Bonterra Energy Income Trust Announces Solid Second Quarter Results
CALGARY, Aug. 12 /CNW/ - Bonterra Energy Income Trust (the Trust or
Bonterra)(www.bonterraenergy.com) (TSX:BNE.UN) is pleased to announce its
financial and operational results for the three months and six months ended
June 30, 2008.HIGHLIGHTS
Three Months Ended Six Months Ended
June 30 June 30
2008 2007 2008 2007
-------------------------------------------------------------------------
FINANCIAL ($000, except $ per unit)
Revenue - realized oil and gas 34,398 23,462 64,891 46,064
Adjusted Distribution Base(1) 21,352 11,695 39,410 24,824
Per Unit - Basic 1.25 0.69 2.32 1.47
Per Unit - Diluted 1.24 0.69 2.31 1.47
Cash Distributions per Unit 0.84 0.66 1.54 1.32
Payout ratio 67% 96% 67% 90%
Net Earnings 12,912 5,371 23,716 13,033
Per Unit - Basic 0.76 0.32 1.40 0.77
Per Unit - Diluted 0.75 0.32 1.39 0.77
Capital Expenditures and
Acquisitions 2,543 1,699 8,964 9,324
Total Assets 153,247 139,432
Working Capital Deficiency(2) 57,147 49,595
Unitholders Equity 46,612 51,920
-------------------------------------------------------------------------
OPERATIONS
Oil and NGL's
Barrels Per Day 3,024 3,074 3,088 3,150
Average Price ($ per barrel) 101.69 67.60 94.31 65.02
Natural Gas
MCF Per Day 7,272 6,663 7,206 6,567
Average Price ($ per MCF) 9.61 7.40 8.97 7.46
Total Barrels per Day(3) 4,236 4,185 4,289 4,245
(1) Adjusted distribution base is not a recognized measure under GAAP.
Management believes that in addition to cash flow from operations,
adjusted distribution base is a useful supplemental measure as it
demonstrates the Trust's ability to generate the funds 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
adjusted distribution base 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 Canadian Institute of Chartered Accountants (CICA) published
recommendations regarding disclosure of a measure called Standardized
Distributable Cash. Please refer to page 9 of this report for the
reconciliation between adjusted distribution base and standardized
distributable cash.
(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.Report to Unitholders
Bonterra Energy Income Trust (Bonterra or the Trust) is pleased to report
the operating and financial results for the three months and six months ended
June 30, 2008. During the quarter, the Trust once again realized several new
milestones on the heels of a record-setting first quarter mainly due to the
sustained strength in both crude oil and natural gas prices, relatively stable
production levels and cost controls.Key successes included:
- Record-level revenue from oil and gas sales during the second quarter
of 2008 of approximately $34.4 million, a 12 percent increase over
the previous quarter and a 47 percent increase over second quarter
2007.
- Net earnings increased 140 percent to an all-time high of
approximately $12.9 million in the second quarter of 2008 compared to
$5.4 million in the second quarter of 2007. Net earnings also
increased 20 percent quarter over quarter.
- Bonterra's adjusted distribution base was approximately
$21.4 million, an increase of 18 percent over first quarter 2008 and
83 percent over second quarter 2007.
- Cash distributions to unitholders increased to $0.84 per unit during
the quarter compared to $0.66 in the second quarter of 2007; a payout
ratio of 67 percent in 2008 compared to 96 percent in 2007.
Subsequent to the quarter end, Bonterra increased the distribution to
$0.32 per trust unit for both the July and August payments. This
represents the fourth increase during 2008. The January, 2008
distribution was $0.22 per unit.The continued strength in crude oil and natural gas prices can be seen in
Bonterra's average realized price of $101.69 per barrel for oil and natural
gas liquids and $9.61 per mcf for natural gas during the second quarter of
2008. This represents an increase of 50 percent and 30 percent, respectively,
when compared with the second quarter of 2007.
As a result, Bonterra's cash netbacks also increased to a record level of
$55.34 per barrel of oil equivalent (boe) in the second quarter of 2008
compared to $45.67 per boe in the first quarter of 2008 and $32.09 in the
second quarter of 2007. The increased netbacks were mainly a result of the
aforementioned strength in commodity prices which more than offset increased
royalty expense and a higher realized loss on risk management contracts during
the quarter.
Bonterra's exposure to the higher prices was offset somewhat by its risk
management program. Bonterra has entered into commodity hedging contracts on
approximately 28 percent of its 2008 production. Realized risk management
losses for the first six months of 2008 were approximately $5.4 million. The
risk management contracts will all expire on December 31, 2008. In light of
the exceptionally strong prices Bonterra is receiving for production coupled
with the reduction in the payout ratio, management and the board of directors
have reassessed the hedging policy and decided that in the near term the Trust
will not enter into further risk management strategies.
Bonterra intends to continue providing superior value to unitholders by
paying stable, or when appropriate increase or decrease distributions while
executing a conservative and targeted development program. Bonterra's current
distribution level of $0.32 per trust unit is expected to be sustainable as
long as prices average Cdn $115 per barrel of crude oil and Cdn $9.50 per mcf
of natural gas and production is sustained at a rate of approximately
4,450 boe per day.
As the Trust produces its oil and gas assets, it is essential to invest
capital to not only offset natural production declines but grow production and
reserves. Bonterra's decline rate is among the lowest in the energy trust
sector. This not only highlights the top-quality nature of the asset base but
also allows the Trust to spend less capital to replace and increase production
while paying out a higher portion of its adjusted distribution base.
Daily production decreased slightly in the second quarter of 2008 to
4,236 boe per day when compared to first quarter 2008 levels of 4,343 boe per
day. Production levels have been historically lower for the Trust in the
second quarter versus the first quarter each year. This is mainly due to over
85 percent of wells having restricted access during second quarters due to
spring break-up and restricted road access. During the quarter, Bonterra was
unable to complete wells, tie-ins and timely repairs which negatively impacted
production. In addition, the operator of a natural gas plant where 40 percent
of the Trust's Pembina production is processed conducted their annual
turnaround during the month of May resulting in approximately 300 mcf per day
of natural gas being shut-in.
However, this did represent a slight increase when compared to the second
quarter of 2007 where 4,185 boe per day was recorded. For the first six months
of 2008, the Trust incurred capital expenditures of approximately 8.5 million
on its development program. Key activities included drilling:- 10 Cardium oil wells (8.1 net) and 1 shallow gas well (0.1 net) on
operated lands; and
- 3 Cardium wells (0.4 net) on non-operated lands;The Trust's success rate is 100 percent on its 2008 drilling program. In
addition, 16 Cardium wells and 2 natural gas wells were tied-in during the
first half of the year. The remaining 4 Cardium oil wells were tied in
subsequent to quarter-end. The final natural gas well is expected to be
completed and tied in prior to the end of the third quarter this year.
In view of the higher commodity price environment and current
expectations, the Board of Directors has deemed it appropriate to increase the
full year capital budget by 25 percent to $25 million. Bonterra's development
program is typically most active with the commencement of its summer drill
program. The balance of this year's program is expected to begin in the third
week of August and include drilling 17 Cardium wells (approximately 14.5 net)
prior to year-end and 3 to 5 shallow gas wells.
Bonterra has historically grown production and reserves by developing its
own properties rather than through acquisitions. However, Bonterra's
conservative capital structure and strong balance sheet positions the Trust to
capitalize on any future opportunities should they arise.
In the second quarter of 2008, the Trust's net debt as a percentage of
annualized adjusted distribution base was approximately eight months.
Management and the Board are of the opinion that by limiting debt levels to
approximately one year adjusted distribution base or less, the Trust will be
well-situated to make strategic acquisitions. In addition, this provides
Bonterra with the flexibility to fund its development program from cash flow,
the exercise of employee trust unit options and additional bank loans if need
be without having to issue further equity.
Bonterra will continue to assess all future acquisition opportunities. As
well, the Trust is continuing to evaluate the options available to it in
response to the federal government's legislation change to the taxation of
Canadian trusts. The board and management are currently considering whether to
continue as a trust until the end of 2010 when the tax structure will change
or whether there may be advantages in converting its structure earlier.
Bonterra expects to have greater clarity regarding a longer-term solution
within the year.
We wish to thank both the Board of Directors and staff for their efforts
and hard work during the first half of the year. The record-level operating
and financial results recorded would not be possible without a unified and
focused effort. As the Trust moves into the second half of 2008, it will
continue to execute the long-term strategy to maximize unitholder returns
through prudent financial management while conservatively growing the Trust
with a targeted exploitation and development program.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 there from. 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.Financial and Operational Discussion
------------------------------------
Production
----------
Three months ended Six months ended
June 30, Mar 31, June 30, June 30, June 30,
2008 2008 2007 2008 2007
-------------------------------------------------------------------------
Crude oil and NGLs
(barrels per day) 3,024 3,153 3,074 3,088 3,150
Natural gas (MCF per day) 7,272 7,139 6,663 7,206 6,567
-------------------------------------------------------------------------
Total BOE's per day 4,236 4,343 4,185 4,289 4,245
-------------------------------------------------------------------------Barrels of oil equivalent (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 volumes for the second quarter were affected primarily by two
factors. Firstly, spring breakup prevented timely repairs on the Trust's
producing wells. This is a normal occurrence as over 85 percent of the Trust's
wells have restricted access during the second quarter of each year. Secondly,
the operator of a natural gas plant where approximately 40 percent of the
Trust's Pembina production gets processed conducted their annual turnaround
during the month of May resulting in an average of approximately 300 MCF per
day (50 BOE per day for the month of May) of natural gas being shut-in.
The Trust drilled 10 gross (8.1 net) Cardium oil wells and 1 gross
(.1 net) shallow gas well in the first six months of 2008 on its operated
lands. In addition the Trust participated in the drilling of 3 (.4 net)
Cardium wells on non-operated lands. As at June 30, 2008, Bonterra had 4 gross
(4 net) Cardium oil wells and 1 gross (.1 net) natural gas wells and 3 gross
(2.5 net) coalbed methane wells (CBM) drilled but not on production. During
the first six months of 2008, the Trust tied-in 16 gross (10.8 net) Cardium
wells and 2 gross (2 net) natural gas wells. The Trust completed and tied-in
the remaining Cardium oil wells in July. The natural gas well is anticipated
to be completed and tied in prior to the end of the third quarter.
It is currently expected that the summer drill program will commence
during the third week of August. It is anticipated that a total of 17 gross,
approximately 14.5 net, Cardium wells will be drilled prior to December 31.
Bonterra is also pursuing the possible drilling of 3 to 5 shallow gas wells in
2008. Based on current expectations the Trust is increasing its 2008 capital
drilling budget by $5,000,000 to $25,000,000.Revenue
-------
Three months ended Six months ended
June 30, Mar 31, June 30, June 30, June 30,
(Cdn $) 2008 2008 2007 2008 2007
-------------------------------------------------------------------------
Revenue - oil and gas
sales (000's) 34,398 30,493 23,462 64,891 46,064
Average Realized Prices:
Crude oil and NGLs
(per barrel) 101.69 87.20 67.60 94.31 65.02
Natural gas (per MCF) 9.61 8.32 7.40 8.97 7.46
-------------------------------------------------------------------------Second quarter realized gross revenue of $34,398,000 was the highest
single quarter revenue ever recorded by the Trust. The increase in revenue
over prior periods was primarily due to higher commodity prices. Included in
revenue is a realized loss on risk management contracts of $5,381,000 for the
first six months of 2008 ($815,000 gain in the first six months of 2007). In
addition, the Trust also recorded an unrealized loss on risk management
contracts of $7,025,000 for the first six months of 2008 (first six months of
2007 - $439,000). All fair value adjustments related to outstanding risk
management contracts are recorded as adjustments to net earnings.
During the first quarter of 2008, the Trust reassessed its hedging
policy. With the disposal of the Trust's interest in the Dodsland properties,
which had production volume of approximately one barrel per day per well and
operating costs per barrel in the mid $30's, as well as the reduction in the
payout ratio from the high 80 percent to mid 60 percent range, Bonterra has
decided that at least in the near term it will not enter into further risk
management contracts. The Trust will however maintain the existing risk
management agreements until they expire. Kindly refer to Note 10 to the
attached interim financial statements for details of outstanding risk
management contracts. As at June 30, 2008, the fair value of the outstanding
risk management contracts was a net liability of $10,109,000 (December 31,
2007 - $3,085,000).Royalties
---------
Three months ended Six months ended
June 30, Mar 31, June 30, June 30, June 30,
($ 000) 2008 2008 2007 2008 2007
-------------------------------------------------------------------------
Crown royalties 4,263 3,613 2,389 7,876 4,545
Freehold royalties, gross
overriding royalties and
net carried interests 1,056 731 1,479 1,787 1,901
-------------------------------------------------------------------------
Total royalty expense 5,319 4,344 3,868 9,663 6,446
-------------------------------------------------------------------------Royalties paid by the Trust consist primarily of Crown royalties paid to
the Provinces of Alberta and Saskatchewan. The non-Crown royalty figure for
the six months ended June 30, 2007 includes a prior year royalty charge
adjustment of $800,000.
The majority of the Trust's wells are low productivity wells and
therefore have low Crown royalty rates. The Trust's average Crown royalty rate
is approximately 11.2 percent (2007 - 10 percent) and approximately
2.5 percent (2007 - 2.5 percent) for other royalties before hedging
adjustments. Bonterra continues to expect an average combined royalty rate of
approximately 13.5 percent for the balance of 2008.
The recently announced Alberta royalty amendments will result in a higher
average royalty rate for Bonterra in 2009 and beyond. The Trust currently
estimates that the new legislation will increase the average Crown royalty
rate by between 4 to 6 percent (15-17 percent of gross revenues). The new
royalty rates vary by prices as well as productivity levels.Production Costs
----------------
Three months ended Six months ended
June 30, Mar 31, June 30, June 30, June 30,
($ 000) 2008 2008 2007 2008 2007
-------------------------------------------------------------------------
Production costs 6,089 6,317 6,556 12,406 12,137
$ per BOE 15.79 15.98 17.21 15.89 15.80
-------------------------------------------------------------------------Continued high commodity prices have resulted in service cost increases
in the 5 to 10 percent range on a year over year basis. The Trust continues to
monitor costs as best it can, but given the high commodity price environment,
it expects costs per BOE to remain in the $15.50 to $16.00 range for the
remainder of 2008.
The Trust's production comes primarily from low productivity wells. These
wells generally result in higher production costs on a per unit-of-production
basis as costs such as municipal taxes, surface leases, power and personnel
costs are not variable with production volumes. The high production costs for
the Trust are substantially offset by current low royalty rates of
approximately 13.5 percent, which is much lower than industry average for
conventional production and results in high cash netbacks on a combined basis
despite higher than industry average production costs.General and Administrative (G&A) Expense
----------------------------------------
Three months ended Six months ended
June 30, Mar 31, June 30, June 30, June 30,
($ 000) 2008 2008 2007 2008 2007
-------------------------------------------------------------------------
G&A Expense 855 877 527 1,732 1,091
$ per BOE 2.22 2.22 1.42 2.22 1.44
-------------------------------------------------------------------------
The increase in G&A expense year over year was due to increased employee
compensation of approximately $575,000 as well as increases in other
professional service costs of approximately $100,000. Offsetting a portion of
the increase was increased cost recoveries of $26,000 from related
corporations (see Related Party section).
Interest Expense
----------------
Three months ended Six months ended
June 30, Mar 31, June 30, June 30, June 30,
($ 000) 2008 2008 2007 2008 2007
-------------------------------------------------------------------------
Interest Expense 650 799 744 1,449 1,441
-------------------------------------------------------------------------Increases in average outstanding debt balances in 2008 over 2007 amounts
were offset by an approximately one percent drop in borrowing rates. The
quarter over quarter decrease was due to slightly lower interest rates as well
as reduced debt balances. Increased cash flow resulting from record crude oil
prices coupled with the Trust's lower payout ratio resulted in a reduction of
approximately $6,000,000 in the Trust's debt in Q2 from Q1 2008. With spring
breakup during the second quarter, restricting Bonterra's capital programs,
and continuing record commodity prices the Trust anticipates reduced debt
levels for the third quarter of 2008 increasing thereafter as the Trust
continues with its fall and winter drill programs. Bonterra is currently able
to borrow at rates between 4.35 and 4.75 percent per annum.
The Trust's net debt as a percentage of annualized second quarter
adjusted distribution base was approximately eight months (67 percent). The
Trust believes that maintaining debt at or less than one year's adjusted
distribution base (calculated quarterly based on annualized quarterly results)
is an appropriate level to either take advantage of future acquisition
opportunities or provide flexibility to develop its infill oil, shallow gas
and CBM potential from its cash flow and additional bank loans. Thus, it
should not be necessary to issue additional trust units.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. During the quarter
29,000 employee unit options were issued with an estimated fair value of
$115,000 ($3.95 per option) using the Black-Scholes pricing model. If no
further options are issued approximately $548,000 of compensation expense will
be expensed during the remainder of 2008, 2009 and 2010.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 $7,010,000 and
$6,786,000, respectively for the six month periods ending June 30, 2008 and
June 30, 2007. The increase in the depletion amount was due primarily to
increased production volumes and a marginal increase in the average cost of
reserves.
The Trust continues to replace production declines with reserves from
newly drilled wells. The Trust has capital costs of approximately $6.10 per
proved BOE of reserves based on the December 31, 2007 independent engineering
report.
All wells drilled during the fourth quarter of 2007 and first half of
2008 have been successful and therefore no dry hole costs were recorded during
2008.Taxes
-----Future income tax expense for the first six months of 2008 decreased by
$2,590,000 compared to the first six months of 2007. Until June 2007, the
Trust had been tax effecting the reversal of taxable temporary differences at
a nil tax rate on the assumption that the Trust would make sufficient tax
deductible cash distributions to Unitholders such that the Trust's taxable
income would be nil for the foreseeable future and the tax burden would have
continued to be with whomever received the monthly distribution. The new
legislation limits the tax deductibility of cash distributions such that
income taxes may become payable in the future. This resulted in a one-time
adjustment to 2007's future income tax expense of approximately $3.8 million.
The Trust has estimated its future income taxes based on its best
estimates of results from operations and tax pool claims and cash
distributions in the future assuming no material change to the Trust's current
organizational structure. As currently interpreted, Canadian Generally
Accepted Accounting Principles (GAAP) does not permit the Trust's estimate of
future income taxes to incorporate any assumptions related to a change in
organizational structure until such structures are given legal approval.
The Trust's estimate of its future income taxes will vary as to the
Trust's assumptions pertaining to the factors described above and such
variations may be material.
Until 2011, the new legislation does not directly affect the Trust's cash
flow from operations, and accordingly, the Trust's financial condition.
Currently, 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.
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 a resource surcharge payable by the
Trust's 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 reduced the resource surcharge rate to 3.1 percent on July 1, 2007 and to
3.0 percent on July 1, 2008.
The Canadian taxable portion of distributions for each taxation year is
calculated on an annual basis and is reported by February 28 of the following
year.Net Earnings
------------
Three months ended Six months ended
June 30, Mar 31, June 30, June 30, June 30,
($ 000) 2008 2008 2007 2008 2007
-------------------------------------------------------------------------
Net Earnings 12,912 10,804 5,371 23,716 13,033
-------------------------------------------------------------------------Net earnings increased to an all time high of $23,716,000 in the first
half of 2008 from $13,033,000 in the corresponding 2007 period. Revenue
increases due to increased commodity prices and production were partially
offset by increased loss on risk management contracts (both realized and
unrealized) as well as increased royalty expense. The Trust's quarter over
quarter net earnings increased $2,108,000 due primarily to increased commodity
prices.
The Trust continues to return in excess of 35 percent of its gross
realized revenues in net earnings. The Trust's low capital costs combined with
a low debt to adjusted distribution base ratio all contribute to the high
return. Bonterra's higher than industry average per unit operating costs are
more than offset with its low royalty rates resulting in one of the highest
cash netbacks in the industry (see cash netback).Comprehensive Income
--------------------On January 1, 2007, the Trust adopted the new GAAP accounting standards
regarding the accounting for financial instruments. On adoption, the Trust
increased its investment in a related party by $1,836,000 for the fair value
of this investment. Other comprehensive income for the first half of 2008
included a decrease in the unrealized gain on investment in a related party of
$164,000 (2007 increase of $628,000) net of applicable income taxes.Standardized Distributable Cash
-------------------------------Compliance with Guidance
This Management's 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".Definition and Disclosure of Standardized Distributable Cash
Cumulative
Amounts from
Inception
of Trust
Six Six (July 1,
Months Ended Months Ended 2001) to
June 30, June 30, June 30,
($000) 2008 2007 2008
-------------------------------------------------------------------------
Cash Flow from Operating Activities 36,742 26,178 255,017
Less adjustment for:
Capital expenditures (8,964) (9,324) (103,462)
Financing restrictions caused
by debt - - -
-------------------------------------------------------------------------
Standardized Distributable Cash 27,778 16,854 151,555
-------------------------------------------------------------------------
Definition and Disclosure of Adjusted Distribution Base (Formerly Funds
Flow from Operations)
Cumulative
Amounts from
Inception
of Trust
Six Six (July 1,
Months Ended Months Ended 2001) to
June 30, June 30, June 30,
($000) 2008 2007 2008
-------------------------------------------------------------------------
Standardized Distributable
Cash - per above 27,778 16,854 151,555
Adjusted for:
Capital expenditures 8,964 9,324 103,462
Gain on sale of property - - 1,089
Changes in accounts receivable 4,837 (599) 10,413
Changes in crude oil inventory (87) (65) 166
Changes in parts inventory (11) (24) (201)
Changes in prepaid expenses 1,058 454 1,556
Changes in accounts payable and
accrued liabilities (5,042) (1,429) (3,179)
Asset retirement obligations
settled 1,913 309 4,442
-------------------------------------------------------------------------
Adjusted Distribution Base(1) 39,410 24,824 269,303
-------------------------------------------------------------------------
(1) Adjusted distribution base is not a recognized measure under GAAP.
The Trust believes that in addition to cash flow from operations the
adjusted distribution base is a useful supplemental measure as it
demonstrates the Trust's ability to generate the funds 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
adjusted distribution base as funds provided by operations before
changes in non-cash operating working capital items excluding gain on
sale of property and asset retirement obligations.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 reoccurring items that would cause a seasonal
impact in working capital.Analysis of Relationship between Standardized Distributable Cash,
Distributions, and Investing and Financing Activities
Six Months
Ended Year ended Year ended Year ended
June 30, December 31, December 31, December 31,
($000) 2008 2007 2006 2005
-------------------------------------------------------------------------
Standardized Distributable
Cash 27,778 32,133 14,346 23,413
Distributions(1) (26,211) (44,648) (47,281) (38,949)
Increase (decrease) in
bank debt (4,442) 12,043 25,202 11,717
Proceeds on exercise
of employee unit options 4,490 993 5,161 2,823
Issuance of units (net of
costs of issue) - - - (259)
Non-cash financing and
investing working capital
adjustments (1,615) (521) 2,572 1,255
-------------------------------------------------------------------------
(1) Includes the distribution declared in July in respect of June
operations and excludes the January, distribution as it was in
respect of December 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:
Expenditure
Expected
Year ($000)
-------------------------------------------------------------------------
2008 (including expenditures incurred to date) 2,227
2009 250
2010 175
2011 563
2012 856
-------------------------------------------------------------------------
4,071
-------------------------------------------------------------------------Definition and History of Productive Capacity and Strategy
Bonterra's primary objective is to continue paying distributions to its
Unitholders. This is accomplished by developing and growing its reserves from
which cash flow is generated. The Trust defines Productive Capacity
Maintenance as the maintaining of the Trust's 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
Ended Year ended Year ended Year ended
June 30, December 31, December 31, December 31,
2008 2007 2006 2005
-------------------------------------------------------------------------
Proven and probable
reserves at beginning
of period (BOE's) 27,320,000 26,476,000 23,870,000 19,711,000
Reserves added due to
acquisitions (BOE's) - (421,000) 16,000 2,393,000
Reserves added due to
capital expenditures
(BOE's) (1) 2,806,000 4,082,000 3,100,000
Production during
period (BOE's) 781,000 1,540,000 1,476,000 1,334,000
Increase in productive
capacity (BOE's) (1) 845,000 2,606,000 4,159,000
Reserves per unit
(fully diluted) 1.55(1)(2) 1.62 1.57 1.46
Productive capacity
maintenance
requirements $8,642,000 $17,043,000 $17,472,000 $9,205,000
Capital expenditures
for the period $8,964,000 $19,300,000 $38,348,000 $56,703,000
Capital expenditures
in excess of
maintenance
requirements $322,000 $2,257,000 $20,876,000 $47,498,000
Cost of increased
productive capacity
(per BOE) (1) $2.67 $8.01 $11.42
-------------------------------------------------------------------------
(1) The Trust does not update reserve information quarterly.
(2) Assuming no other additional reserves in 2008.Financing Strategy
The Trust maintains a strategy of limiting its debt levels to
approximately one year adjusted distribution base. Bonterra has a long-term
goal to retain between 20 to 25 percent of its adjusted distribution base to
finance its capital maintenance expenditures. Over the past years, this level
of retention of adjusted distribution base, along with the exercising of unit
options and modest increases in its bank loans has proven to be sufficient to
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 exceeds 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 the adjusted distribution base. 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 that the
debt is payable upon demand.Per Unit and Ratio Disclosures
Cumulative
Amounts from
Inception
of Trust
Six Six (July 1,
Months Ended Months Ended 2001) to
June 30, June 30, June 30,
($000 except $ per unit) 2008 2007 2008
-------------------------------------------------------------------------
Standardized Distributable Cash 27,778 16,854 151,555
Per weighted average unit 1.64 1.00 9.64
Per fully diluted unit 1.63 1.00 9.59
Cash distributions(1) 26,211 22,309 230,510
Payout ratio 0.94 1.32 1.52
Adjusted Distribution Base 39,410 24,824 269,303
Per weighted average unit 2.32 1.47 17.25
Per fully diluted unit 2.31 1.47 17.13
Cash distributions(1) 26,211 22,309 230,510
Payout ratio 0.67 0.90 0.86
-------------------------------------------------------------------------
(1) Includes distributions declared in July 2008 and 2007 in respect of
June 2008 and 2007 operations, respectively.On a go forward basis, the Trust plans to maintain the payout ratio in
respect of Standardized Distributable Cash at a level between 110 to
120 percent to facilitate a debt to cash flow level of less than one year and
to not incur current tax (excluding Saskatchewan Resource Surcharge). This
will be attained through controlling costs of capital replacement, by
examining lower cost methods of reserve replacement as well as increased cash
flow from wells currently producing.
Tax Attributes of Distributions and the Trust's Assets
See discussion under 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 as
described above in this report):
June 30, June 30,
$ per Barrel of Oil Equivalent (BOE) 2008 2007
-------------------------------------------------------------------------
Production volumes (BOE) 780,644 757,485
Gross production revenue $90.02 $59.73
Realized gain (loss) on risk management contracts (6.90) 1.08
Royalties (12.38) (8.51)
Field operating costs (15.89) (15.80)
-------------------------------------------------------------------------
Field netback 54.85 36.50
General and administrative (2.22) (1.44)
Interest and taxes (2.18) (2.11)
-------------------------------------------------------------------------
Cash netback $50.45 $32.95
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The following table illustrates the Trust's cash netback for the three
month periods:
June 30, March 31,
$ per Barrel of Oil Equivalent (BOE) 2008 2008
-------------------------------------------------------------------------
Production volumes (BOE) 385,468 395,176
Gross production revenue $99.66 $80.62
Realized gain (loss) on risk management contracts (10.43) (3.46)
Royalties (13.81) (10.99)
Field operating (15.80) (15.98)
-------------------------------------------------------------------------
Field netback 59.62 50.19
General and administrative (2.22) (2.22)
Interest and taxes (2.06) (2.30)
-------------------------------------------------------------------------
Cash netback $55.34 $45.67
-------------------------------------------------------------------------
-------------------------------------------------------------------------Liquidity and Capital Resources
-------------------------------
During the first six months of 2008, the Trust incurred capital costs of
$8,964,000 (2007 - $9,324,000). The Trust and its partners drilled 13 gross
(8.5 net) Cardium oil wells and one gross (0.1 net) shallow gas well in the
first half of 2008.
The Trust currently has plans to drill a total of 30 gross (23 net)
Cardium infill oil wells in 2008 and 5 gross shallow gas wells. Total capital
costs of approximately $25,000,000 are budgeted for 2008. It is anticipated
that the entire 2008 capital expenditures will be funded from cash flow and
funds from the exercise of employee unit options. Should it be necessary, the
Trust will use its financial facilities to cover any shortfall.
The Trust, through its operating subsidiaries, has a bank revolving
credit facility of $69,900,000 at June 30, 2008 (December 31, 2007-
$69,900,000). The credit facilities carry an interest rate of Canadian
chartered bank prime.
Sensitivity Analysis
--------------------
Commodity prices have fluctuated significantly over the recent past. The
following table updates the cash flow sensitivity for movements in the
commodity prices of $1 U.S. WTI for crude oil, $0.10 per MCF AECO for natural
gas and $0.01 fluctuation in exchange rates. These figures have been updated
from December 31, 2007 to include commodity price hedges entered into during
the first half of 2008.Cash Flow
-------------------------------------------------------------------------
U.S. $1.00 per barrel $ 692,000
Canadian $0.10 per MCF $ 181,000
Change of Canadian $0.01/U.S. $ exchange rate $ 587,000
-------------------------------------------------------------------------
The TSX does not accept responsibility for the adequacy or accuracy of
this release.
BONTERRA ENERGY INCOME TRUST
CONSOLIDATED BALANCE SHEETS
As at June 30, 2008 (unaudited) and
December 31, 2007
($000) 2008 2007
Assets
Current
Accounts receivable 15,412 10,575
Crude oil inventory 648 792
Parts inventory 121 132
Prepaid expenses 2,388 1,330
Future income tax asset (Note 5) 2,986 913
Investments in related party (Note 2) 3,828 4,014
-------------------------------------------------------------------------
25,383 17,756
-------------------------------------------------------------------------
Property and Equipment (Note 3)
Petroleum and natural gas properties
and related equipment 196,243 187,288
Accumulated depletion and depreciation (68,379) (61,805)
-------------------------------------------------------------------------
Net Property and Equipment 127,864 125,483
-------------------------------------------------------------------------
153,247 143,239
-------------------------------------------------------------------------
Liabilities
Current
Distribution payable 5,474 3,724
Accounts payable and accrued liabilities 13,967 12,291
Derivative liability 10,110 3,085
Debt (Note 4) 52,980 57,422
-------------------------------------------------------------------------
82,531 76,522
Future Income Tax Liability (Note 5) 10,741 7,595
Asset Retirement Obligations 13,363 14,904
-------------------------------------------------------------------------
106,635 99,021
-------------------------------------------------------------------------
Commitments (Note 9)
Unitholders' Equity (Note 6)
Unit capital 95,528 90,590
Contributed surplus 2,254 2,140
-------------------------------------------------------------------------
97,782 92,730
-------------------------------------------------------------------------
Deficit (54,037) (51,543)
Accumulated other comprehensive income (Note 7) 2,867 3,031
-------------------------------------------------------------------------
(51,170) (48,512)
Total Unitholders' Equity 46,612 44,218
-------------------------------------------------------------------------
153,247 143,239
-------------------------------------------------------------------------
BONTERRA ENERGY INCOME TRUST
CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY
For the periods ended
June 30 (unaudited) Three Months Six Months
($000) 2008 2007 2008 2007
-------------------------------------------------------------------------
Unitholders' equity,
beginning of period 48,136 57,646 44,218 53,359
Comprehensive income
for the period 12,577 5,017 23,552 13,661
Adjustment of opening
accumulated comprehensive
income - - - 2,380
Net capital contributions 4,210 234 4,490 705
Unit based compensation
adjustment 279 185 562 403
Distributions declared (18,590) (11,162) (26,210) (18,588)
-------------------------------------------------------------------------
Unitholders' Equity,
End of Period 46,612 51,920 46,612 51,920
-------------------------------------------------------------------------
-------------------------------------------------------------------------
BONTERRA ENERGY INCOME TRUST
CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT
For the periods ended June 30
(unaudited)
($000, except $ per unit) Three Months Six Months
2008 2007 2008 2007
(Note 11) (Note 11)
-------------------------------------------------------------------------
Revenue
Oil and gas sales 38,412 23,237 70,272 45,249
Realized gain (loss) on
risk management
contracts (4,014) 225 (5,381) 815
Unrealized gain (loss)
on risk management
contracts (Note 10) (4,636) 1,313 (7,025) (439)
Royalties (5,319) (3,868) (9,663) (6,446)
Interest and other 9 12 22 33
-------------------------------------------------------------------------
24,452 20,919 48,225 39,212
-------------------------------------------------------------------------
Expenses
Production costs 6,089 6,556 12,406 12,137
General and
administrative 855 527 1,732 1,091
Interest on debt 650 744 1,449 1,441
Unit option based
compensation 279 185 562 403
Dry hole costs - 9 - 476
Depletion, depreciation
and accretion 3,516 3,284 7,010 6,786
-------------------------------------------------------------------------
11,389 11,305 23,159 22,334
-------------------------------------------------------------------------
Earnings Before Taxes 13,063 9,614 25,066 16,878
-------------------------------------------------------------------------
Taxes (Note 5)
Current 142 84 253 158
Future 9 4,159 1,097 3,687
-------------------------------------------------------------------------
151 4,243 1,350 3,845
-------------------------------------------------------------------------
Net Earnings for
the Period 12,912 5,371 23,716 13,033
Deficit at beginning
of period (48,359) (37,009) (51,543) (37,245)
Distributions declared (18,590) (11,162) (26,210) (18,588)
-------------------------------------------------------------------------
Deficit at End of Period (54,037) (42,800) (54,037) (42,800)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Earnings per Trust
Unit - Basic 0.76 0.32 1.40 0.77
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Earnings per Trust
Unit - Diluted 0.75 0.32 1.39 0.77
-------------------------------------------------------------------------
-------------------------------------------------------------------------
BONTERRA ENERGY INCOME TRUST
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the periods ended June 30
(unaudited)
($000, except $ per unit) Three Months Six Months
2008 2007 2008 2007
(Note 11) (Note 11)
-------------------------------------------------------------------------
Net Earnings for the
Period 12,912 5,371 23,716 13,033
Unrealized gains (losses)
on investments (net of
income taxes; three months
ended 2008 - 25,
2007 - (61), six months
ended 2008 - (22),
2007 - 109) (335) (354) (164) 628
-------------------------------------------------------------------------
Other Comprehensive Income
(Loss) (335) (354) (164) 628
-------------------------------------------------------------------------
Comprehensive Income 12,577 5,017 23,552 13,661
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Comprehensive Income Per
Trust Unit - Basic 0.74 0.30 1.39 0.81
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Comprehensive Income Per
Trust Unit - Diluted 0.73 0.30 1.38 0.81
-------------------------------------------------------------------------
-------------------------------------------------------------------------
BONTERRA ENERGY INCOME TRUST
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the periods ended June 30
(unaudited)
($000) Three Months Six Months
2008 2007 2008 2007
(Note 11) (Note 11)
-------------------------------------------------------------------------
Operating Activities
Net earnings for the
period 12,912 5,371 23,716 13,033
Items not affecting cash
Unrealized loss on risk
management contracts 4,636 (1,313) 7,025 439
Unit option based
compensation 279 185 562 403
Dry hole costs - 9 - 476
Depletion, depreciation
and accretion 3,516 3,284 7,010 6,786
Future income taxes 9 4,159 1,097 3,687
-------------------------------------------------------------------------
21,352 11,695 39,410 24,824
-------------------------------------------------------------------------
Change in non-cash
working capital
Accounts receivable (1,636) 60 (4,837) 599
Crude oil inventory (55) 79 87 65
Parts inventory (3) 16 11 24
Prepaid expenses (1,113) (502) (1,058) (454)
Accounts payable and
accrued liabilities 2,171 2,326 5,042 1,429
Asset retirement
obligations settled (186) (261) (1,913) (309)
-------------------------------------------------------------------------
(822) 1,718 (2,668) 1,354
-------------------------------------------------------------------------
Cash Provided by
Operating Activities 20,530 13,413 36,742 26,178
-------------------------------------------------------------------------
Financing Activities
Increase (decrease)
in debt (5,933) 1,766 (4,442) 9,222
Unit option proceeds 4,210 234 4,490 705
Unit distributions (13,116) (11,162) (24,460) (22,638)
-------------------------------------------------------------------------
Cash Used in Financing
Activities (14,839) (9,162) (24,412) (12,711)
-------------------------------------------------------------------------
Investing Activities
Property and equipment
expenditures (2,543) (1,699) (8,964) (9,324)
Change in non-cash
working capital
Accounts receivable - 729 - 993
Accounts payable and
accrued liabilities (3,148) (3,281) (3,366) (5,136)
-------------------------------------------------------------------------
Cash Used in Investing
Activities (5,691) (4,251) (12,330) (13,467)
-------------------------------------------------------------------------
Net Cash Inflow - - - -
Cash, beginning of period - - - -
-------------------------------------------------------------------------
Cash, End of Period - - - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash Interest Paid 650 744 1,449 1,441
Cash Taxes Paid 90 93 368 183
-------------------------------------------------------------------------
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------------------
Periods Ended June 30, 2008 and 2007 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
2007 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 2007 annual financial statements.
The Trust adopted Section 1535 "Capital Disclosures", Section 3862,
"Financial Instruments - Disclosures" and Section 3863, "Financial
Instruments - Presentation". All the above Sections were required to be
adopted for fiscal years beginning on or after October 1, 2007. As a
result, the Trust has added Note 9 providing the required disclosures
regarding the Trust's objectives, policies and processes for managing
capital and 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.
The Trust also adopted Section 3031 - "Inventories", which replaces
Section 3030. This section is harmonized with International Accounting
Standards and provides additional guidance on the measurement and
disclosure requirements for inventories. This new standard did not have
an impact on the Trust's financial statements.
Accounting changes
In February 2008, the CICA issued Section 3064, "Goodwill and Intangible
Assets", replacing Section 3062, "Goodwill and Other Intangible Assets"
and Section 3450, "Research and Development Costs". Various changes have
been made to other sections of the CICA Handbook for consistency
purposes. The new section will be applicable to financial statements
relating to fiscal years beginning on or after October 1, 2008.
Accordingly, the Trust will adopt the new standards for its fiscal year
beginning January 1, 2009. This standard establishes standards for the
recognition, measurement, presentation and disclosure of goodwill
subsequent to its initial recognition and of intangible assets by profit-
oriented enterprises. Standards concerning goodwill are unchanged from
the standards included in the previous Section 3062. The Trust does not
expect that the adoption of this new Section will have a material impact
on its consolidated financial statements.
2. INVESTMENT IN RELATED PARTY
The investment consists of 689,682 (December 31, 2007 - 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, 2008 of $5.55 per share and at December 31, 2007 of
$5.82 per share. The common shares trade on the Toronto Stock Exchange
under the symbol CMF. The investment represents less than one and a half
percent ownership in the outstanding shares of Comaplex.
3. PROPERTY AND EQUIPMENT
June 30, 2008 December 31, 2007
-------------------------------------------------------------------------
Accumulated Accumulated
Depletion and Depletion and
($000) Cost Depreciation Cost Depreciation
-------------------------------------------------------------------------
Undeveloped land 316 - 316 -
Petroleum and natural gas
properties and related
equipment 194,872 67,624 185,947 61,105
Furniture, equipment
and other 1,055 755 1,025 700
-------------------------------------------------------------------------
196,243 68,379 187,288 61,805
-------------------------------------------------------------------------
-------------------------------------------------------------------------
4. DEBT
The Trust, through its operating subsidiaries, has a bank revolving
credit facility of $69,900,000 at June 30, 2008 (December 31, 2007 -
$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 $355,000 (December 31, 2007 -
$355,000) were issued at June 30, 2008. 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. Cash interest paid during the six month periods ended June 30,
2008 and 2007 for these loans was $1,499,000 and $1,441,000,
respectively.
5. TAXES
The Trust has recorded a future income tax liability and a current income
tax asset related to assets and liabilities and related tax amounts:
June 30, December 31,
($000) 2008 2007
-------------------------------------------------------------------------
Future income tax liability related to assets
and liabilities: 12,584 11,517
Future tax asset related to finance costs: (46) (79)
Future tax asset related to corporate tax losses
carried forward in the subsidiary companies (1,797) (3,843)
-------------------------------------------------------------------------
Future income tax liability 10,741 7,595
-------------------------------------------------------------------------
Future income tax asset related to current portion
of derivative liability 2,986 913
-------------------------------------------------------------------------
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
($000) % Amount
-------------------------------------------------------------------------
Undepreciated capital costs 20-100 16,899
Canadian oil and gas property
expenditures 10 1,620
Canadian development expenditures 30 30,651
Canadian exploration expenditures 100 93
Income tax losses carried forward(1) 100 7,084
-------------------------------------------------------------------------
56,347
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Income tax losses carried forward expire in 2026 ($215,000) and 2027
($6,869,000).
The Trust has the following tax pools, which may be used in reducing
future taxable income allocated to its Unitholders:
Rate of Utilization
($000) % Amount
-------------------------------------------------------------------------
Canadian oil and gas property
expenditures 10 13,555
Finance costs 20 195
Eligible capital expenditures 7 336
-------------------------------------------------------------------------
14,086
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 tax is paid on
the distributions 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. The tax rate was
subsequently lowered to 29.5 percent in 2011 and 28 percent in 2012 and
thereafter.
On February 26, 2008, the Minister of Finance announced that instead of
basing the provincial component of the trust tax rate on a flat rate of
13 percent, the provincial component will instead be based on the general
provincial corporate tax rate in each province in which the income trust
has a permanent establishment. Under the proposal, the Trust would be
considered to have a permanent establishment in Alberta, where the
provincial tax rate in 2011 is expected to be 10 percent. This would
result in an overall tax rate to the Trust of 26.5 percent in 2011 and
25 percent thereafter.
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 reversals of these temporary differences
at the above mentioned tax rates. 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, 2008, the Trust has
estimated the amount of its temporary differences which are estimated to
reverse post 2010 will be $14,303,000 (December 31, 2007 - $14,496,000)
resulting in an additional $4,022,000 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.
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 ($000)
Balance, January 1, 2008 16,928,158 90,590
Issued pursuant to Trust's unit option plan 179,000 4,490
Transfer of contributed surplus to unit capital - 449
-------------------------------------------------------------------------
Balance, June 30, 2008 17,107,158 95,528
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The number of trust units used to calculate diluted net earnings per unit
for the period ended June 30:
Three Months Six Months
2008 2007 2008 2007
-------------------------------------------------------------------------
Basic units
outstanding 17,025,803 16,911,916 16,982,068 16,905,494
Dilutive effect of
unit options 185,533 50,735 102,363 32,600
-------------------------------------------------------------------------
Diluted units
outstanding 17,211,336 16,962,651 17,084,431 16,938,094
-------------------------------------------------------------------------
The deficit balance is composed of the following items:
June 30, June 30,
($000) 2008 2007
-------------------------------------------------------------------------
Accumulated earnings 176,472 135,439
Accumulated cash distributions (230,509) (178,239)
-------------------------------------------------------------------------
Deficit (54,037) (42,800)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The Trust provides an option plan for its directors, officers, employees
and consultants. Under the plan, the Trust may grant options for up to
1,710,700 (December 31, 2007 - 1,693,000) 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,
2008 and December 31, 2007, and changes during the six month and
twelve month periods ended on those dates is presented below:
June 30, 2008 December 31, 2007
-------------------------------------------------------------------------
Weighted- Weighted-
Average Average
Exercise Exercise
Options Price Options Price
-------------------------------------------------------------------------
Outstanding at
beginning of period 1,177,000 $27.59 721,500 $26.55
Options granted 29,000 39.09 553,000 28.11
Options exercised (179,000) 25.09 (53,500) 18.56
Options cancelled - - (44,000) 27.92
-------------------------------------------------------------------------
Outstanding at end
of period 1,027,000 $28.35 1,177,000 $27.59
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Options exercisable
at end of period 408,500 $27.48 530,000 $26.63
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The following table summarizes information about unit options outstanding
at June 30, 2008:
Options Outstanding Options Exercisable
---------------------------------- ----------------------
Weighted-
Average Weighted- Weighted-
Range of Number Remaining Average Number Average
Exercise Outstanding Contractual Exercise Exercisable Exercise
Prices At 6/30/08 Life Price At 6/30/08 Price
-------------------------------------------------------------------------
$23.35 113,500 0.7 years $23.35 113,500 $23.35
24.20-27.50 19,500 1.9 years 25.65 - -
28.30-28.75 825,000 1.3 years 28.47 275,000 28.75
32.00-33.75 40,000 1.4 years 33.55 20,000 33.55
38.80-39.20 29,000 2.6 years 39.09 - -
-------------------------------------------------------------------------
$23.35-$39.20 1,027,000 1.3 years $28.35 408,500 $27.48
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The Trust records compensation expense over the vesting period based on
the fair value of options granted to employees, directors and
consultants. The Trust granted 29,000 unit options with an estimated fair
value of $115,000 ($3.95 per option) in 2008 and 553,000 unit options in
2007 with an estimated fair value of $1,494,000 ($2.70 per option) using
the Black-Scholes option pricing model with the following key
assumptions:
2008 2007
-------------------------------------------------------------------------
Weighted-average risk free interest rate (%) 2.9 4.7
Expected life (years) 2.5 2.3
Weighted-average volatility (%) 29.2 27.2
Dividend yield based on the percentage of
distributions paid to the Unitholders
during the period
7. ACCUMULATED OTHER COMPREHENSIVE INCOME
Other
January 1, Comprehensive June 30,
($000) 2008 Income (Loss) 2008
-------------------------------------------------------------------------
Unrealized gains (losses) on
available-for-sale financial assets 3,031 (164) 2,867
-------------------------------------------------------------------------
Other December
January 1, Comprehensive 31,
($000) 2007 Income 2007
-------------------------------------------------------------------------
Unrealized gains on
available-for-sale financial assets 1,566 1,465 3,031
-------------------------------------------------------------------------
8. RELATED PARTY TRANSACTIONS
The Trust received a management fee from Comaplex of $165,000 (2007 -
$150,000) for management services and office administration. This fee has
been included as a recovery in general and administrative expenses. As at
June 30, 2008, the Trust had an account receivable from Comaplex of
$63,000 (December 31, 2007 - $63,000).
The Trust received a management fee from Pine Cliff Energy Ltd. (Pine
Cliff) of $119,000 (2007 - $108,000) for management services and office
administration. This fee has been included as a recovery in general and
administrative expenses. As at June 30, 2008 the Trust had an account
receivable from Pine Cliff of $1,000 (December 31, 2007 - $4,000).
The above charges represent the agreed to exchange amount of the services
rendered.
9. FINANCIAL AND CAPITAL RISK MANAGEMENT
Financial Risk Factors
----------------------
The Trust undertakes transactions in a range of financial instruments
including:
- Receivables;
- Payables;
- Common share investments
- Bank loans
- Derivatives
The Trust's activities result in exposure to a number of financial risks
including market risk (commodity price risk, interest rate risk, foreign
exchange risk, credit risk, and liquidity risk).
Bonterra's overall risk management program seeks to mitigate these risks
and reduce the volatility on the Trust's financial performance. Financial
risk management is carried out by senior management under the direction
of the Directors of Bonterra Energy Corp. (a subsidiary of the Trust).
The Trust enters into various risk management contracts in accordance
with Board approval to manage Bonterra's exposure to commodity price
fluctuations. Currently no risk management agreements are in place in
respect of interest rate risk. The Trust does not speculatively trade in
risk management contracts. The Trust's risk management contracts are
entered into to manage the risks relating to commodity prices from its
business activities.
Capital Risk Management
-----------------------
The Trust's objectives when managing capital are to safeguard the Trust's
ability to continue as a going concern, so that it can continue to
provide returns to its Unitholders and benefits for other stakeholders
and to maintain an optimal capital structure to reduce the cost of
capital. In order to maintain or adjust the capital structure, the Trust
may adjust the amount of distributions, the percentage of return of
capital or issue new units.
The Trust monitors capital on the basis of the ratio of debt to adjusted
distribution base. This ratio is calculated using each quarter end net
debt (total debt adjusted for working capital) and divided by the
annualized current quarter adjusted distribution base. For these
purposes, the Trust defines adjusted distribution base as funds provided
by operations before changes in non-cash operating working capital items
excluding gains or losses on sale of property and asset retirement
obligations.
The Trust believes that maintaining debt at or less than one year's
adjusted distribution base is an appropriate level to allow it to take
advantage in the future of either acquisition opportunities or to provide
flexibility to develop its infill oil, shallow gas and coal bed methane
potential without requiring the issuance of trust units.
Bonterra has a long-term goal to retain between 20 to 25 percent of its
adjusted distribution base to finance its capital expenditures.
The following section (a) of this note provides a summary of the Trust's
underlying economic positions as represented by the carrying values, fair
values and contractual face values of the Trust's financial assets and
financial liabilities. The Trust's debt to adjusted distribution base is
also provided.
The following section (b) addresses in more detail the key financial risk
factors that arise from the Trust's activities including its policies for
managing these risks.
The following section (c) provides details of the Trust's risk management
contracts that are used for financial risk management.
a) Financial assets, financial liabilities and debt ratio
The carrying amounts, fair value and face values of the Trust's
financial assets and liabilities are shown in Table 1.
Table 1
As at June 30, 2008 As at December 31, 2007
------------------------------------------------------------------
Carrying Fair Face Carrying Fair Face
($000) Value Value Value Value Value Value
Financial
assets
Accounts
receivable 15,412 15,412 15,441 10,575 10,575 10,595
Investments
in related
party 3,828 3,828 N/A 4,014 4,014 N/A
Financial
liabilities
Distributions
payable 5,474 5,474 5,474 3,724 3,724 3,724
Accounts
payable and
accrued
liabilities 13,967 13,967 13,967 12,291 12,291 12,291
Derivative
liability 10,110 10,110 - 3,085 3,085 -
Debt 52,980 52,980 52,980 57,422 57,422 57,422
The net debt and adjusted distribution base figures for the
three months ended June 30, 2008 and June 30, 2007 are presented
in Table 2.
Table 2
For the three month
periods ended June 30, June 30,
($000) 2008 2007
------------------------------------------------------------------
Debt 52,980 54,601
Distribution payable 5,474 -
Accounts payable and accrued liabilities 13,967 10,041
Derivative liability 10,110 -
Current assets (25,383) (15,047)
------------------------------------------------------------------
Net Debt 57,148 49,595
------------------------------------------------------------------
Cash flow from operations 20,530 13,413
Changes in non-cash operating
working capital 636 (1,979)
Asset retirement obligations settled 186 261
------------------------------------------------------------------
Adjusted Distribution Base 21,352 11,695
Annualized adjusted distribution base 85,408 46,780
------------------------------------------------------------------
Net debt to adjusted distribution base 0.67 1.06
------------------------------------------------------------------
b) Risks and mitigations
Market risk is the risk that the fair value or future cash flow of
the Trust's financial instruments will fluctuate because of
changes in market prices. Components of market risk to which
Bonterra is exposed are discussed below.
Commodity price risk
--------------------
The Trust's principal operation is the production and sale of
crude oil, natural gas and natural gas liquids. Fluctuations in
prices of these commodities directly impact the Trust's
performance and ability to continue with its distributions.
The Trust currently uses various risk management contracts to set
price parameters for a portion of its production (see section c
below). Management, in agreement with the Board of Directors,
recently decided that at least in the near term it will
discontinue the use of commodity price agreements. The Trust will
assume full risk in respect of commodity prices.
Sensitivity Analysis
Commodity prices have fluctuated significantly over the recent
past. The following table updates the cash flow sensitivity for
movements in the commodity prices of $1 U.S. WTI for crude oil,
$0.10 per MCF AECO for natural gas and $0.01 fluctuation in
exchange rates. These figures have been updated from December 31,
2007 to include commodity price hedges entered into during the
first half of 2008.
Cash Flow
------------------------------------------------------------------
U.S. $1.00 per barrel $ 692,000
Canadian $0.10 per MCF $ 181,000
Change of Canadian $0.01/U.S. $ exchange rate $ 587,000
------------------------------------------------------------------
Interest rate risk
------------------
Interest rate risk refers to the risk that the value of a
financial instrument or cash flows associated with the instrument
will fluctuate due to changes in market interest rates. Interest
rate risk arises from interest bearing financial assets and
liabilities that Bonterra uses. The principal exposure of the
Trust is on its bank borrowings which have a variable interest
rate which gives rise to a cash flow interest rate risk.
Bonterra's debt consists of an operating line as well as
borrowings by means of banker acceptances (BA's). The Trust
manages its exposure to interest rate risk through entering into
various term lengths on its BA's but in no circumstances do the
terms exceed six months. As discussed above, the Trust manages its
capital such that its debt to adjusted distribution base is no
higher than one year. This allows flexibility in obtaining cost
effective financing.
Sensitivity Analysis
Based on historic movements and volatilities in the interest rate
markets and management's current assessment of the financial
markets, the Trust believes that a one percent variation in the
Canadian prime interest rate is reasonably possible over a
12-month period. No income tax effect has been calculated as the
Trust remains non-taxable until January 1, 2011.
The following illustrates the annual impact of a one percent
fluctuation in the Canadian prime rate:
As at As at
June 30, 2008 December 31, 2007
-------------------------------------------------------------------------
Plus 1% Minus 1% Plus 1% Minus 1%
($000) Earnings Equity Earnings Equity Earnings Equity Earnings Equity
Financial
assets
---------
Accounts
receivable - - - - - - - -
Investments
in related
party - - - - - - - -
Financial
liabilities
------------
Distribution
payable - - - - - - - -
Accounts
payable and
accrued
liabilities - - - - - - - -
Derivative
liability - - - - - - - -
Debt (530) (530) 530 530 (574) (574) 574 574
-------------------------------------------------------------------------
Total
increase
(decrease) (530) (530) 530 530 (574) (574) 574 574
-------------------------------------------------------------------------
Foreign exchange risk
---------------------
The Trust has no foreign operations and currently sells all its
product sales in Canadian currency. The Trust however is exposed
to currency risk in that crude oil is priced in U.S. currency then
converted to Canadian currency. Bonterra mitigates some of this
risk by using risk management contracts for a portion of its crude
oil production in Canadian dollars. Please refer to sensitivity
analysis under commodity price risk as well as section "c" below
for a list of currently outstanding risk management agreements.
Management, in agreement with the Board of Directors, recently
decided that at least in the near term it will discontinue the use
of commodity price agreements. The Trust will assume full risk in
respect of foreign exchange fluctuations.
Credit risk
-----------
Credit risk is the risk that a contracting party will not complete
its obligations under a financial instrument and cause the Trust
to incur a financial loss. Bonterra is exposed to credit risk on
all financial assets included on the balance sheet. To help
mitigate this risk:
- The Trust only enters into material agreements with credit
worthy counterparties. These include major oil and gas
companies or one of the major Canadian chartered banks.
- Agreements for product sales are primarily on 30 day renewal
terms.
- Investments are only with companies that have common
management with the Trust.
Of the accounts receivable balance of June 30, 2008 ($15,412,000)
and December 31, 2007 ($10,575,000) over 90 percent relates to
product sales with international oil and gas companies. All of the
derivative contracts as of both June 30, 2008 and December 31,
2007 were with either Bonterra's principal banker or its major
crude oil purchaser.
The Trust assesses quarterly, if there has been any impairment of
the financial assets of the Trust. During the three month period
ended June 30, 2008 there was no impairment provision required on
any of the financial assets of the Trust due to historical success
of collecting receivables. The Trust does have a credit risk
exposure as the majority of the Trust's accounts receivable are
with counterparties having similar characteristics. However,
payments from the Trust's largest accounts receivable counter
parties have always been received within 30 days and the sales
agreements with these parties are cancellable with 30 days notice
if payments are not received.
The carrying value of accounts receivable approximates their fair
value due to the relatively short periods to maturity on this
instrument. The maximum exposure to credit risk is represented by
the carrying amount on the balance sheet. There are no material
financial assets that the Trust considers past due.
Liquidity risk
--------------
Liquidity risk includes the risk that, as a result of Bonterra's
operational liquidity requirements:
- The Trust will not have sufficient funds to settle a
transaction on the due date,
- Bonterra will not have sufficient funds to continue with its
distributions,
- The Trust will be forced to sell assets at a value which is
less than what they are worth, or
- Bonterra may be unable to settle or recover a financial
asset at all.
To help reduce these risks the Trust:
- Has a capital policy of maintaining no more than a one year
debt to adjusted distribution base.
- Uses of derivative instruments that are readily tradable
should the need arise.
- Maintains a portfolio of high-quality long reserve life oil
and gas assets.
c) Risk management contracts
The Trust entered into the following commodity hedging contracts
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
July 1, 2008 to
December 31, 2008 Crude Oil 500 barrels WTI Floor of $85.00
and ceiling of
$104.80 per
barrel
April 1, 2008 to
October 31, 2008 Natural Gas 1,500 GJ's AECO Floor of $6.00
and ceiling of
$7.60 per GJ
As of June 30, 2008, the fair value of the outstanding commodity risk
management contracts was a net liability of $10,110,000 (December 31,
2007 - $3,085,000).
10. UNREALIZED LOSS ON RISK MANAGEMENT CONTRACTS
The following table reconciles the movement in the fair value of the
Trust's financial risk management contracts that have not been designated
as effect accounting hedges for the periods ended June 30:
Three Months Six Months
($000) 2008 2007 2008 2007
-------------------------------------------------------------------------
Fair Value, beginning
of period (5,474) (603) (3,085) 1,149
Fair Value, end of period (10,110) 710 (10,110) 710
-------------------------------------------------------------------------
Unrealized loss on risk
management contracts (4,636) 1,313 (7,025) (439)
-------------------------------------------------------------------------
11. RESTATEMENT
The Trust has determined that its cash flow hedges on commodities are no
longer effective hedges for accounting purposes. The following financial
statement items have been restated to eliminate the use of hedge
accounting:
Three months ended June 30, 2007
($000 except $ per unit) Reported Adjustment Restated
-------------------------------------------------------------------------
Unrealized gain (loss) on risk
management contracts - 1,313 1,313
Future tax expense 3,777 382 4,159
Net earnings for the period 4,440 931 5,371
Deficit at beginning of period (35,767) (1,242) (37,009)
Deficit at end of period (42,489) (311) (42,800)
Net earnings per unit (basic and
diluted) 0.26 0.06 0.32
Other comprehensive income 577 (931) (354)
-------------------------------------------------------------------------
Six months ended June 30, 2007
($000 except $ per unit) Reported Adjustment Restated
-------------------------------------------------------------------------
Unrealized loss on risk
management contracts - (439) (439)
Future tax expense 3,815 (128) 3,687
Net earnings for the period 13,344 (311) 13,033
Deficit at end of period (42,489) (311) (42,800)
Net earnings per unit
(basic and diluted) 0.79 (0.02) 0.77
Other comprehensive income 317 311 628
-------------------------------------------------------------------------
12. SUBSEQUENT EVENT - DISTRIBUTION
Subsequent to June 30, 2008, the Trust declared distributions of
$0.32 per unit payable on August 31, 2008 to Unitholders of record on
August 15, 2008.%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