Bonterra Energy Income Trust Announces Second Quarter Results
CALGARY, Aug. 14 /CNW/ - Bonterra Energy Income Trust
(www.bonterraenergy.com) (TSX:BNE.UN) is pleased to announce its financial and
operational results for the six months ended June 30, 2007.HIGHLIGHTS
----------
Three Months Ended Six Months Ended
June 30 June 30
2007 2006 2007 2006
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FINANCIAL ($000, except $ per unit)
Revenue - oil and gas 23,462 23,219 46,064 43,350
Funds Flow from Operations(1) 11,695 14,008 24,824 26,161
Per Unit - Basic 0.69 0.84 1.47 1.57
Per Unit - Diluted 0.69 0.83 1.47 1.56
Net Earnings 4,440 10,617 13,344 20,338
Per Unit - Basic 0.26 0.64 0.79 1.22
Per Unit - Diluted 0.26 0.63 0.79 1.21
Cash Distributions per Unit 0.66 0.69 1.32 1.38
Capital Expenditures and Acquisitions 1,699 6,246 9,324 16,294
Total Assets 139,432 122,166
Working Capital Deficiency(2) 49,595 28,820
Unitholders Equity 51,920 61,202
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OPERATIONS
Oil and NGL's
Barrels Per Day 3,074 3,001 3,150 2,999
Average Price ($ per barrel) 67.60 69.90 65.02 63.46
Natural Gas
MCF Per Day 6,663 6,181 6,567 6,127
Average Price ($ per MCF) 7.40 7.16 7.46 7.83
Total Barrels per Day 4,185 4,031 4,245 4,020
(1) Funds flow from operations is not a recognized measure under GAAP.
Management believes that in addition to net earnings, funds flow from
operations is a useful supplemental measure as it demonstrates the
Trust's ability to generate the cash necessary to make trust
distributions, repay debt or fund future growth through capital
investment. Investors are cautioned, however, that this measure
should not be construed as an indication of the Trust's performance.
The Trust's method of calculating this measure may differ from other
issuers and accordingly, it may not be comparable to that used by
other issuers. For these purposes, the Trust defines funds flow from
operations as funds provided by operations before changes in non-cash
operating working capital items excluding gain on sale of property
and asset retirement expenditures.
(2) Includes 100 percent of debt.
(3) BOE's are calculated using a conversion ratio of 6 MCF to 1 barrel of
oil. The conversion is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent
a value equivalency at the wellhead and as such may be misleading if
used in isolation.Forward-looking Information
---------------------------
Certain statements contained in this press release include statements
which contain words such as "anticipate", "could", "should", "expect", "seek",
"may", "intend", "likely", "will", "believe" and similar expressions, relating
to matters that are not historical facts, and such statements of our beliefs,
intentions and expectations about development, results and events which will
or may occur in the future, constitute "forward-looking information" within
the meaning of applicable Canadian securities legislation and are based on
certain assumptions and analysis made by us derived from our experience and
perceptions. Forward-looking information in this press release includes, but
is not limited to: expected cash provided by continuing operations; cash
distributions; future capital expenditures, including the amount and nature
thereof; oil and natural gas prices and demand; expansion and other
development trends of the oil and gas industry; business strategy and outlook;
expansion and growth of our business and operations; and maintenance of
existing customer, supplier and partner relationships; supply channels;
accounting policies; credit risks; and other such matters.
All such forward-looking information is based on certain assumptions and
analyses made by us in light of our experience and perception of historical
trends, current conditions and expected future developments, as well as other
factors we believe are appropriate in the circumstances. The risks,
uncertainties, and assumptions are difficult to predict and may affect
operations, and may include, without limitation: foreign exchange
fluctuations; equipment and labour shortages and inflationary costs; general
economic conditions; industry conditions; changes in applicable environmental,
taxation and other laws and regulations as well as how such laws and
regulations are interpreted and enforced; the ability of oil and natural gas
trusts to raise capital; the effect of weather conditions on operations and
facilities; the existence of operating risks; volatility of oil and natural
gas prices; oil and gas product supply and demand; risks inherent in the
ability to generate sufficient cash flow from operations to meet current and
future obligations; increased competition; stock market volatility;
opportunities available to or pursued by us; and other factors, many of which
are beyond our control.
Actual results, performance or achievements could differ materially from
those expressed in, or implied by, this forward-looking information and,
accordingly, no assurance can be given that any of the events anticipated by
the forward-looking information will transpire or occur, or if any of them do,
what benefits will be derived therefrom. Except as required by law, Bonterra
disclaims any intention or obligation to update or revise any forward-looking
information, whether as a result of new information, future events or
otherwise.
The forward-looking information contained herein is expressly qualified
by this cautionary statement.
General
-------
Bonterra Energy Income Trust ("Bonterra" or "the Trust") is pleased to
report its results for the first half of 2007. Oil and natural gas revenue
increased by six percent from $43,350,000 in the 2006 six month period to
$46,064,000 for the 2007 six month period. The increase is mainly attributable
to an increase in production volumes of 5.6 percent to 4,245 barrels of oil
equivalent (BOE's) from 4,020 BOE's for the comparable six month period.
Funds flow from operations and net earnings decreased by 5 and 34 percent
respectively in 2007 compared to the results from the first half of 2006. Both
reductions were principally due to one time issues that related to prior years
and the first quarter of 2007 and were all recorded in the second quarter of
2007. The one time issues that affected net earnings and fund flow from
operations consisted of an approximately $850,000 royalty adjustment for 2005,
2006 and Q1 2007 and extra operating costs and reworking costs to existing
producing and non-producing wells that will assist in increased production
volumes in future quarters.
Other cash items that had a negative impact on funds flow and net
earnings were an approximate $1,000,000 increase in operating costs, an
interest expense increase of $787,000 and the elimination of Alberta royalty
tax credits resulting in a reduction of revenue of $335,000 and no gain on
sale of property in 2007 compared to a 2006 gain of $532,000.
These negatives more than offset the increase in oil and gas revenues
(including hedging adjustments) of $2,714,000 and the reduction of general and
administrative costs of $153,000. Net earnings were also affected by an
increase in non-cash items of $1,279,000 of depletion, depreciation and
accretion, dry hole costs of $476,000 and additional future income taxes of
$3,864,000 (resulting mainly from the Federal Governments legislated change in
how Trusts will be taxed).
The above items also had an impact on the payout ratio for the first six
months of 2007 resulting in a payout ratio of 90 percent compared to an
objective of 80 percent. Production increases and the elimination of one time
charges during the last half of 2007 should assist in improving upon this
ratio. Obviously commodity prices will influence funds flow as well.
Bonterra's production consists of approximately 75 percent oil and therefore
may not be impacted too much by the projected lower natural gas prices.
At June 30, 2007, Bonterra had 7 gross (4.8 net) Cardium oil wells,
12 gross (9 net) natural gas wells, and 7 gross (5.5 net) coal-bed methane
wells (CBM) drilled but not on production. The majority of these wells
(excluding the CBM wells) will be completed and tied-in by the end of Q3 2007.
The Trust does not anticipate the completion and tie-in of the CBM wells will
occur until sometime in 2008.
While service costs continue to be high, Bonterra will continue to focus
more on directing capital expenditures towards completions, tie-ins, reworking
of existing wells, recompletions of gas zones to take advantage of new
commingling regulations for gas wells, and refracing of existing Cardium oil
wells rather than just drilling new wells. Exceedingly wet weather during the
second quarter delayed the implementation of the above however, despite
reducing the capital expenditure budget for 2007 to $20 million from
$38 million in 2006 and the delay; Bonterra may still grow its production
volumes by conducting these types of programs during the balance of the year.
With regard to dealing with the federal taxation changes that were
announced on October 31, 2006 and now have been legislated, Bonterra is
evaluating the implications and various alternatives that are available to
mitigate the impact of the additional taxes commencing in 2011. One of the
difficult issues that has to be dealt with is that Bonterra has three types of
unitholders that are affected differently; being Canadian resident unitholders
that hold the units outside of tax shelters, Canadian resident unitholders
that hold units within tax shelters and foreign unitholders. Generally what is
beneficial for one type of unitholder may be detrimental to other types of
unitholders.
The Trust continues to have upside potential by continuing to drill and
develop its large inventory of undrilled locations and potentially from
additional recovery of oil in place by water flooding, CO(2) sequestration,
and by reworking and refracing existing producing and suspended wells.
Production
----------
Average daily production volume for the six months ended June 30, 2007
was 4,245 barrels of oil equivalent (BOE's) per day. BOE's are calculated
using a conversion ratio of 6 MCF to 1 barrel of oil. The conversion is based
on an energy equivalency conversion method primarily applicable at the burner
tip and does not represent a value equivalency at the wellhead and as such may
be misleading if used in isolation.
The Trust drilled 7 gross (6.4 net) Cardium oil wells and 2 gross
(0.7 net) shallow gas wells in the first six months of 2007 on its operated
lands. As at June 30, 2007 Bonterra had 7 gross (4.8 net) Cardium oil wells,
12 gross (9 net) natural gas wells and 7 gross (5.5 net) coal-bed wells
drilled but not on production on its operated lands. During the first six
months of 2007, the Trust tied-in 11 gross (10.7 net) Cardium wells and
2 gross (1 net) natural gas wells on its operated lands.
Management anticipates that all the currently drilled but not producing
Cardium wells will be completed and tied-in by the end of the third quarter of
2007. Seven gross (4.1 net) of the natural gas wells are anticipated to be
completed and tied-in by the end of the third quarter of 2007. The remaining
shallow gas wells and coal-bed methane wells will not be completed and tied-in
in 2007 for various reasons, including landowner issues, regulatory factors,
gathering system capacity and line pressure issues.
The Trust has been active in reworking existing natural gas wells
resulting in significant increases to production without the necessity of
drilling further wells. Production gains from such reworks as well as solution
gas from the newly completed Cardium oil wells has accounted for the majority
of the natural gas production increases in the first half of 2007. Overall
production rates in the second quarter of 2007 were affected by normal spring
break up conditions resulting in the inability to perform maintenance on wells
as well as higher initial declines in production on the newly completed
Cardium oil wells which is a normal happening for new Cardium wells.
Revenue
-------
Revenue from petroleum and natural gas sales was $46,064,000 (2006 -
$43,350,000). The increase in revenue over the 2006 first half was primarily
due to additional production from the wells drilled during 2006. The average
price received for crude oil and natural gas liquids during the first six
months of 2007 was $65.02 ($67.60 in the second quarter) per barrel and $7.46
($7.40 in the second quarter) per MCF for natural gas compared to $63.46 per
barrel and $7.83 per MCF in the corresponding 2006 period. On a quarter over
quarter basis, revenue increased by $860,000 due primarily to increased crude
oil prices from first quarter pricing of $62.53 offset partially by reduced
production volumes.
Gross revenue increased by $815,000 (2006 decreased by $1,091,000) due to
higher prices received as a result of price hedging. The Trust will continue
to assess hedging future production to assist in managing its funds flow. The
Trust continues to follow the policy of protecting production that has high
operating costs with hedges that provide a significant level of profitability
and also to provide for a reasonable amount of funds flow protection for
development projects. The Trust will however maintain a policy of not hedging
more than 50 percent of production to allow it to benefit from any price
movements in either crude oil or natural gas. Kindly refer to Notes 9 and 10
to the attached interim financial statements for present hedging details. At
June 30, 2007, the fair value of the outstanding commodity hedging contracts
was a net asset of $710,000 (December 31, 2006 - $1,189.000).
Royalties
---------
During the second quarter of 2007, two significant royalty adjustments
were recorded. Firstly, the Trust discovered that the production limit
resulting in additional gross overriding royalty in respect of certain of its
Cardium oil wells had been reached. The production limit was calculated on a
multitude of Cardium wells including several that were not owned by the Trust.
In addition the exact wells that the production limit was applicable to was
not readily known by the Trust nor easily calculated. In discussions with the
payee it was determined that the combined production limit for all entities
involved was reached in late 2005. The royalty has been calculated based on
this agreed date and the affected wells for Bonterra and other operators in
the area were identified. The approximate amount of the adjustment, net to the
Trust is $700,000 for periods prior to April 1, 2007. The monthly amount of
the royalty on a go forward basis for Bonterra is approximately $40,000 per
month based on current pricing and production levels.
Secondly, the Trust was informed by the operator of one of its
non-operated properties that it had not charged a net profit royalty for the
years 2004, 2005 and 2006. In review of the agreements it was confirmed no
payment was made and an amount of approximately $150,000 was accrued by the
Trust for payment of such net profit royalty.
Royalties paid by the Trust consist of Crown royalties paid to the
Provinces of Alberta and Saskatchewan as well as numerous gross override and
freehold royalties. During the first six months of 2007 the Trust paid
$4,545,000 (2006 - $4,389,000) in Crown royalties and $1,901,000, which
includes the above described adjustments of $700,000 and $150,000, (2006 -
$1,062,000) in freehold royalties, gross overriding royalties and net carried
interests. The majority of the Trust's wells are low productivity wells and
therefore have low Crown royalty rates. The Trust's average Crown royalty rate
is approximately ten percent (2006 - ten percent) and approximately
2.5 percent (after adjusting for the one time items discussed above) (2006 -
2.5 percent) for other royalties before hedging adjustments. The Trust was
eligible for Alberta Crown Royalty rebates for Alberta production from all
wells that it drilled on Crown lands and from a small amount of purchased
wells; however this program was discontinued by the Alberta Government
effective January 1, 2007 which resulted in a reduction of revenue of $335,000
in 2007.
Gain on Sale of Property
------------------------
During the first quarter of 2006, the Trust disposed of a non-operated;
non-core property for gross proceeds of $750,000 (approximately $75,000 per
producing BOE). The Trust follows successful efforts accounting for its oil
and gas properties and therefore reported a gain of $532,000 on the difference
between the depleted value of the property and the above proceeds.
Production Costs
----------------
Production costs for the six months ended June 30, 2007 were $12,137,000
compared to $10,552,000 for the six months ended June 30, 2006. On a BOE basis
production costs averaged $15.80 in 2007 ($17.21 in Q2) verses $14.50 in the
corresponding 2006 period. Production costs in Q2 increased $975,000 over Q1
due to the Trust performing numerous maintenance programs on its oil producing
facilities and pipelines and the operators of a number of the Trusts gas
plants performed their annual turnarounds. In addition a number of natural gas
production optimizations were performed and the costs associated with this
program were expensed. These optimizations should result in increased
production volumes in the future. The balance of the increase on a year over
year basis is due to higher costs being charged by the oil and gas service
industry.
The Trust's production comes primarily from low productivity wells. These
wells generally result in higher production costs on a per unit-of-production
basis as costs such as municipal taxes, surface lease, power and personnel
costs are not variable with production volumes. Production costs in the $14 to
$15 per BOE range are expected. The high production costs for the Trust are
substantially offset by low royalty rates of approximately 12.5 percent, which
is much lower than industry average for conventional production and results in
high cash net backs on a combined basis despite higher than average production
costs.
General and Administrative Expenses
-----------------------------------
General and administrative expenses were $1,091,000 ($527,000 in the
second quarter) in the first half of 2007 compared to $1,244,000 in the six
months ended June 30, 2006 and $564,000 in the three months ended March 31,
2007. Costs on a BOE bases decreased to $1.44 per BOE in the first half of
2007 compared to $1.71 per BOE in the first half of 2006. The decrease in
general and administrative expenses year over year was due primarily to
approximately a $140,000 decrease in third party consulting fees. Increases in
employee salary compensation were offset by reduced bonus accruals and a
general reduction in overall office expenditures. The quarter over quarter
amounts were not significantly different other than annual report and filing
costs for the year were incurred in the first quarter.
Interest Expense
----------------
Interest expense increased to $1,441,000 ($744,000 in the second quarter)
for the six months ended June 30, 2006 compared to $654,000 for the six months
ended June 30, 2006 and $697,000 for the first quarter of 2007. Increased
average debt levels and increased interest rates were the primary factors for
the increase in interest expense. The Trust's average borrowing rate for 2007
was approximately 5.6 percent compared to 5 percent for the first six months
of 2006. The Trust's net debt as a percentage of annualized second quarter
funds flow was approximately twelve and three quarter months which is slightly
higher than the Trust's goal of one year.
The Trust's bank loan of $54,601,000 increased by approximately
$9.2 million from the $45,379,000 at December 31, 2006. The increase is due to
the payment of the balance of the costs for the 2006 fourth quarter drilling
program as well as for expenditures related to the Trust's winter 2007 drill
program of $9,324,000 which represents 47 percent of the Trust's estimated
2007 capital expenditure program of $20,000,000.
Unit Based Compensation
-----------------------
Unit based compensation is a statistically calculated value representing
the estimated expense of issuing employee unit options. The Trust records a
compensation expense over the vesting period based on the fair value of
options granted to employees, directors and consultants.
The Trust issued 522,000 unit options of which 517,000 were issued at the
end of June 2007 at an average price of $28.30 and a fair value of $2.74 per
unit. The fair value of the options granted has been estimated using the
Black-Scholes option pricing model, assuming a weighted risk free interest
rate of 4.7 (2006 - 4.1) percent, expected weighted average volatility of
27 percent (2006 - 27), expected weighted average life of 2.5 years (2006 -
2.5) and an annual dividend rate based on the distributions paid to the
Unitholders during the year. As the options were issued at the end of the
quarter no significant expense in relation to these options was recorded in
Q2. The future unit based compensation impact of these options is
approximately $235,000 per quarter over the next five quarters.
Depletion, Depreciation and Accretion
-------------------------------------
Provision for depletion, depreciation and accretion was $6,786,000 and
$5,507,000 for the six month periods ending June 30, 2007 and June 30, 2006
respectively. The increase was primarily due to increased production resulting
from the Trust's 2006 drill program. The Trust continues to replace production
declines with newly drilled wells that have higher capital costs. The Trust
has capital costs of approximately $6 per proven BOE of reserves based on the
December 31, 2006 independent engineering report. The decrease in Q2 of
$218,000 from Q1 depletion amounts was due to reduced production volumes.
Dry hole costs of $476,000 relate to additional costs required in 2007 to
properly reclaim well sites relating to the seven shallow gas wells considered
to be dry holes in 2006. No additional dry holes were determined to exist
during the first half of 2007.
Income Taxes
------------
Please refer to Note 5 to the attached Financial Statements for details
pertaining to income taxes.
Net Earnings
------------
Net earnings decreased to $13,344,000 in the first six months of 2007
from $20,338,000 in the corresponding 2006 period. Revenue increases due to
increased production volumes were generally offset by increased operating
costs, interest expense, depletion, depreciation accretion and dry hole costs,
and provision for future income taxes. The Trust's quarter over quarter net
earnings decreased by $4,464,000 primarily due to these combined items and are
explained in detail in various sections of this report.
Comprehensive Income
--------------------
On January 1, 2007 the Trust became obliged to adopt the new accounting
standards regarding the accounting for financial instruments. On adoption the
Trust increased its investment in related party by $1,836,000 for the fair
value of this investment. On January 1, 2007 the Trust further recognized a
current asset of $1,148,000 for the fair value of its commodity derivative
contracts. These adjustments resulted in a further increase in the future
income tax liability and accumulated other comprehensive income of $604,000
and $2,380,000 respectively.
Other comprehensive income for the six months included an increase in the
unrealized gain on investment in a related party of $628,000, a reduction of
$577,000 relating to the recognition and transfer of previously reported gains
in accumulated other comprehensive income and a gain of $266,000 was recorded
in relation to the fair value adjustment on outstanding commodity derivative
contracts. All of the above adjustments are net of applicable income tax
effects.
Standardized Distributable Cash
-------------------------------
Compliance with Guidance
The following Management, Discussion and Analysis is in all material
respects in accordance with the recommendations provided in CICA's publication
Standardized Distributable Cash in Income Trusts and Other Flow-Through
Entities: Guidance on Preparation and Disclosure. All trusts will be obligated
to adopt these recommendations commencing with the third quarter of 2007.
Bonterra has decided to commence with these changes for this report.Definition and Disclosure of Standardized Distributable Cash
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Cumulative
Amounts From
Six Months Six Months Inception
Ended June Ended June of Trust
2007 2006 (July 1, 2001)
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Cash Flow from Operating
Activities $26,178,000 $25,921,000 $166,842,000
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Less adjustment for:
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Capital expenditures (9,324,000) (16,294,000) (75,198,000)
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Financing restrictions caused
by debt - - -
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Standardized Distributable Cash $16,854,000 $ 9,627,000 $92,473,000
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Definition and Disclosure of Adjusted Distribution Base (Formerly Funds
Flow from Operations)
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Cumulative
Amounts From
Six Months Six Months Inception
Ended June Ended June of Trust
2007 2006 (July 1, 2001)
-------------------------------------------------------------------------
Standardized Distributable Cash
- per above $16,854,000 $ 9,627,000 $92,473,000
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Adjusted for:
-------------------------------------------------------------------------
Capital expenditures 9,324,000 16,294,000 75,198,000
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Gain on sale of property - 532,000 1,089,000
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Changes in accounts receivable (599,000) (290,000) 4,494,000
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Changes in crude oil inventory (65,000) 153,000 304,000
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Changes in parts inventory (24,000) 4,000 (208,000)
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Changes in prepaid expenses 454,000 531,000 254,000
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Changes in accounts payable
and accrued liabilities (1,429,000) (815,000) 1,594,000
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Asset retirement obligations
settled 309,000 125,000 1,709,000
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Adjusted Distribution Base
(formerly Funds Flow from
Operations)(1) $24,824,000 $26,161,000 $176,907,000
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(1) Funds flow from operations is not a recognized measure under GAAP.
The Trust believes that in addition to net earnings, funds flow from
operations is a useful supplemental measure as it demonstrates the
Trust's ability to generate the cash necessary to make trust
distributions, repay debt or fund future growth through capital
investment. Investors are cautioned, however, that this measure
should not be construed as an indication of the Trust's performance.
The Trust's method of calculating this measure may differ from other
issuers and accordingly, it may not be comparable to that used by
other issuers. For these purposes, the Trust defines funds flow from
operations as funds provided by operations before changes in non-cash
operating working capital items excluding gain on sale of property.Working Capital Policies
The Trust, excluding current portion of debt, maintains a consistent
level of working capital. All items of working capital are generally turned
over every 30 to 60 days. Excluding minor variations due to payment of bonuses
and property taxes there are no recurring items that would cause a seasonal
impact in working capital.Analysis of Relationship between Standardized Distributable Cash,
Distributions, and Investing and Financing Activities
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Six Months Year ended Year ended Year ended
Ended June December 31, December 31, December 31,
2007 2006 2005 2004
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Standardized
Distributable
Cash $16,854,000 $13,596,000 $22,316,000 $18,875,000
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Distributions(1) ($22,309,000) ($47,281,000) ($38,949,000) ($27,088,000)
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Increase in bank
debt $9,222,000 $25,202,000 $11,717,000 ($17,969,000)
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Proceeds on issuance
of employee unit
options $705,000 $5,161,000 $2,823,000 $3,292,000
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Issuance of units
(net of costs of
issue) - - ($259,000) $20,272,000
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Proceeds on sale
of properties - $750,000 $1,097,000 -
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Non cash financing
and investing
working capital
adjustments ($4,472,000) $2,572,000 $1,255,000 $2,618,000
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(1) Includes distribution declared in July in respect of June operations.
The only unfunded operating transaction of the Trust is its asset
retirement obligations. The Trust has the following estimated timing of
expenditures for asset retirement obligations:
Expected
Year Expenditure
-----------------------------------------------------------
2007 (including expenditures incurred to date) $421,000
2008 494,000
2009 398,000
2010 986,000
2011 805,000
-----------------------------------------------------------
-----------------------------------------------------------
$3,104,000
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-----------------------------------------------------------Definition and History of Productive Capacity and Strategy
Bonterra's primary objective is to grow its reserves from which it
expects to continue with distributions for its unitholders. The Trust defines
Productive Capacity Maintenance as the maintaining of the Trusts proven plus
probable reserves. The Trust follows a policy of internal development as its
primary method of planned growth. Bonterra has a significant inventory of
undrilled Cardium oil infill drilling locations as well as several shallow gas
opportunities on its lands or through farm-in agreements. It is management's
view that the calculation of the amount required for Productive Capacity
Maintenance is the amount of reserves produced in the relevant time period
multiplied by the Trust's finding and development costs for proven plus
probable reserves. For this purpose the Trust believes that the use of a three
year average rate is reasonable given fluctuations in annual costs due to
market conditions.-------------------------------------------------------------------------
Six Months Year ended Year ended Year ended
Ended June December 31, December 31, December 31,
2007 2006 2005 2004
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Proven and probable
reserves at
beginning of
period (BOE's) 26,476,000 23,870,000 19,711,000 16,529,000
-------------------------------------------------------------------------
Reserves added due
to acquisitions
(BOE's) - 16,000 2,393,000 -
-------------------------------------------------------------------------
Reserves added
due to capital
expenditures
(BOE's) (1) 4,082,000 3,100,000 4,351,000
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Production during
period (BOE's) 757,000 1,476,000 1,334,000 1,169,000
-------------------------------------------------------------------------
Increase in
productive
capacity
(BOE's) (1) 2,606,000 4,159,000 3,182,000
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Reserves per unit
(fully diluted) 1.52(2) 1.57 1.46 1.39
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Productive capacity
maintenance
requirements $12,043,000 $17,472,000 $9,205,000 $3,460,000
-------------------------------------------------------------------------
Capital expenditures
for the period $9,324,000 $38,348,000 $56,703,000 $10,595,000
-------------------------------------------------------------------------
Capital expenditures
in excess of
maintenance
requirements ($2,719,000) $20,876,000 $47,498,000 $7,135,000
-------------------------------------------------------------------------
Cost of increased
productive capacity
(per BOE) (1) $8.01 $11.42 $2.24
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(1) The Trust does not update reserve information quarterly.
(2) Assuming no additional reserves in 2007.Financing Strategy
The Trust maintains a strategy of limiting its debt levels to
approximately one year funds flow. Bonterra has a long term goal to retain
between 15 to 20 percent of its funds flow to finance its capital maintenance
expenditures. Over the past years, this level of retention of funds has proven
to be sufficient to amply maintain the productive capacity of the Trust. To
the extent additional capital expenditures are incurred to increase reserves,
the Trust anticipates financing them through proceeds received on exercise of
employee unit options, equity placements or from its line of credit.
Periods may exist where the cost of replacing reserves exceed the level
of funds withheld. However, the Trust with its long life reserves and
relatively low debt levels compared to other income trusts has the flexibility
to increase or decrease its capital commitments depending on commodity prices
and costs of development.
It is management's strategy to finance the costs of reclamation as well
as potential income taxes (commencing in 2011) resulting from the recently
enacted income trust tax law from funds flow. Management is reviewing various
organizational alternatives and operational strategies to mitigate the impact
of the new tax.
Compliance with Financial Covenants
Due to the relatively low debt levels maintained by the Trust, the
Trust's loan agreements do not contain any debt covenants other than the debt
is payable upon demand.Per Unit and Ratio Disclosures
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Cumulative
Amounts From
Six Months Six Months Inception
Ended June Ended June of Trust
2007 2006 (July 1, 2001)
-------------------------------------------------------------------------
Standardized Distributable Cash
- per above $16,854,000 $ 9,627,000 $92,473,000
-------------------------------------------------------------------------
Per weighted average unit $1.00 $0.58 $6.17
-------------------------------------------------------------------------
Per fully diluted unit $1.00 $0.57 $6.11
-------------------------------------------------------------------------
Cash distributions(1) $22,309,000 $23,042,000 $159,651,000
-------------------------------------------------------------------------
Payout ratio 1.32 2.39 1.73
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Adjusted Distribution Base $24,824,000 $26,161,000 $176,907,000
-------------------------------------------------------------------------
Per weighted average unit $1.47 $1.57 $11.81
-------------------------------------------------------------------------
Per fully diluted unit $1.47 $1.56 $11.69
-------------------------------------------------------------------------
Cash distributions(1) $22,309,000 $23,042,000 $159,651,000
-------------------------------------------------------------------------
Payout ratio 0.90 0.88 0.90
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes distribution declared in July 2007 and 2006 in respect of
June 2007 and 2006 operations respectively.On a go forward basis the Trust plans to reduce the payout ratio in
respect of Standardized Distributable Cash to a level between 110 to
120 percent to facilitate a debt to cash flow level of approximately one year
and to incur no current income tax (excluding Saskatchewan Resource
Surcharge). This will be attained through better controlling costs of capital
replacement, by examining lower cost methods of reserve replacement as well as
increased cash flow from wells currently drilled but not tied in.
Tax Attributes of Distributions and the Trust's Assets
See discussion under Income Taxes.
Cash Netback
------------
The following table illustrates the Trust's cash netback for the six
month periods ended (The 2007 netback includes one time charges to royalties
and field operating costs as described above in this report):-----------------------------------------------------------
June 30 June 30
$ per Barrel of Oil Equivalent (BOE) 2007 2006
-----------------------------------------------------------
Production volumes (BOE) 757,485 727,620
Gross production revenue $60.81 $59.58
Royalties (8.51) (7.49)
Field operating (15.80) (14.50)
-----------------------------------------------------------
Field netback 36.50 37.59
General and administrative (1.44) (1.71)
Interest and taxes (2.11) (1.16)
-----------------------------------------------------------
Cash netback $32.95 $34.72
-----------------------------------------------------------
-----------------------------------------------------------
The following table illustrates the Trust's cash netback for the three
month periods ended (The June 30 netback includes one time charges to
royalties and field operating costs as described above in this report):
June 30 March 31
$ per Barrel of Oil Equivalent (BOE) 2007 2007
-----------------------------------------------------------
Production volumes (BOE) 370,031 387,454
Gross production revenue $63.41 $58.33
Royalties (10.45) (6.65)
Field operating (17.21) (14.40)
-----------------------------------------------------------
Field netback 35.75 37.28
General and administrative (1.42) (1.46)
Interest and taxes (2.24) (1.99)
-----------------------------------------------------------
Cash netback $32.09 $33.83
-----------------------------------------------------------
-----------------------------------------------------------Liquidity and Capital Resources
-------------------------------
During the first half of 2007, the Trust incurred capital costs of
$9,324,000. The Trust drilled 7 gross (6.4 net) Cardium oil wells and 2 gross
(0.7 net) shallow gas wells in the first half of 2007 on its operated lands.
The Trust currently has plans to drill a total of 20 gross (15 net) wells
in 2007. Total capital cost of approximately $20,000,000 is budgeted for 2007.
The capital expenditures will be funded from funds flow, the Trusts lines of
credit and funds from the exercising of employee unit options.
The Trust through its operating subsidiaries has a bank revolving credit
facility of $59,900,000 at June 30, 2007 (December 31, 2006 - $49,900,000).
Subsequent to the end of Q2 the Trust increased its credit facility to
$69,900,000. The credit facilities carry an interest rate of Canadian
chartered bank prime.
The TSX does not accept responsibility for the adequacy or accuracy of
this release.CONSOLIDATED BALANCE SHEETS
As at June 30, 2007 (unaudited) and
December 31, 2006 2007 2006
-------------------------------------------------------------------------
Assets
Current
Accounts receivable $8,894,000 $10,486,000
Crude oil inventory 778,000 843,000
Parts inventory 90,000 114,000
Prepaid expenses 1,540,000 1,086,000
Derivative asset (Note 1) 710,000 -
Investments in related party (Note 1 and 2) 3,035,000 461,000
-------------------------------------------------------------------------
15,047,000 12,990,000
-------------------------------------------------------------------------
Property and Equipment (Note 3)
Petroleum and natural gas properties
and related equipment 185,034,000 176,602,000
Accumulated depletion and depreciation (60,649,000) (54,650,000)
-------------------------------------------------------------------------
Net Property and Equipment 124,385,000 121,952,000
-------------------------------------------------------------------------
$139,432,000 $134,942,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities
Current
Distributions payable $- $4,050,000
Accounts payable and accrued liabilities 10,041,000 13,748,000
Debt (Note 4) 54,601,000 45,379,000
-------------------------------------------------------------------------
64,642,000 63,177,000
Future Income Tax Liability (Note 5) 7,989,000 3,587,000
Asset Retirement Obligations 14,881,000 14,819,000
-------------------------------------------------------------------------
87,512,000 81,583,000
-------------------------------------------------------------------------
Commitments (Notes 9 and 10)
Unitholders' Equity (Note 6)
Unit capital 90,267,000 89,488,000
Contributed surplus 1,445,000 1,116,000
-------------------------------------------------------------------------
91,712,000 90,604,000
-------------------------------------------------------------------------
Deficit (42,489,000) (37,245,000)
Accumulated other comprehensive income
(Note 7) 2,697,000 -
-------------------------------------------------------------------------
(39,792,000) (37,245,000)
-------------------------------------------------------------------------
51,920,000 53,359,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
$139,432,000 $134,942,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY
For the periods
ended June 30
(unaudited) Three Months Six Months
2007 2006 2007 2006
-------------------------------------------------------------------------
Unitholders' equity,
beginning of
period $57,646,000 $61,365,000 $53,359,000 $57,322,000
Comprehensive income
for the period 5,017,000 10,617,000 13,661,000 20,338,000
Adjustment of opening
accumulated
comprehensive
income (Note 1) - - 2,380,000 -
Net capital
contributions 234,000 549,000 705,000 2,366,000
Unit based
compensation
adjustment 185,000 207,000 403,000 365,000
Distributions
declared (11,162,000) (11,536,000) (18,588,000) (19,189,000)
-------------------------------------------------------------------------
Unitholders' Equity,
End of Period $51,920,000 $61,202,000 $51,920,000 $61,202,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF OPERATIONS AND
ACCUMULATED EARNINGS
For the periods
ended June 30
(unaudited) Three Months Six Months
2007 2006 2007 2006
-------------------------------------------------------------------------
Revenue
Oil and gas
sales $23,237,000 $23,395,000 $45,249,000 $44,441,000
Hedging gain
(loss) 225,000 (176,000) 815,000 (1,091,000)
Royalties (3,868,000) (2,872,000) (6,446,000) (5,451,000)
Gain on sale
of property - - - 532,000
Alberta royalty
tax credits - 159,000 - 335,000
Interest and
other 12,000 28,000 33,000 35,000
-------------------------------------------------------------------------
19,606,000 20,534,000 39,651,000 38,801,000
-------------------------------------------------------------------------
Expenses
Production
costs 6,556,000 5,400,000 12,137,000 10,552,000
General and
administrative 527,000 612,000 1,091,000 1,244,000
Interest on debt 744,000 423,000 1,441,000 654,000
Unit based
compensation 185,000 207,000 403,000 365,000
Dry hole costs 9,000 - 476,000 -
Depletion,
depreciation
and accretion 3,284,000 2,910,000 6,786,000 5,507,000
-------------------------------------------------------------------------
11,305,000 9,552,000 22,334,000 18,322,000
-------------------------------------------------------------------------
Earnings before
Income Taxes 8,301,000 10,982,000 17,317,000 20,479,000
-------------------------------------------------------------------------
Income Taxes
(Recovery)
Current 84,000 91,000 158,000 190,000
Future 3,777,000 274,000 3,815,000 (49,000)
-------------------------------------------------------------------------
3,861,000 365,000 3,973,000 141,000
-------------------------------------------------------------------------
Net Earnings for
the Period 4,440,000 10,617,000 13,344,000 20,338,000
Deficit at
beginning of
period (35,767,000) (25,146,000) (37,245,000) (27,214,000)
Distributions
declared (11,162,000) (11,536,000) (18,588,000) (19,189,000)
-------------------------------------------------------------------------
Deficit at End
of Period ($42,489,000) ($26,065,000) (42,489,000) (26,065,000)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Earnings per
Trust Unit -
Basic (Note 5) $0.26 $0.64 $0.79 $1.22
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Earnings per
Trust Unit -
Diluted (Note 5) $0.26 $0.63 $0.79 $1.21
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
For the periods ended June 30 (unaudited) Three Months Six Months
2007 2007
-------------------------------------------------------------------------
Net Earnings for the Period $4,440,000 $13,344,000
Other Comprehensive Income, net of tax
Unrealized gains and losses on investments
(net of income taxes; Three Months ended -
($61,000), Six Months ended - $109,000) (354,000) 628,000
-------------------------------------------------------------------------
Gains and losses on derivatives designated
as cash flow hedges (net of income taxes;
Three Months ended - $491,000, Six Months
ended - $110,000) 1,193,000 266,000
Gains and losses on derivatives designated
as cash flow hedges in prior periods
transferred to net earnings in the current
period (net of income taxes; Three Months
ended - $109,000, Six Months ended
- $238,000) (262,000) (577,000)
-------------------------------------------------------------------------
Changes in gains and losses on derivatives
designated as cash flow hedges (net of
income taxes; Three Months ended - $382,000,
Six Months ended - ($128,000)) 931,000 (311,000)
-------------------------------------------------------------------------
Other Comprehensive Income 577,000 317,000
-------------------------------------------------------------------------
Comprehensive Income $5,017,000 $13,661,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the periods
ended June 30
(unaudited) Three Months Six Months
2007 2006 2007 2006
-------------------------------------------------------------------------
Operating Activities
Net earnings for
the period $4,440,000 $10,617,000 $13,344,000 $20,338,000
Items not
affecting cash
Gain on sale
of property - - - (532,000)
Unit based
compensation 185,000 207,000 403,000 365,000
Dry hole costs 9,000 - 476,000 -
Depletion,
depreciation
and accretion 3,284,000 2,910,000 6,786,000 5,507,000
Future income
taxes 3,777,000 274,000 3,815,000 (49,000)
-------------------------------------------------------------------------
11,695,000 14,008,000 24,824,000 25,629,000
-------------------------------------------------------------------------
Change in non-cash
working capital
Accounts
receivable 60,000 15,000 599,000 290,000
Crude oil
inventory 79,000 (26,000) 65,000 (153,000)
Parts
inventory 16,000 (79,000) 24,000 (4,000)
Prepaid
expenses (502,000) (406,000) (454,000) (531,000)
Accounts payable
and accrued
liabilities 2,326,000 522,000 1,429,000 815,000
Asset retirement
obligations
settled (261,000) (42,000) (309,000) (125,000)
-------------------------------------------------------------------------
1,718,000 (16,000) 1,354,000 292,000
-------------------------------------------------------------------------
Cash Provided by
Operating
Activities 13,413,000 13,992,000 26,178,000 25,921,000
-------------------------------------------------------------------------
Financing Activities
Increase in debt 1,766,000 4,302,000 9,222,000 11,342,000
Unit option
proceeds 234,000 549,000 705,000 2,366,000
Unit distri-
butions (11,162,000) (11,536,000) (22,638,000) (22,827,000)
-------------------------------------------------------------------------
Cash Used in
Financing
Activities (9,162,000) (6,685,000) (12,711,000) (9,119,000)
-------------------------------------------------------------------------
Investing Activities
Property and
equipment
expenditures (1,699,000) (6,246,000) (9,324,000) (16,294,000)
Proceeds on sale
of properties - - - 750,000
Change in
non-cash working
capital
Accounts
receivable 729,000 270,000 993,000 (721,000)
Accounts payable
and accrued
liabilities (3,281,000) (1,331,000) (5,136,000) (537,000)
-------------------------------------------------------------------------
Cash Used in
Investing
Activities (4,251,000) (7,307,000) (13,467,000) (16,802,000)
-------------------------------------------------------------------------
Net Cash Inflow - - - -
Cash, beginning
of period - - - -
-------------------------------------------------------------------------
Cash, End of
Period $- $- $- $-
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash Interest
Paid $744,000 $423,000 $1,441,000 $654,000
Cash Taxes Paid
(Recovered) $93,000 ($506,000) $183,000 ($394,000)
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------------------
Periods Ended June 30, 2007 and 2006 unaudited
1. SIGNIFICANT ACCOUNTING POLICIES
The accounting policies and methods of application followed in the
preparation of the interim financial statements other than described
below are the same as those followed in the preparation of the Trust's
2006 annual financial statements. These interim financial statements do
not include all disclosure requirements for annual financial statements.
The interim financial statements as presented should be read in
conjunction with the 2006 annual financial statements.
Financial instruments - recognition and measurement
On January 1, 2007, the Trust adopted Section 3855 of the Canadian
Institute of Chartered Accounts' ("CICA") Handbook, "Financial
Instruments - Recognition and Measurement" and Section 3861 Financial
Instruments - Presentation and Disclosure. It sets out the standards for
recognizing and measuring financial instruments in the balance sheet and
the standards for reporting gains and losses in the financial statements.
Financial assets available for sale, assets and liabilities held for
trading and derivative financial instruments, part of a hedging
relationship or not, have to be measured at fair value.
The Trust has made the following classifications:
- Investment in related party is classified as available-for sale and
will thus be marked-to-market through comprehensive income at each
period end.
- Accounts receivable are classified as loans and receivables and are
recorded at amortized cost using the effective interest method. Gains
and losses are recognized in net earnings when the asset is no longer
recognized.
- Accounts payable and accrued liabilities and bank debt are classified
as other financial liabilities and are recorded at amortized cost
using the effective interest method. Gains and losses are recognized
in net earnings when the liability is no longer recognized.
The adoption of this Section is done retroactively without restatement of
the consolidated financial statements of prior periods. As of January 1,
2007, the impact on the consolidated balance sheet of measuring the
investment in related party at marked-to-market was an increase of
$1,836,000 to investment in a related party, an increase in future tax
liability of $270,000 and an increase in accumulated other comprehensive
income of $1,566,000.
The impact on the consolidated financial balance sheet of measuring
hedging derivatives at fair value as at January 1, 2007 was an increase
in other assets of $1,148,000, an increase in future tax liability of
$334,000 and an increase in accumulated other comprehensive income of
$814,000.
The Trust selected January 1, 2003 as its transition date for embedded
derivatives. An embedded derivative is a component of a financial
instrument or another contract of which the characteristics are similar
to a derivative. This had no impact on the consolidated financial
statements.
Comprehensive income
On January 1, 2007, the Trust adopted Section 1530 of the CICA Handbook,
"Comprehensive Income". It describes reporting and disclosure
recommendations with respect to comprehensive income and its components.
Comprehensive income is the change in unitholders' equity, which results
from transactions and events from sources other than the Trust's
unitholders. These transactions and events include unrealized gains and
losses from changes in fair value of certain financial instruments.
The adoption of this Section implied that the Trust now presents a
consolidated statement of comprehensive income as a part of the
consolidated financial statements.
Equity
On January 1, 2007, the Trust adopted Section 3251 of the CICA Handbook
"Equity" replacing Section 3250 "Surplus". It describes standards for the
presentation of equity and changes in equity for reporting periods as a
result of the application of Section 1530 "Comprehensive Income".
Hedges
On January 1, 2007, the Trust adopted Section 3865 of the CICA Handbook
"Hedges". The recommendations of this Section expand the guidelines
required by Accounting Guideline 13(AcG-13), Hedging Relationships. This
section describes when and how hedge accounting can be applied as well as
the disclosure requirements. Hedge accounting enables the recording of
gains, losses, revenues and expenses from the derivative financial
instrument in the same period as those related to the hedge item.
Accounting changes
The Trust also adopted Section 1506, "Accounting Changes," whereby the
only impact is to provide disclosure of when an entity has not applied a
new source of GAAP that has been issued but is not yet effective. This is
the case with Section 3862, "Financial Instruments Disclosures" and
Section 3863, "Financial Instruments Presentations" which are required to
be adopted for fiscal years beginning on or after October 1, 2007. The
Trust will adopt these standards on January 1, 2008 and it is expected
the only effect on the Trust will be incremental disclosures regarding
the significance of financial instruments for the entity's financial
position and performance; and the nature, extent and management of risks
arising from financial instruments to which the entity is exposed.
2. INVESTMENT IN RELATED PARTY
The investment consists of 689,682 (December 31, 2006 - 689,682) common
shares in Comaplex Minerals Corp. (Comaplex), a company with common
directors and management. The investment is recorded at fair market
value. The fair market value, as determined by using the trading price of
the stock at June 30, 2007, was $3,035,000 (December 31, 2006 -
$2,297,000). The common shares trade on the Toronto Stock Exchange under
the symbol CMF. The investment represents less than a two percent
ownership in the outstanding shares of Comaplex.
3. PROPERTY AND EQUIPMENT
June 30, 2007 December 31, 2006
Accumulated Accumulated
Depletion and Depletion and
Cost Depreciation Cost Depreciation
-------------------------------------------------------------------------
Undeveloped land $ 334,000 $ - $ 334,000 $ -
Petroleum and
natural gas
properties and
related equipment 183,736,000 60,011,000 175,353,000 54,008,000
Furniture,
equipment and
other 964,000 638,000 915,000 642,000
-------------------------------------------------------------------------
$185,034,000 $60,649,000 $176,602,000 $54,650,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
4. DEBT
The Trust through its operating subsidiaries has a bank revolving credit
facility of $59,900,000 at June 30, 2007 (December 31, 2006 -
$59,900,000). Subsequent to the end of the quarter, the Trust increased
its bank facility to $69,900,000. The terms of the credit facility
provide that the loan is due on demand and is subject to annual review.
The credit facility has no fixed payment requirements. The amount
available for borrowing under the credit facility is reduced by the
amount of outstanding letters of credit. Letters of credit totalling
$340,000 were issued at June 30, 2007 (December 31, 2006 - $340,000).
Security for the credit facility consists of various fixed and floating
demand debentures totalling $79,000,000 over all of the Trust's assets,
and a general security agreement with first ranking over all personal and
real property.
The credit facility carries an interest rate of Canadian chartered bank
prime. The Trust has classified this debt as a current liability as
required by generally accepted accounting principles. It has been
management's experience that these types of loans which are required to
be classified as a current liability are seldom called by principal
bankers as long as all the terms and conditions of the loan are complied
with. Cash interest paid during the six month periods ended June 30, 2007
and 2006 for these loans were $1,441,000 and $654,000 respectively.
5. INCOME TAXES
The Trust has recorded a future income tax liability related to assets
and liabilities and related tax amounts. The following figures reflect
the consequences of the Canadian Federal Governments October 31, 2006
announcement on the future taxation of Income Trusts:
June 30, December 31,
2007 2006
-----------------------------------------------------------
Future income tax liability to
assets and liabilities: $10,701,000 $ 6,233,000
Future tax asset related to
finance costs: (112,000) -
Future tax asset related to
corporate tax losses carried
forward in the subsidiary
companies (2,600,000) (2,646,000)
-----------------------------------------------------------
$ 7,989,000 $ 3,587,000
-----------------------------------------------------------
-----------------------------------------------------------
Income tax expense varies from the amounts that would be computed by
applying Canadian federal and provincial income tax rates as follows:
2007(1) 2006(2)
-----------------------------------------------------------
Earnings before income taxes $13,344,000 $20,338,000
Combined federal and provincial
income tax rates 0% 34.97%
-----------------------------------------------------------
Income tax provision calculated
using statutory tax rates - 7,112,000
Increase (decrease) in taxes
resulting from:
Saskatchewan resource surcharge 158,000 190,000
Unit-based compensation - 128,000
Non-deductible crown royalties - 558,000
Resource allowance - (930,000)
Change in effective tax rate 3,801,000 -
Trust income allocated to
Unitholders - (7,076,000)
Others (14,000) 159,000
-----------------------------------------------------------
Income tax expense $ 3,973,000 $ 141,000
-----------------------------------------------------------
-----------------------------------------------------------
(1) 2007 items calculated using trust effective tax rate
(2) 2006 items calculated using corporation effective tax rates
The Trust's subsidiaries have the following tax pools, which may be used
to reduce taxable income in future years, limited to the applicable rates
of utilization:
Rate of
Utilization
% Amount
-----------------------------------------------------------
Undepreciated capital costs 20-100 $16,105,000
Canadian oil and gas property
expenditures 10 1,182,000
Canadian development expenditures 30 35,187,000
Canadian exploration expenditures 100 93,000
Income tax losses carried forward(1) 100 9,035,000
-----------------------------------------------------------
$61,602,000
-----------------------------------------------------------
-----------------------------------------------------------
(1) Income tax losses carried forward expire in 2014 ($635,000), 2015
($3,574,000) and 2016 ($4,826,000).
The Trust has the following tax pools, which may be used in reducing
future taxable income allocated to its Unitholders:
Rate of
Utilization
% Amount
-----------------------------------------------------------
Canadian oil and gas property
expenditures 10 $14,950,000
Finance costs 20 483,000
Eligible capital expenditures 7 162,000
-----------------------------------------------------------
$15,595,000
-----------------------------------------------------------
-----------------------------------------------------------
On October 31, 2006, the Canadian Federal Government announced a proposed
Trust taxation pertaining to taxation of distributions paid by publicly
traded income trusts and this was enacted by legislation in June, 2007.
Previously, distributions paid to unitholders, other than returns of
capital, were claimed as a deduction by the Trust in arriving at taxable
income whereby tax is eliminated at the Trust level and is paid by the
unitholders. The June, 2007 legislation results in a two-tiered tax
structure whereby distributions commencing in 2011 would first be subject
to a 31.5 percent tax at the Trust level and then investors would be
subject to tax on the distribution as if it were a taxable dividend paid
by a taxable Canadian corporation.
Prior to June 2007, the Trust estimated the future income tax on certain
temporary differences between amounts recorded on its balance sheet for
book and tax purposes at a nil effective tax rate. The entire balance of
the future income tax liability reported related to assets and
liabilities and related tax amounts held through the Trust's 100 percent
held subsidiaries. Under the legislation, the Trust now estimates the
effective tax rate on post 2010 reversal of these temporary differences
to be 31.5%. Temporary differences at the Trust level reversing before
2011 will still give rise to nil future income taxes.
Based on its assets and liabilities as at June 30, 2007, the Trust has
estimated the amount of its temporary differences which were previously
not subject to tax and estimated the periods in which these differences
will reverse. The Trust estimates that $12,070,000 net taxable temporary
differences will reverse after January 1, 2011, resulting in an
additional $3,801,000 future income tax liability. The taxable temporary
differences relate principally to the excess of net book value of oil and
gas properties over the remaining tax pools attributable thereto.
As the legislation gives rise to a change in the Trust's estimated future
income tax liability in the period, the recognition of the additional
liability is accounted for prospectively in the period and an additional
$3,801,000 of future income tax expense has been recorded for the period.
While the Trust believes it will be subject to additional tax under the
new legislation, the estimated effective tax rate on temporary difference
reversals after 2011 may change in future periods. As the legislation is
new, future technical interpretations of the legislation could occur and
could materially affect management's estimate of the future income tax
liability.
The amount and timing of reversals of temporary differences will also
depend on the Trust's future operating results, acquisitions and
dispositions of assets and liabilities, and distribution policy. A
significant change in any of the preceding assumptions could materially
affect the Trust's estimate of the future income tax liability.
6. UNIT CAPITAL
Authorized
The Trust is authorized to issue an unlimited number of trust units
without nominal or par value.
Issued Number Amount
-----------------------------------------------------------
Trust Units
Balance, January 1, 2007 16,874,658 $89,488,000
Issued pursuant to Trust's unit
option plan 41,000 705,000
Transfer of contributed surplus
to unit capital - 74,000
-----------------------------------------------------------
Balance, June 30, 2007 16,915,658 $90,267,000
-----------------------------------------------------------
-----------------------------------------------------------
The number of trust units used to calculate diluted net earnings per unit
for the period ended June 30, 2007 of 16,938,094 (2006 - 16,809,422)
included the basic weighted average number of units outstanding of
16,905,494 (2006 - 16,703,957) plus 32,600 (2006 - 105,465) units related
to the dilutive effect of unit options.
The deficit balance is composed of the following items:
June 30, June 30,
2007 2006
-----------------------------------------------------------
Accumulated earnings $135,750,000 $105,494,000
Accumulated cash distributions (178,239,000) (131,559,000)
-----------------------------------------------------------
Deficit $(42,489,000) $(26,065,000)
-----------------------------------------------------------
-----------------------------------------------------------
The Trust provides an option plan for its directors, officers, employees
and consultants. Under the plan, the Trust may grant options for up to
1,692,000 (December 31, 2006 - 1,687,000) trust units. The exercise price
of each option granted equals the market price of the trust unit on the
date of grant and the option's maximum term is five years.
A summary of the status of the Trust's unit option plan as of June 30,
2007 and December 31, 2006, and changes during the six month and twelve
month periods ending on those dates is presented below:
June 30, 2007 December 31, 2006
-------------------------------------------------------------------------
Options Weighted-Average Options Weighted-Average
Exercise Price Exercise Price
-------------------------------------------------------------------------
Outstanding at
beginning of
period 721,500 $26.55 646,000 $18.67
Options granted 546,000 28.12 447,000 29.18
Options exercised (41,000) 17.19 (339,500) 15.20
Options cancelled (40,000) 28.21 (32,000) 24.70
-------------------------------------------------------------------------
Outstanding at end
of period 1,186,500 $27.54 721,500 $26.55
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Options exercisable
at end of period 209,500 $23.73 212,500 $22.62
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The following table summarizes information about unit options outstanding
at June 30, 2007:
Options Outstanding Options Exercisable
---------------------------------- ----------------------
Weighted-
Average Weighted- Weighted-
Range of Number Remaining Average Number Average
Exercise Outstanding Contractual Exercise Exercisable Exercise
Prices At 6/30/07 Life Price At 6/30/07 Price
-------------------------------------------------------------------------
$22.45-$23.35 237,500 1.7 years $23.32 194,500 $23.35
$24.20-$25.00 24,000 2.6 years 24.34 - -
$26.60 5,000 2.6 years 26.60 - -
$28.30-$28.75 880,000 2.4 years 28.49 15,000 28.72
$32.00-$33.75 40,000 2.5 years 33.55 - -
-------------------------------------------------------------------------
$22.45-$33.75 1,186,500 2.3 years $27.54 209,500 $23.73
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The Trust records a compensation expense over the vesting period based on
the fair value of options granted to employees, directors and
consultants.
7. ACCUMULATED OTHER COMPREHENSIVE INCOME
Six months ended June 30, 2007
Opening Other Ending
Comprehensive
Income
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Unrealized gains and losses on
available-for sale financial
assets $1,566,000 $ 628,000 $2,194,000
Unrealized gains and losses on
derivatives designated as
cash flow hedges 814,000 (311,000) 503,000
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$2,380,000 $ (317,000) $2,697,000
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8. RELATED PARTY TRANSACTIONS
The Trust received a management fee from Comaplex of $150,000 (2006 -
$150,000) for management services, accounting services and office
administration. This cost has been included as a recovery of general and
administrative expenses. The above charge represents the fair value of
the services rendered. At June 30, 2007 the Trust had an accounts
receivable from Comaplex of $60,000 (December 31, 2006 - $38,000).
The Trust received a management fee from Pine Cliff Energy Ltd. (Pine
Cliff) of $108,000 (2006 - $108,000) for management services, accounting
services and office administration. This fee has been included as a
recovery in general and administrative expenses. As at June 30, 2007 the
Trust had no amounts for accounts receivable from or accounts payable to
Pine Cliff. The above charge represents the fair value of the services
rendered.
9. COMMITMENTS - FUTURE SALES AGREEMENTS
The Trust entered into the following commodity hedging contracts for a
portion of its 2007 and 2008 production:
Period of Agreement Commodity Volume per day Index Price (Cdn.)
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July 1, 2007 to
December 31, 2007 Crude Oil 500 barrels WTI Floor of $75.00
and ceiling of
$93.00 per
barrel
July 1, 2007 to
December 31, 2007 Crude Oil 500 barrels WTI Floor of $70.00
and ceiling of
$80.06 per
barrel
January 1, 2008 to
June 30, 2008 Crude Oil 1,000 barrels WTI Floor of $73.00
and ceiling of
$83.00 per
barrel
April 1, 2007 to
July 31, 2007 Natural Gas 2,000 GJ's AECO $6.52 per GJ
April 1, 2007 to
October 31, 2007 Natural Gas 1,000 GJ's AECO Floor of $6.50
and ceiling of
$9.20 per GJ
November 1, 2007
to March 31, 2008 Natural Gas 2,000 GJ's AECO Floor of $6.50
and ceiling of
$10.37 per GJ
10. SUBSEQUENT EVENT - COMMITMENTS
Subsequent to June 30, 2007, the Trust entered into the following
commodity hedging contract for a portion of its 2008 production:
Period of Agreement Commodity Volume per day Index Price (Cdn.)
-------------------------------------------------------------------------
July 1, 2008 to
December 31, 2008 Crude Oil 500 barrels WTI Floor of $73.00
and ceiling of
$80.68 per
barrel
11. SUBSEQUENT EVENT - DISTRIBUTIONS
Subsequent to June 30, 2007, the Trust declared distributions of $0.22
per unit payable on July 31 and August 31, 2007 to Unitholders of record
on July 16 and August 15, 2007 respectively. The distribution represents
funds flow in the Trust for the months of June and July 2007.%SEDAR: 00017467E
For further information:
For further information: Additional information relating to the Trust may be found on WWW.SEDAR.COM as well as on the Trust's website at www.bonterraenergy.com or by contacting George F. Fink, President, and CEO or Garth E. Schultz, Vice President - Finance, and CFO at (403) 262-5307 or by fax at (403) 265-7488