10,289 19,043 20,409
General and administrative 3,455 3,181 6,974 6,236
Financing 8,240 7,221 19,781 14,769
Unit-based compensation 2,460 1,421 4,773 2,833
Depreciation, depletion and
accretion 63,965 56,568 129,331 111,993
----------------------------------------------------------------------------
131,102 118,363 268,302 234,966
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Income before taxes 9,263 71,952 77,252 130,622
Income taxes (reductions) (20,019) 38,016 (24,328) 35,056
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income 29,282 33,936 101,580 95,566
Changes in comprehensive income,
net of taxes - (1,251) - (2,701)
----------------------------------------------------------------------------
Comprehensive income 29,282 32,685 101,580 92,865
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated earnings, beginning of
period 119,926 199,511 125,203 214,417
Distributions declared (84,282) (76,757) (161,857) (153,293)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated earnings, end of
period $ 64,926 $156,690 $ 64,926 $ 156,690
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income per unit - basic $ 0.26 $ 0.32 $ 0.92 $ 0.91
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income per unit - diluted $ 0.26 $ 0.32 $ 0.92 $ 0.91
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Cash Flows
(thousands) Three Months Six Months
ended June 30, ended June 30,
2008 2007 2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(unaudited)
Cash provided by (used in):
Operating Activities:
Net income $ 29,282 $ 33,936 $ 101,580 $ 95,566
Items not requiring
cash from operations:
Depreciation, depletion
and accretion 63,965 56,568 129,331 111,993
Unit-based compensation 2,460 1,421 4,773 2,833
Unrealized (gains) losses
on financial instruments 108,224 (3,830) 127,688 9,175
Future income taxes
(reductions) (20,019) 38,016 (24,328) 35,056
Asset retirement
expenditures (4,204) (1,093) (7,122) (1,473)
Changes in non-cash
working capital items 986 (8,008) 13,421 (4,273)
----------------------------------------------------------------------------
180,694 117,010 345,343 248,877
----------------------------------------------------------------------------
Financing Activities:
Issuance of equity, net
of issue costs 214,401 3,361 219,103 6,371
Distributions (81,915) (76,662) (159,343) (153,106)
Changes in long-term debt (248,772) 29,810 (105,522) 60,252
Changes in non-cash
working capital items (989) (534) (326) (271)
----------------------------------------------------------------------------
(117,275) (44,025) (46,088) (86,754)
----------------------------------------------------------------------------
Investing Activities:
Exploitation and
development (62,166) (67,715) (155,431) (158,331)
Property acquisitions (5,454) 55 (174,828) (910)
Property dispositions 683 100 683 100
Changes in non-cash working
capital items 3,518 (5,425) 30,321 (2,982)
----------------------------------------------------------------------------
(63,419) (72,985) (299,255) (162,123)
----------------------------------------------------------------------------
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 six months ended June 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. The Trust continues to monitor and assess the impact of the
planned convergence of Canadian GAAP with IFRS.
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 June 30, 2008 Bonavista charged NuVista $373,000
(2007 - $370,000) 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 - nil). For the six months
ended June 30, 2008 Bonavista charged NuVista $786,000 (2007 - $712,000) in fees
relating to general and administrative services provided to NuVista, in addition
NuVista charged Bonavista management fees for a jointly owned partnership
totaling $675,000 (2007 - nil). Bonavista also charged NuVista $71,800 (2007 -
$604,000) for costs that are outside the TSA during the first six months of 2008
relating to NuVista's share of direct charges from third parties. As at June 30,
2008, the amount payable to NuVista was $2.2 million.
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 $556.7 million (2007 - $487.4 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:
----------------------------------------------------------------------------
Six Months
ended June 30,
2008 2007
----------------------------------------------------------------------------
(thousands)
Balance, beginning of period $ 116,893 $ 96,324
Accretion expense 4,190 3,429
Liabilities incurred 4,682 492
Liabilities acquired 2,487 -
Liabilities settled (7,122) (1,473)
----------------------------------------------------------------------------
Balance, end of period $ 121,130 $ 98,772
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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. At present, no principal
payments are required under the credit facility until August 10, 2010.
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 six months ended June 30, 2008 include interest on
bank loans of $18.1 million (2007 - $12.9 million) and convertible debentures of
$1.7 million (2007 - $1.8 million). For the six months ended June 30, 2008,
Bonavista paid cash interest of $20.1 million (2007 - $15.0 million). For the
six months ending June 30, 2008 our effective interest rate was 4.4% (2007 -
5.0%).
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 June 30, 2008:
----------------------------------------------------------------------------
Debt Equity
Component Component
----------------------------------------------------------------------------
(thousands)
Balance, December 31, 2007 $ 48,830 $ 1,054
Accretion 33 -
Issue expenses related to conversions to trust
units 37 -
Amortization of issue expenses 346 -
Conversion to trust units (4,777) (98)
----------------------------------------------------------------------------
Balance, June 30, 2008 $ 44,469 $ 956
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 171 4,777
Issued on conversion of exchangeable shares 98 329
Issued upon exercise of trust unit incentive rights 904 15,967
Conversion of restricted trust units 53 -
Issue costs, related to debenture conversions - (37)
Issue costs, net of future tax benefit - (8,426)
Adjustment to equity component of debenture on
conversion - 98
Unit-based compensation - 7,040
----------------------------------------------------------------------------
Balance, June 30, 2008 93,983 $ 1,084,579
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(ii) Contributed surplus:
----------------------------------------------------------------------------
Amount
----------------------------------------------------------------------------
(thousands)
Balance, December 31, 2007 $ 9,369
Unit-based compensation expense 4,773
Unit-based compensation capitalized 610
Exercise of trust unit incentive rights and conversion of
restricted trust units (7,040)
----------------------------------------------------------------------------
Balance, June 30, 2008 $ 7,712
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(iii) Exchangeable shares:
----------------------------------------------------------------------------
Number Amount
----------------------------------------------------------------------------
(thousands)
Balance, December 31, 2007 12,230 $ 74,710
Exchanged for trust units (53) (329)
----------------------------------------------------------------------------
Balance, June 30, 2008 12,177 $ 74,381
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Exchange ratio, June 30, 2008 1.82966 -
----------------------------------------------------------------------------
Trust units issuable on exchange 22,279 $ 74,381
----------------------------------------------------------------------------
----------------------------------------------------------------------------
c) Long term incentive plans:
For the three months ended June 30, 2008 there were 10,540 restricted trust
units granted and 106,800 trust unit incentive rights issued with an average
exercise price of $29.70 per trust unit and an estimated fair value of $7.36 per
trust unit. As at June 30, 2008 there were 114,566 restricted trust units
outstanding and 2,750,225 trust unit rights outstanding with an average exercise
price of $25.04 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 27%; 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 June 30, 2008
----------------------------------------------------------------------------
(thousands)
Trust units 91,356
Exchangeable shares converted at the exchange ratio 22,357
----------------------------------------------------------------------------
Basic equivalent trust units 113,713
Convertible debentures 1,775
Trust unit incentive rights 689
Restricted trust units 115
----------------------------------------------------------------------------
Diluted equivalent trust units 116,292
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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, and arises principally from the Trust's receivables from crude oil
and natural gas marketers and joint venture partners.
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 June 30, 2008 the Trust's receivables consisted of $95.9 million
of receivables from crude oil and natural gas marketers which has substantially
been collected, $19.2 million from joint venture partners of which $2.1 million
has been subsequently collected, and $16.5 million of Crown deposits, prepaids
and inventory. As at June 30, 2008 the Trust has $10.2 million in accounts
receivable that is considered to be past due. Although these amounts have been
outstanding for greater than 90 days, they are still deemed to be collectible.
The Trust does not have an allowance for doubtful accounts as at June 30, 2008
and did not provide for any doubtful accounts nor was it required to write-off
any receivables during the period ended June 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 with conversion
prices of $23.00 and $29.00, we expect that both of these convertible debenture
series will convert to trust units prior to maturity as the current trust unit
trading price exceeds the conversion price. The Trust also maintains and
monitors a certain level of cash flow which is used to partially finance all
operating, investing and capital expenditures.
(c) Market risk:
Market risk is the risk that changes in market conditions, such as commodity
prices, interest rates, and foreign exchange rates, will affect the Trust's net
income or the value of financial instruments. The objective of market risk
management is to manage and control market risk exposures within acceptable
limits, while maximizing the Trust's returns.
The Trust utilizes both financial derivatives and physical delivery sales
contracts to manage market risks. All such transactions are conducted in
accordance with the Trust's risk management policy that has been approved by the
Board of Directors.
i) Commodity price risk
Commodity price risk is the risk that the fair value of future cash flows will
fluctuate as a result of changes in commodity prices. Commodity prices for crude
oil and natural gas are impacted not only by global economic events that dictate
the levels of supply and demand but also by the relationship between the
Canadian and United States dollar. The Trust has attempted to mitigate a portion
of the commodity price risk through the use of various financial derivative and
physical delivery sales contracts. The Trust's policy is to enter into commodity
price contracts when considered appropriate to a maximum of 60% of forecasted
production volumes.
As at June 30, 2008, the Trust has hedged by way of costless collars to sell
natural gas (gjs/d) and crude oil (bbls/d) as follows:
----------------------------------------------------------------------------
Volume Average Price Term
----------------------------------------------------------------------------
July 1, 2008 -
35,000 gjs/d CDN$ 7.43 - CDN$ 8.77 - AECO October 31, 2008
November 1, 2008 -
10,000 gjs/d CDN$ 9.25 - CDN$ 13.50 - AECO March 31, 2009
April 1, 2009 -
5,000 gjs/d CDN$ 9.00 - CDN$ 12.00 - AECO October 31, 2009
July 1, 2008 -
7,000 bbls/d US$ 65.43 - US$ 78.58 - WTI December 31, 2008
July 1, 2008 -
4,000 bbls/d CDN$ 61.75 - CDN$ 70.88 - Bow River December 31, 2008
January 1, 2009 -
1,000 bbls/d CDN$ 70.00 - CDN$ 78.00 - Bow River December 31, 2009
January 1, 2009 -
1,000 bbls/d CDN$ 85.00 - CDN$125.25 - WTI December 31, 2009
April 1, 2009 -
2,000 bbls/d CDN$ 100.00 - CDN$ 169.00 - WTI December 31, 2009
January 1, 2009 -
2,000 bbls/d US$ 65.00 - US$ 80.50 - WTI March 31, 2009
April 1, 2009 -
1,000 bbls/d US$ 85.00 - US$ 105.60 - WTI 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 June 30,
2008 2007
----------------------------------------------------------------------------
Realized gains (losses) on financial
instruments $ (39,967) $ 834
Unrealized gains (losses) on financial
instruments (108,224) 3,830
----------------------------------------------------------------------------
$ (148,191) $ 4,664
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 $407,000 and $2.6
million, respectively, on net income for those commodity price contracts that
were in place as at June 30, 2008.
ii) Physical purchase contracts:
As at June 30, 2008, the Trust has entered into direct sale costless collars to
sell natural gas as follows:
ii) Physical purchase contracts:
As at June 30, 2008, the Trust has entered into direct sale costless collars
to sell natural gas as follows:
----------------------------------------------------------------------------
Volume Average Price (CDN$ - AECO) Term
----------------------------------------------------------------------------
45,000 gjs/d $ 7.19 - $ 8.36 July 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
----------------------------------------------------------------------------
Subsequent to June 30, 2008, the Trust has entered into direct sale costless
collars to sell natural gas as follows:
----------------------------------------------------------------------------
Volume Average Price (CDN$ - AECO) Term
----------------------------------------------------------------------------
5,000 gjs/d $ 8.00 - $ 10.13 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 June 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 six months ended June 30, 2008 would have a $1.3 million and $2.9 million
impact respectively. For the similar periods in 2007 net income would be
impacted by approximately $844,000 and $1.9 million respectively. The
sensitivity impact is higher for the periods ending in 2008 because of an
increase in the weighted average outstanding bank debt. The Trust had no
interest rate swap or financial contracts in place as at or during the period
ended June 30, 2008.
Fair value of financial instruments
The Trust's financial instruments as at June 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 June 30, 2008, the market deficit of these derivative
financial instruments was approximately $172.7 million.
The fair market value of the convertible debentures as at June 30, 2008 is $61.6
million, which has been determined by its June 30, 2008 closing trading price.
Bank debt bears interest at a floating market rate and accordingly the fair
market value approximates the carrying value.
8. Capital management:
The Trust's objective when managing capital is to maintain a flexible capital
structure which allows it to execute its growth strategy through strategic
acquisitions and expenditures on exploration and development activities while
maintaining a strong financial position that provides our unitholders with
stable distributions and rates of return.
The Trust considers its capital structure to include working capital (excluding
unrealized gains and losses on financial instruments), convertible debentures,
bank debt, and unitholders' equity. The Trust monitors capital based on the
ratio of net debt to annualized funds from operations. The ratio represents the
time period it would take to pay off the debt if no further capital expenditures
were incurred and if funds from operations remained constant. This ratio is
calculated as net debt, defined as outstanding bank debt plus or minus net
working capital, divided by funds from operations for the most recent calendar
quarter, annualized (multiplied by four). The Trust's strategy is to maintain a
ratio of no more than 2.0 to 1. This strategy is more restrictive than the
existing financial covenants on the Trust's credit facility. This ratio may
increase at certain times as a result of acquisitions or low commodity prices.
As at June 30, 2008, the Trust's ratio of net debt to annualized funds from
operations was 0.9 to 1 (2007 - 1.1 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 June 30, 2008.
INVESTOR INFORMATION
Bonavista Energy Trust is a natural gas weighted energy trust which is committed
to maintaining its emphasis on operating high quality oil and natural gas
properties, delivering consistent distributions to unitholders and ensuring
financial strength and sustainability.
Corporate information provided herein contains forward-looking information. The
reader is cautioned that assumptions used in the preparation of such
information, particularly those pertaining to cash distributions, production
volumes, commodity prices, operating costs and drilling results, which are
considered reasonable by Bonavista at the time of preparation, may be proven to
be incorrect. Actual results achieved during the forecast period will vary from
the information provided herein and the variations may be material. There is no
representation by Bonavista that actual results achieved during the forecast
period will be the same in whole or in part as those forecast.
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