Bonterra Energy Income Trust Announces First Quarter Results
CALGARY, May 11 /CNW/ - Bonterra Energy Income Trust
(www.bonterraenergy.com) (TSX:BNE.UN) is pleased to announce its financial and
operational results for the three months ended March 31, 2007.HIGHLIGHTS
----------
For the three months ended March 31, December 31, March 31,
2007 2006 2006
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FINANCIAL
Revenue - oil and gas $ 22,602,000 $ 21,719,000 $ 20,131,000
Funds Flow From Operations(1) $ 13,129,000 $ 12,235,000 $ 12,153,000
Per Unit - Basic $ 0.78 $ 0.72 $ 0.73
Per Unit - Diluted $ 0.78 $ 0.72 $ 0.72
Net Earnings $ 8,904,000 $ 6,471,000 $ 9,721,000
Per Unit - Basic $ 0.53 $ 0.39 $ 0.58
Per Unit - Diluted $ 0.53 $ 0.38 $ 0.58
Cash Distributions per Unit $ 0.66 $ 0.72 $ 0.69
Capital Expenditures $ 7,625,000 $ 9,457,000 $ 10,048,000
Total Assets $140,926,000 $134,942,000 $118,439,000
Working Capital Deficiency(2) $ 49,288,000 $ 50,187,000 $ 25,532,000
Unitholders' Equity $ 57,646,000 $ 53,359,000 $ 61,365,000
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OPERATIONS
Oil and NGL's - Barrels Per Day 3,227 3,138 2,996
- Average Price
($ per barrel) $ 62.53 $ 60.79 $ 57.02
Natural Gas - MCF Per Day 6,470 5,885 6,071
- Average Price
($ per MCF) $ 7.52 $ 7.57 $ 8.52
Total Barrels Per Day(3) 4,305 4,119 4,008
(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 has been successful on a year over year quarterly basis in
increasing production volumes, revenue, and funds flow on a gross and per unit
basis. Earnings declined slightly ($9.7 million Q1 2006; $8.9 million Q1 2007)
on a gross and per unit basis due mainly to higher costs, loss of Alberta
Royalty Tax Credit, an increase in interest expense, dry hole costs and an
increase in depletion, depreciation, and accretion, offset partially by an
increase in revenue.
At March 31, 2007, Bonterra had 6 gross (3.8 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.
Subject to service costs and government regulations, a few of the CBM wells
will also be completed.
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, recompletion 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. Despite reducing the capital
expenditure budget for 2007 to $20 million from $38 million in 2006, Bonterra
may still grow its production volumes by conducting these types of programs.
With regard to dealing with the possibility of the proposed federal
taxation changes being legislated, Bonterra is still taking a wait and see
approach. It will deal with this issue when details about the changes are
legislated and there is certainty rather than speculation.
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.
Financial and Operational Discussion
------------------------------------
Production
----------
Average daily production volume for the three months ended March 31, 2007
was 4,305 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. Production consists of 3,227 barrels per
day of crude oil and natural gas liquids and 6,470 MCF per day of natural gas.
Bonterra's first quarter 2006 average production was 4,008 BOE's per day
consisting of 2,996 barrels per day of crude oil and natural gas liquids and
6,071 MCF per day of natural gas.
The Trust drilled 4 gross (3.4 net) Cardium oil wells and 2 gross
(.7 net) shallow gas wells in the first quarter of 2007 on its operated lands.
As at March 31, 2007 Bonterra had 6 gross (3.8 net) Cardium oil wells and 12
gross (9 net) natural gas wells and 7 gross (5.5 net) coal-bed wells drilled
but not on production. During the first quarter of 2007, the Trust tied-in
10 gross (9.7 net) Cardium wells and 2 gross (1 net) natural gas wells.
Management anticipates that the majority of the currently drilled but not
producing wells (excluding the coal-bed wells) will be completed and tied-in
by the end of the third quarter 2007. It continues to be difficult obtaining
services and materials to complete and tie-in wells on a timely basis. In
addition, the current spring breakup is preventing completion of the existing
inventory of uncompleted wells.
Revenue
-------
Revenue from petroleum and natural gas sales (including hedge gains and
losses) for the quarter was $22,602,000 (2006 - $20,131,000). The increase in
revenue over the 2006 first quarter was primarily due to higher production
from the wells drilled during the 2006 drill program but not completed until
late 2006 or early 2007. The average price received for crude oil and natural
gas liquids during the first quarter of 2007 was $62.53 per barrel and
$7.52 per MCF for natural gas compared to $57.02 per barrel and $8.52 per MCF
in the corresponding 2006 period. On a quarter over quarter basis, revenue
increased by $883,000 due to increased production volumes and a moderate
increase in crude oil prices.
Gross revenue increased by $590,000 (2006 decreased $915,000) 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 high cost production 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 Note 8 to the attached interim financial
statements for details. As at March 31, 2007, the fair value of the
outstanding commodity hedging contracts was a net liability of $604,000
(December 31, 2006 - net asset of $1,189,000).
Royalties
---------
Royalties paid by the Trust consist primarily of Crown royalties paid to
the Provinces of Alberta and Saskatchewan. During the first quarter of 2007
the Trust paid $2,156,000 (2006 - $2,085,000) in Crown royalties and $422,000
(2006 - $494,000) 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 percent (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
effective January 1, 2007.
Production Costs
----------------
Production costs for the three months ended March 31, 2007 were
$5,581,000 compared to $5,152,000 for the three months ended March 31, 2006.
On a BOE basis production costs averaged $14.40 in 2007 verses $14.28 in the
corresponding 2006 period. Operating costs on the Trust's newly drilled wells
are in the range of $2 to $7 per BOE due to higher original production
volumes. The lower costs per BOE on the new wells are offsetting the
escalating costs being charged by service companies.
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 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 $564,000 in the first quarter of
2007 compared to $632,000 in the three months ended March 31, 2006 and
$481,000 in the three months ended December 31, 2006.
Costs on a BOE bases decreased to $1.46 per BOE in the first quarter of
2007 from $1.75 per BOE in the first quarter of 2006. The decrease in general
and administrative expenses year over year was due to increased administration
fee recoveries on operated production. The quarter over quarter increase was
due primarily to increased employee compensation expense and increased annual
report, TSX fees and security commission filing costs associated with filing
of the annual report and other continuous disclosure documentation during the
first quarter.
Interest Expense
----------------
Interest expense increased to $697,000 for the three months ended
March 31, 2007 compared to $231,000 for the three months ended March 31, 2006
and $542,000 for the fourth quarter of 2006. Increased average debt levels and
increased interest rates were the primary factors in the increase in interest
expense. The Trust's net debt as a percentage of annualized first quarter
funds flow was approximately eleven and a half months.
The Trust's bank loan of $52,835,000 increased by approximately
$7.5 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 Trusts winter 2007 drill
program of $7,625,000 which represents 38 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. Only 24,000 employee
unit options were granted during the first quarter of 2007 resulting in no
significant impact to unit based compensation.
Depletion, Depreciation, Accretion and Dry Hole Costs
-----------------------------------------------------
The Trust follows the successful efforts method of accounting for
petroleum and natural gas exploration and development costs. Under this
method, the costs associated with dry holes are charged to operations. For
intangible capital costs that result in the addition of reserves, the Trust
depletes its oil and natural gas intangible assets using the
unit-of-production basis by field. The Trust believes that the successful
efforts method of accounting provides a more accurate cost of the producing
properties than the alternative measure of full cost accounting.
Provision for depletion, depreciation and accretion was $3,502,000 and
$2,597,000 for the three month periods ending March 31, 2007 and March 31,
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.
Dry hole costs of $467,000 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 quarter of 2007.
Income Taxes
------------
Taxable income earned within the Trust is required to be allocated to its
Unitholders and as such the Trust will not incur any current taxes. However,
the Trust operates its oil and gas interests through its 100 percent owned
subsidiaries Bonterra Energy Corp. ("Bonterra Corp.") and Novitas Energy Ltd.
("Novitas") and these corporations may periodically be taxable. The Trust
amalgamated Bonterra Corp. with Comstate Resources Ltd. effective January 1,
2007.
These corporations pay the majority of their income to the Trust through
interest and royalty payments which are deductible for income tax purposes.
The current tax provision relates to resource surcharge payable by the Trusts
subsidiaries to the Province of Saskatchewan. The surcharge is calculated as a
flat percent of revenues generated from the sale of petroleum products
produced in Saskatchewan. The provincial government of Saskatchewan has
announced its intention to reduce the current resource surcharge rate of
3.3 percent to 3 percent by July 1, 2008.
Future tax provision relates to the future taxes that exist within
Bonterra Corp. and Novitas. The liability on the balance sheet relates to
temporary differences existing between Bonterra Corp.'s and Novitas' book
value of their assets and their remaining tax pools.
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 $16,303,000
Canadian oil and gas property
expenditures 10 1,212,000
Canadian development expenditures 30 34,933,000
Canadian exploration expenditures 100 93,000
Income tax losses carried forward(1) 100 9,035,000
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$61,576,000
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(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 $15,317,000
Finance costs 20 554,000
Eligible capital expenditures 7 165,000
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$16,036,000
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-------------------------------------------------------------------------The Canadian taxable portion of distributions for the 2007 taxation year
is calculated on an annual basis and is reported generally by March 1 of the
following year.
As of March 31, 2007 proposed Trust taxation legislation has not been
substantially enacted and as such the effects of the legislation has not been
incorporated into the first quarter report.
Net Earnings
------------
Net earnings decreased to $8,904,000 in the first quarter of 2007 from
$9,721,000 in the corresponding 2006 period. Revenue increases due to
increased commodity prices and production were generally offset by increased
interest expense and depletion, depreciation, accretion and dry hole costs.
The Trust's quarter over quarter net earnings increased $2,433,000 primarily
due to decreased dry hole costs in Q1 2007 and an increase in production
volumes.
Comprehensive Income
--------------------
On January 1, 2007 the Trust adopted 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 quarter included an increase in the
unrealized gain on investment in a related party of $982,000, a loss of
$315,000 relating to the amortization of the amount recognized in accumulated
other comprehensive income on January 1, 2007 for commodity derivative
contracts and a loss of $927,000 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.
Funds Flow from Operations
--------------------------
Funds flow from operations for the three months ending March 31, 2007 was
$13,129,000 compared to $12,153,000 for the three months ended March 31, 2006
and $12,235,000 for the final three months of 2006. 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 and asset retirement expenditures.
The increase over the first quarter of 2006 was primarily due to higher
commodity prices and increased production resulting from the Trust's 2006
drill program. As with all oil and gas producers the Trust's funds flow is
highly dependent on commodity prices.
The following reconciliation compares funds flow for the first three
months of 2007 and 2006 to the Trust's cash flow from operations as calculated
according to Canadian generally accepted accounting principles:2007 2006
Cash flow from operating activities $12,765,000 $11,929,000
Items not affecting funds flow:
Gain on sale of property - 532,000
Changes in accounts receivable (539,000) (275,000)
Changes in crude oil inventory 14,000 127,000
Changes in parts inventory (8,000) (75,000)
Changes in prepaid expenses (48,000) 125,000
Changes in accounts payable and
accrued liabilities 897,000 (293,000)
Asset retirement obligations settled 48,000 83,000
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Funds flow for the period $13,129,000 $12,153,000
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Cash Netback
------------
The following table illustrates the Trust's cash netback for the three
month periods ended:
March 31 December 31 March 31
$ per Barrel of Oil Equivalent (BOE) 2007 2006 2006
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Production volumes (BOE) 387,454 378,916 360,720
Gross production revenue $58.33 $57.32 $55.80
Royalties (6.65) (6.37) (7.15)
Field operating (14.40) (15.83) (14.28)
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Field netback 37.28 35.12 34.37
General and administrative (1.46) (1.27) (1.75)
Interest and taxes (1.99) (1.64) (0.91)
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Cash netback $33.83 $32.21 $31.71
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-------------------------------------------------------------------------Related Party Transactions
--------------------------
The Trust received a management fee from Comaplex Minerals Corp., a
company with common directors and management, of $75,000 (2006 - $75,000) for
management services and office administration. In addition the Trust received
a management fee from Pine Cliff Energy Ltd., a company with common directors
and management, of $54,000 (2006 - $54,000) for management services and office
administration. These recoveries have been offset against the Trust's general
and administrative expense.
Liquidity and Capital Resources
-------------------------------
During the first quarter of 2007, the Trust incurred capital costs of
$7,625,000. The Trust drilled 4 gross (3.4 net) Cardium oil wells and 2 gross
(0.7 net) shallow gas wells in the first quarter of 2007 on its operated
lands.
The Trust currently has plans to drill a total of 20 gross (15 net)
Cardium infill oil 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 March 31, 2007 (December 31, 2006 - $49,900,000).
The credit facility carries 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 March 31, 2007 (unaudited)
and December 31, 2006 2007 2006
Assets
Current
Accounts receivable $9,683,000 $10,486,000
Crude oil inventory 873,000 843,000
Parts inventory 106,000 114,000
Prepaid expenses 1,038,000 1,086,000
Investments in related party
(Notes 1 and 2) 3,448,000 461,000
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15,148,000 12,990,000
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Property and Equipment (Note 3)
Petroleum and natural gas properties
and related equipment 183,360,000 176,602,000
Accumulated depletion and depreciation (57,582,000) (54,650,000)
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Net Property and Equipment 125,778,000 121,952,000
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$140,926,000 $134,942,000
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Liabilities
Current
Distribution payable $- $4,050,000
Accounts payable and accrued liabilities 10,996,000 13,748,000
Derivative liability (Note 1) 605,000 -
Debt (Note 4) 52,835,000 45,379,000
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64,436,000 63,177,000
Future Income Tax Liability 3,888,000 3,587,000
Asset Retirement Obligations 14,956,000 14,819,000
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83,280,000 81,583,000
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Commitments (Note 8)
Unitholders' Equity (Note 5)
Unit capital 90,009,000 89,488,000
Contributed surplus 1,284,000 1,116,000
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91,293,000 90,604,000
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Deficit (35,767,000) (37,245,000)
Accumulated other comprehensive income
(Note 6) 2,120,000 -
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(33,647,000) (37,245,000)
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57,646,000 53,359,000
-------------------------------------------------------------------------
$140,926,000 $134,942,000
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CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY
For the Three Months Ended March 31
(unaudited) 2007 2006
Unitholders' equity, beginning of period $53,359,000 $57,322,000
Comprehensive income for the period 8,644,000 9,721,000
Adjustment of opening accumulated
comprehensive income (Note 1) 2,380,000 -
Net capital contributions 471,000 1,817,000
Unit based compensation adjustment 218,000 158,000
Distributions declared (7,426,000) (7,653,000)
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Unitholders' Equity, End of Period $57,646,000 $61,365,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT
For the Three Months Ended
March 31 (unaudited) 2007 2006
Revenue
Oil and gas sales $22,012,000 $21,046,000
Hedging gain (loss) 590,000 (915,000)
Royalties (2,578,000) (2,579,000)
Gain on sale of property - 532,000
Alberta royalty tax credits - 176,000
Interest and other 21,000 7,000
-------------------------------------------------------------------------
20,045,000 18,267,000
-------------------------------------------------------------------------
Expenses
Production costs 5,581,000 5,152,000
General and administrative 564,000 632,000
Interest on debt 697,000 231,000
Unit based compensation 218,000 158,000
Dry hole costs 467,000 -
Depletion, depreciation and accretion 3,502,000 2,597,000
-------------------------------------------------------------------------
11,029,000 8,770,000
-------------------------------------------------------------------------
Earnings Before Income Taxes 9,016,000 9,497,000
-------------------------------------------------------------------------
Income Taxes (Recovery)
Current 74,000 99,000
Future 38,000 (323,000)
-------------------------------------------------------------------------
112,000 (224,000)
-------------------------------------------------------------------------
Net Earnings for the Period 8,904,000 9,721,000
Deficit at beginning of period (37,245,000) (27,214,000)
Distributions declared (7,426,000) (7,653,000)
-------------------------------------------------------------------------
Deficit at End of Period ($35,767,000) ($25,146,000)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Earnings Per Unit - Basic and Diluted $0.53 $0.58
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
For the Three Months Ended March 31 (unaudited) 2007
Net Earnings for the Period $8,904,000
Unrealized gains and losses on investments
(net of income taxes of $170,000) 982,000
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Gains and losses on derivatives designated as cash
flow hedges (net of income taxes of $381,000) (927,000)
Gains and losses on derivatives designated as cash
flow hedges in prior periods transferred to
net income in the current period
(net of income taxes of $129,000) (315,000)
-------------------------------------------------------------------------
Changes in gains and losses on derivatives
designated as cash flow hedges
(net of income taxes of $510,000) (1,242,000)
-------------------------------------------------------------------------
Other Comprehensive Income (260,000)
-------------------------------------------------------------------------
Comprehensive Income $8,644,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended
March 31 (unaudited) 2007 2006
Operating Activities
Net earnings for the period $8,904,000 $9,721,000
Items not affecting cash
Gain on sale of property - (532,000)
Unit based compensation 218,000 158,000
Dry hole costs 467,000 -
Depletion, depreciation and accretion 3,502,000 2,597,000
Future income taxes (recovery) 38,000 (323,000)
-------------------------------------------------------------------------
13,129,000 11,621,000
-------------------------------------------------------------------------
Change in non-cash working capital
Accounts receivable 539,000 275,000
Crude oil inventory (14,000) (127,000)
Parts inventory 8,000 75,000
Prepaid expenses 48,000 (125,000)
Accounts payable and accrued liabilities (897,000) 293,000
Asset retirement obligations settled (48,000) (83,000)
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(364,000) 308,000
-------------------------------------------------------------------------
Cash Provided by Operating Activities 12,765,000 11,929,000
-------------------------------------------------------------------------
Financing Activities
Increase in debt 7,456,000 7,040,000
Unit option proceeds 471,000 1,817,000
Unit distributions (11,476,000) (11,291,000)
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Cash Used in Financing Activities (3,549,000) (2,434,000)
-------------------------------------------------------------------------
Investing Activities
Property and equipment expenditures (7,625,000) (10,048,000)
Proceeds on sale of property - 750,000
-------------------------------------------------------------------------
(7,625,000) (9,298,000)
-------------------------------------------------------------------------
Change in non-cash working capital
Accounts receivable 264,000 (991,000)
Accounts payable and accrued liabilities (1,855,000) 794,000
-------------------------------------------------------------------------
(1,591,000) (197,000)
-------------------------------------------------------------------------
Cash Used in Investing Activities (9,216,000) (9,495,000)
-------------------------------------------------------------------------
Net Cash Inflow - -
Cash, beginning of period - -
-------------------------------------------------------------------------
Cash, End of Period $- $-
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash Interest Paid $ 697,000 $ 231,000
Cash Taxes Paid $ 90,000 $ 112,000
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------------------
Periods Ended March 31, 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". It exposes 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 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," the only
impact of which 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 March 31, 2007 was $3,448,000 and at December 31, 2006 was
$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
March 31, 2007 December 31, 2006
Accumulated Accumulated
Depletion and Depletion and
Cost Depreciation Cost Depreciation
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Undeveloped land $ 334,000 $ - $ 334,000 $ -
Petroleum and
natural gas
properties
and related
equipment 182,067,000 56,971,000 175,353,000 54,008,000
Furniture,
equipment
and other 959,000 611,000 915,000 642,000
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$183,360,000 $ 57,582,000 $176,602,000 $ 54,650,000
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4. DEBT
The Trust through its operating subsidiaries has a bank revolving credit
facility of $59,900,000 at March 31, 2007 (December 31, 2006 -
$49,900,000). 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 March 31,
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 three month periods ended March 31,
2007 and 2006 for these loans were $697,000 and $231,000 respectively.
5. UNIT CAPITAL
Authorized
The Trust is authorized to issue an unlimited number of trust units
without nominal or par value.
Issued Number Amount
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Trust Units
Balance, January 1, 2007 16,874,658 $89,488,000
Issued pursuant to Trust's
unit option plan 31,000 471,000
Transfer of contributed surplus to
unit capital - 50,000
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Balance, March 31, 2007 16,905,658 $90,009,000
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The number of trust units used to calculate diluted net earnings per unit
for the period ended March 31, 2007 of 16,913,263 (2006 - 16,783,806)
included the basic weighted average number of units outstanding of
16,899,000 (2006 - 16,676,699) plus 14,263 (2006 - 107,107) units related
to the dilutive effect of unit options.
The deficit balance is composed of the following items:
March 31, March 31,
2007 2006
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Accumulated earnings $131,310,000 $ 94,877,000
Accumulated cash distributions (167,077,000) (120,023,000)
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Deficit $(35,767,000) $(25,146,000)
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The Trust provides an option plan for its directors, officers, employees
and consultants. Under the plan, the Trust may grant options for up to
1,690,000 (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 March 31,
2007 and December 31, 2006, and changes during the three month and twelve
month periods ending on those dates is presented below:
March 31, 2007 December 31, 2006
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Options Weighted- Options Weighted-
Average Average
Exercise Exercise
Price Price
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Outstanding at beginning
of period 721,500 $26.55 646,000 $18.67
Options granted 24,000 24.34 447,000 29.18
Options exercised (31,000) 15.20 (339,500) 15.20
Options cancelled (8,000) 26.05 (32,000) 24.70
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Outstanding at end of period 706,500 $26.98 721,500 $26.55
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Options exercisable at end
of period 189,500 $23.35 212,500 $22.62
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The following table summarizes information about unit options outstanding
at March 31, 2007:
Options Outstanding Options Exercisable
----------------------------------- ----------------------
Weighted-
Number Average Weighted- Number Weighted-
Range of Outstanding Remaining Average Exercisable Average
Exercise At Contractual Exercise At Exercise
Prices 3/31/07 Life Price 3/31/07 Price
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$22.45-$23.35 247,500 2.0 years $23.32 189,500 $23.35
$24.20-$25.00 24,000 2.8 years 24.34 - -
$28.70-$28.75 395,000 1.9 years 28.75 - -
$32.00-$33.75 40,000 2.7 years 33.55 - -
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$22.45-$33.75 706,500 2.0 years $26.98 189,500 $23.35
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The Trust records a compensation expense over the vesting period based on
the fair value of options granted to employees, directors and
consultants.
6. ACCUMULATED OTHER COMPREHENSIVE INCOME
Three months ended March 31, 2007
Opening Other Ending
Comprehensive
Income
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Unrealized gains and losses
on available-for sale
financial assets $ 1,566,000 $ 982,000 $ 2,548,000
Unrealized gains and
losses on derivatives
designated as cash flow
hedges 814,000 (1,242,000) (428,000)
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$ 2,380,000 $ (260,000) $ 2,120,000
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7. RELATED PARTY TRANSACTIONS
The Trust received a management fee from Comaplex of $75,000 (2006 -
$75,000) for management services and office administration. This fee has
been included as a recovery in general and administrative expenses. The
above charge represents the fair value of the services rendered. As at
March 31, 2007 the Trust had an account receivable from Comaplex of
$53,000 (December 31, 2006 - $38,000).
The Trust received a management fee from Pine Cliff Energy Ltd. (Pine
Cliff) of $54,000 (2006 - $54,000) for management services and office
administration. This fee has been included as a recovery in general and
administrative expenses. As at March 31, 2007 the Trust had nominal
amounts for accounts receivable from or accounts payable to Pine Cliff.
The above charge represents the fair value of the services rendered.
8. 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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January 1, 2007 to Crude Oil 500 barrels WTI Floor of $74.55
June 30, 2007 and ceiling of
$85.00 per
barrel
January 1, 2007 to Crude Oil 500 barrels WTI Floor of $75.00
June 30, 2007 and ceiling of
$95.47 per
barrel
July 1, 2007 to Crude Oil 500 barrels WTI Floor of $75.00
December 31, 2007 and ceiling of
$93.00 per
barrel
July 1, 2007 to Crude Oil 500 barrels WTI Floor of $70.00
December 31, 2007 and ceiling of
$80.06 per
barrel
January 1, 2008 to Crude Oil 1,000 barrels WTI Floor of $73.00
June 30, 2008 and ceiling of
$83.00 per
barrel
April 1, 2007 to Natural Gas 2,000 GJ's AECO $6.52 per GJ
July 31, 2007
April 1, 2007 to Natural Gas 1,000 GJ's AECO Floor of $6.50
October 31, 2007 and ceiling of
$9.20 per GJ
November 1, 2007 to Natural Gas 2,000 GJ's AECO Floor of $6.50
March 31, 2008 and ceiling of
$10.37 per GJ
9. SUBSEQUENT EVENT - DISTRIBUTION
Subsequent to March 31, 2007, the Trust declared distributions of
$0.22 per unit payable on April 30 and May 31, 2007 to Unitholders of
record on April 16 and May 15, 2007 respectively. The distribution
represents funds flow in the Trust for the months of March and April
2007.%SEDAR: 00017467E
For further information:
For further information: Additional information relating to the Trust may be found on 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