Bonterra Energy Income Trust Announces Fourth Quarter and Annual Results
CALGARY, March 27 /CNW/ - Bonterra Energy Income Trust
(www.bonterraenergy.com) (TSX:BNE.UN) is pleased to announce its financial and
operational results for the three months and fiscal year ended December 31,
2006.HIGHLIGHTS
- Gross proved reserves total 20,518,000 BOE's(1) resulting in a
reserve life(2) of approximately 13.6 years. Gross proven plus
probable reserves total 26,476,000 BOE's for a 17.6 year reserve
life.
- Funds flow(3) per fully diluted unit increased to $3.12 per unit from
$2.69 with distributions totaling $2.82 per unit in 2006 compared to
$2.37 per unit in 2005.
- Net Earnings per fully diluted unit increased to $2.21 per unit in
2005 from $2.01 per unit in 2005.
(1) 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.
(2) The reserve life index is calculated by dividing the reserves (in
BOE's) by the annualized fourth quarter average production rate in BOE/d
(2005 - 3,780).
(3) 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.
FINANCIAL AND OPERATIONAL SUMMARY
Three Months Ended Years Ended
December 31 December 31
2006 2005 2006 2005
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Oil, Gas & NGL Sales $21,719,000 $21,753,000 $88,734,000 $75,837,000
Funds Flow $12,235,000 $12,489,000 $52,797,000 $44,579,000
Funds Flow per Unit
- basic $ 0.72 $ 0.76 $ 3.15 $ 2.72
Funds Flow per Unit
- diluted $ 0.72 $ 0.76 $ 3.12 $ 2.69
Net Earnings $ 6,471,000 $ 9,918,000 $37,250,000 $33,468,000
Net Earnings per Unit
- basic $ 0.39 $ 0.59 $ 2.23 $ 2.04
Net Earnings per Unit
- diluted $ 0.38 $ 0.58 $ 2.21 $ 2.01
Distributions
per Unit $ 0.72 $ 0.68 $ 2.82 $ 2.37
Units outstanding 16,874,658 16,535,158
Daily Oil and NGL
Production (Bbls) 3,138 2,814 3,040 2,713
Daily Gas
Production (MCF) 5,885 5,795 6,014 5,650
Daily BOE (6:1) 4,119 3,780 4,042 3,655
Average Liquid Price
($/Bbl) $ 60.79 $ 61.13 $ 64.69 $ 58.30
Average Gas Price
($/MCF) $ 7.57 $ 11.16 $ 7.55 $ 8.64
Average BOE Price
($/BOE) $ 57.32 $ 62.55 $ 60.13 $ 56.85
Net Back per BOE $ 32.21 $ 35.36 $ 35.04 $ 32.86ENGINEERING SUMMARY
The Trust engaged the services of Sproule Associates Limited to prepare a
reserve evaluation with an effective date of December 31, 2006. The reserves
are located in the Provinces of Alberta and Saskatchewan. The Trust's main oil
producing areas are located in the Pembina area of Alberta, and Dodsland and
Shaunavon areas of Saskatchewan. The gross reserve figure for the following
charts represents the Trust's ownership interest before royalties and the net
figure is after deductions for royalties.SUMMARY OF OIL AND GAS RESERVES AS OF DECEMBER 31, 2006
(FORECAST PRICES AND COSTS)
RESERVES
Light and Natural Natural Gas
Medium Oil Gas Liquids
Gross Net Gross Net Gross Net
RESERVE CATEGORY (Mbbl) (Mbbl) (MMcf) (MMcf) (Mbbl) (Mbbl)
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PROVED
Developed Producing 12,934 12,269 17,011 12,675 754 536
Developed
Non-Producing 391 389 2,962 2,283 27 19
Undeveloped 2,553 2,319 2,589 1,813 99 70
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TOTAL PROVED 15,878 14,977 22,562 16,771 880 625
PROBABLE 4,522 4,256 7,138 5,339 246 175
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TOTAL PROVED PLUS
PROBABLE 20,400 19,233 29,700 22,110 1,126 800
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RECONCILIATION OF TRUST GROSS RESERVES
BY PRINCIPAL PRODUCT TYPE (FORECAST PRICES AND COSTS)
Light, Medium
Oil and NGL's Natural Gas
Gross Gross
Gross Gross Proved Gross Gross Proved
Proved Probable Plus Proved Probable Plus
(Mbbl) (Mbbl) Probable (Mbbl) (Mbbl) Probable
(Mbbl) (Mbbl)
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December 31, 2005 15,662 3,944 19,606 20,473 5,110 25,583
Extension 10 - 10 920 - 920
Improved recovery 1,655 643 2,298 2,687 639 3,326
Technical revisions 564 197 761 583 1,223 1,806
Discoveries 1 2 3 116 172 288
Acquisitions 16 - 16 - - -
Dispositions (40) (18) (58) (11) (5) (16)
Production (1,110) - (1,110) (2,206) - (2,206)
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December 31, 2006 16,758 4,768 21,526 22,562 7,139 29,701
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SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE
AS OF DECEMBER 31, 2006 (FORECAST PRICES AND COSTS)
NET PRESENT VALUE OF FUTURE NET REVENUE
Before and After Income Taxes
Discounted at (%/year)
0 5 10 15 20
(M$)
RESERVE CATEGORY
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PROVED
Developed Producing 569,022 363,050 271,893 221,685 189,765
Developed Non-Producing 27,731 19,068 15,479 13,444 12,069
Undeveloped 46,070 34,813 26,120 19,332 13,971
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TOTAL PROVED 642,823 416,931 313,492 254,461 215,805
PROBABLE 242,903 103,837 62,670 44,553 34,337
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TOTAL PROVED PLUS PROBABLE 885,726 520,768 376,162 299,014 250,142
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Commodity prices used in the above calculations of reserves are as
follows:
Year Edmonton Alberta Gas Propane Butane Pentane
Par Price Reference
Price
Plantgate
(Cdn $ (Cdn $ (Cdn $ (Cdn $ (Cdn $
per barrel) per MCF) per barrel) per barrel) per barrel)
-------------------------------------------------------------------------
2007 74.10 7.51 43.94 55.23 75.88
2008 77.62 8.38 46.03 57.85 79.49
2009 70.25 7.55 41.66 52.36 71.94
2010 65.56 7.37 38.88 48.87 67.14
2011 61.90 7.54 36.71 46.14 63.40
2012 63.15 7.68 37.45 47.07 64.67
2013 64.42 7.79 38.21 48.02 65.98
2014 65.72 7.93 38.97 48.98 67.30
2015 67.04 8.07 39.76 49.97 68.66
2016 68.39 8.21 40.56 50.97 70.04
2017 69.76 8.54 41.38 52.00 71.45
Crude oil, natural gas and liquid prices escalate at 2% per year
thereafter.
The following cautionary statements are specifically required by NI 51-101
- It should not be assumed that the estimates of future net revenue
presented in the above tables represent the fair market value of the
reserves. There is no assurance that the forecast prices and costs
assumptions will be attained and variances could be material.
- Disclosure provided herein in respect of BOE's may be misleading,
particularly if used in isolation. In accordance with NI 51-101, a
BOE conversion ratio of 6mcf:1bbl has been used in all cases in this
disclosure. This BOE conversion ratio is based on an energy
equivalency conversion method primarily applicable at the burner tip
and does not represent a value equivalency at the wellhead.
- Estimates of reserves and future net revenues for individual
properties may not reflect the same confidence level as estimates of
reserves and future net revenues for all properties due to the
effects of aggregation.A DISCUSSION OF FINANCIAL AND OPERATIONAL RESULTS
Production
The Trust's 2006 average production of oil and natural gas liquids was
3,040 (2005 - 2,713) barrels per day and natural gas production in 2006
averaged 6,014 (2005 - 5,650) MCF per day. Oil production increased by
approximately 12 percent while gas production increased by approximately
6 percent. The increases were predominantly due to the Trusts 2005 and 2006
development programs. The Trust's fourth quarter production saw increases in
both crude oil and natural gas production due to commencement of production
from new wells drilled in 2006.
The Trust's overall annual decline rate for 2006 is approximately
nine percent which the Trust was able to more than offset with its 2006 drill
program. The Trust, along with its partners, drilled 43 gross (30.3 net)
Cardium oil wells. This includes 34 gross and 29 net Cardium wells drilled
directly by the Trust. Also the Trust drilled 18 gross (15.3 net) shallow gas
wells in 2006. The Trust experienced a 100 percent success rate with its and
its partners Cardium drilling program. The drilling of the shallow gas wells
resulted in 11 successful (8.3 net) and 7 gross and net wells that have been
determined to be uneconomic. The expenditures to drill these uneconomic wells
totalled $2,919,000 which has been written off as dry hole costs.
As at December 31, 2006 Bonterra had 21 gross (11.4 net) Cardium oil
wells (including 9 gross, 1.3 net on non operated lands), 12 gross (9.3 net)
natural gas wells and 7 gross (5.5 net) coal-bed wells drilled but not on
production. During the fourth quarter the Trust tied-in 11 gross (10.4 net)
Cardium wells and 1 gross (1 net) natural gas well on its operated lands.
Subsequent to December 31, 2006 and up to the date of this report,
Bonterra has put on production 6 gross (5.8 net) of its operated Cardium oil
wells and 2 gross (1 net) shallow gas wells. Most of the 9 gross (1.3 net)
wells on non-operated lands also have been completed in Q1, 2007. The Trust is
currently completing several of its Edmonton sand gas wells drilled in 2006
and anticipates that the majority of the gas wells will be on production by
the end of the second quarter of 2007. Bonterra is waiting on final regulatory
decisions and recovery in natural gas pricing prior to commencing further
completion work on the coal-bed methane wells.
Revenue
Gross revenue from petroleum and natural gas sales prior to royalties was
$88,734,000 (2005 - $75,837,000). The increase of $12,897,000 was due to
increased production volumes and an increase in the average price received for
crude oil offset partially by a 12.6 percent decline in the average price of
natural gas. The price received for crude oil increased to $64.69 per barrel
in 2006 from $58.30 per barrel in 2005 while natural gas prices decreased to
$7.55 per MCF in 2006 from $8.64 per MCF in 2005. Part of the increase in
average price of crude oil was the increased production related to the Trust's
light sweet crude production in the Pembina area of Alberta which receives a
higher price per barrel. The mix of light crude to mid grade crude has
increased to 87 percent of the Trust's crude oil production in 2006 from
85 percent in 2005
The fourth quarter saw a decrease in gross revenues of $1,946,000 over
quarter three due primarily to decreased crude oil prices. The average price
received in the fourth quarter for crude oil and natural gas liquids was
$60.79 ($71.11 third quarter) per barrel and $7.57 ($6.95 third quarter) per
MCF for natural gas.
Gross revenue has been reduced by $62,000 (2005 - $4,054,000) due to
lower prices received as a result of price hedging. The Trust will continue to
hedge future production (see Business Prospects, Risks, and Outlooks) to
assist in managing its cash 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 cash 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.
Commodity price hedges outstanding as of the date of this report are as
follows:Volume
Period of Agreement Commodity per day Index Price (Cdn.)
------------------- --------- ------- ----- ------------
January 1, 2007 Crude Oil 500 barrels WTI Floor of $74.55
to June 30, 2007 and ceiling of
$85.00 per
barrel
January 1, 2007 Crude Oil 500 barrels WTI Floor of $75.00
to 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
November 1, 2006 Natural Gas 2,000 GJ's AECO Floor of $6.65
to March 31, 2007 and ceiling of
$12.50 per GJ
December 1, 2006 Natural Gas 1,500 GJ's AECO Floor of $6.00
to March 31, 2007 and ceiling of
$9.65 per GJ
April 1, 2007 Natural Gas 2,000 GJ's AECO $6.52 per GJ
to 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 Natural Gas 2,000 GJ's AECO Floor of $6.50
to March 31, 2008 and Ceiling of
$10.37 per GJAs of December 31, 2006 the fair value of the outstanding commodity
hedging contracts was a net asset of $1,189,000 compared to a net liability of
$1,349,000 as of December 31, 2005.
Royalties
Royalties paid by the Trust consist primarily of Crown royalties paid to
the Provinces of Alberta and Saskatchewan. During 2006 the Trust paid
$8,516,000 (2005 - $6,986,000) in Crown royalties and $1,996,000 (2005 -
$2,009,000) 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 (2005 - nine percent) and approximately
two percent (2005 - three percent) for other royalties before hedging
adjustments. Crown royalty rates vary with production volumes and as such the
crown rates are higher on the Trust's newly drilled wells. 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 number of purchased
wells. Effective January 1, 2007, the Alberta Government discontinued the
rebate.
Gain on Sale of Property
The Trust disposed of its interests in a non-core, non-operated property
on January 1, 2006 for proceeds of $750,000 resulting in a gain on sale of
$532,000. Production from this property averaged ten barrels per day in 2005.
On April 8, 2005, a former subsidiary of Novitas Energy Ltd. ("Novitas") (a
subsidiary of the Trust), Pine Cliff Energy Ltd.'s (Pine Cliff) (with common
directors and management with Bonterra) rights offering closed with over
97 percent of former Novitas shareholders exercising their rights to acquire
common shares in Pine Cliff for $0.15 per common share. As part of the rights
offering, the Trust agreed to sell to Pine Cliff effective January 1, 2005
(closing April 9, 2005) approximately 18 BOE per day of production and some
exploration lands formally held by Novitas for proceeds of approximately
$1,000,000. As a result of this sale the Trust reported a gain on sale of
property of $225,000. The balance of the 2005 gain of $38,000 relates to a
disposition of an interest in another non-core area property.
Production Costs
Production costs totalled $22,238,000 in 2006 compared to $20,203,000 in
2005. On a barrel of oil equivalent (BOE) basis 2006 operating costs were
$15.07 compared to $15.14 for 2005. 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. Operating costs on the Trust's newly drilled
wells are significantly lower on a BOE basis than on its older low
productivity wells and has resulted in the Trust being able to maintain its
operating costs to BOE rate even though the oil and gas industry saw double
digit rates of inflation on its well service costs.
Operating costs were $5,997,000 in the fourth quarter of 2006 compared to
$5,689,000 in the third quarter. The increase was due primarily to a $241,000
charge related to an unsuccessful insurance claim relating to a 2005 oil
spill.
As discussed above, the Trust's production comes primarily from low
productivity wells. These wells generally result in higher operating 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 Trust is continually examining means of reducing operating costs.
Operating costs in the $14 to $15 per BOE range are expected for 2007. The
high operating 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 operating costs.
General and Administrative Expense
General and administrative expenses were $2,295,000 in 2006 compared to
$2,420,000 in 2005. On a BOE basis, general and administrative expenses in
2006 averaged $1.56 compared to $1.81 per BOE in 2005. The Trust is managed
internally. In addition, the Trust provides administrative services to
Comaplex Minerals Corp. (Comaplex) and Pine Cliff, companies that share common
directors and management. Please refer to discussion under Related Party
Transactions for details.
The Trust's only significant general and administrative cost increase was
in employee compensation. The Trust has an employee incentive plan equal to
three percent of net earnings before taxes. In 2006 net earnings before taxes
increased to $36,864,000 from $33,548,000 in 2005 resulting in an additional
$100,000 of employee compensation expense. In addition, the Trust added
additional staff to assist with its enhanced capital programs. The additional
employee compensation has been offset by higher intercompany charges and
increased overhead recoveries charged to operations and capital programs.
The fourth quarter general and administrative expenses were $89,000 lower
than the third quarter. The decrease was primarily due to the reduction in the
Trust's employee bonus amount resulting from the provision of $2,919,000 in
dry hole costs.
Interest Expense
Interest expense for the 2006 fiscal year of the Trust was $1,610,000
(2005 - $575,000). The increase was due to increased loan balances resulting
from the Trust's 2006 capital program. The Trust incurred $38,348,000 in
capital development expenditures in 2006 resulting in an increase of
$25,202,000 in outstanding debt.
Interest rate charges during the year on the outstanding debt averaged
approximately 5.3 (2005 - 4.7) percent. The Trust maintained an average
outstanding debt balance of approximately $31,000,000 (2005 - $12,250,000).
Total debt (including negative working capital) as of December 31, 2006
represents approximately 11.5 months of 2006 annual funds flow or 12.3 months
based on annualized 2006 fourth quarter funds flow.
The Trust believes that maintaining debt at or less than one year's funds
flow (calculated quarterly based on annualized quarterly results) 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 natural gas from coals potential without requiring the
issuance of trust units. The Trust's December 31, 2006 debt level is slightly
higher than this level. A significant decrease in the fourth quarter price of
crude oil coupled with the Trust increasing its 2006 capital program, resulted
in higher debt levels and lower funds flow for the quarter. A large number of
wells drilled in 2006 were not tied in for production until the fourth quarter
of 2006 or in 2007 and therefore contributed little or no cash flow to reduce
debt.
The Trust's current bank agreements (each of Bonterra Energy Corp,
Comstate Resources Ltd. and Novitas have their own) provide for a combined
$49,900,000 (January 1, 2007 - $59,900,000) of available credit facility. Bank
debt at December 31, 2006 was $45,379,000 (December 31, 2005 - $20,177,000).
The interest rate charged on all non Banker Acceptances (BA's) facility
borrowings is bank prime. The Trust's banking arrangements allow it to use
BA's as part of its loan facility. Interest charges on BA's are generally one
half percent lower than that charged on the general loan account.
Unit Based Compensation
The Trust is required to record a compensation expense over the vesting
period of its unit options based on the fair value of the unit options granted
to employees, directors and consultants. During the year 447,000 (2005 -
407,000) unit options were granted with a fair value of $2.67 per unit (2005 -
$2.49). The fair value of options granted has been estimated using the
Black-Scholes option pricing model, assuming a weighted risk free interest
rate of 4.1 (2005 - 3.5) percent, expected weighted average volatility of 27
(2005 - 31) percent, expected weighted average life of 2.5 (2005 - 2.5) years
and an annual dividend rate based on the distributions paid to the Unitholders
during the year. The result of applying the above, a total unit based
compensation of $734,000, based on currently issued and outstanding options,
is required to be recorded over the years 2007 and 2008.
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.
For tangible assets such as well equipment, a life span of ten years is
estimated and the related tangible costs are depreciated at one tenth of
original cost per year. The use of a ten year life span instead of calculating
depreciation over the life of reserves was determined to be more
representative of actual costs of tangible property. Given the Trust's long
production life, wells generally require replacement of tangible assets more
than once during their life time. Most of the Trust's wells have been
producing since the 1960's and are expected to continue to produce for at
least another twenty years.
Provisions are made for asset retirement obligations through the
recognition of the fair value of obligations associated with the retirement of
tangible long-life assets being recorded in the period the asset is put into
use, with a corresponding increase to the carrying amount of the related
asset. The obligations recognized are statutory, contractual or legal
obligations. The liability is adjusted over time for changes in the value of
the liability through accretion charges which are included in depletion,
depreciation and accretion expense. The costs capitalized to the related
assets are amortized to earnings in a manner consistent with the depletion and
depreciation of the underlying asset.
At December 31, 2006, the estimated total undiscounted amount required to
settle the asset retirement obligations was $46,434,000 (2005 - $39,921,000).
Of the $6,513,000 increase, approximately $2 million is due to the increased
number of wells resulting from the Trust's 2006 capital program, with the
balance resulting from increased inflation assumptions.
These obligations will be settled based on the useful lives of the
underlying assets, which extend up to 40 years into the future. This amount
has been discounted using a credit-adjusted risk-free interest rate of
five percent. The discount rate is reviewed annually and adjusted if
considered necessary. A change in the rate would have a significant impact on
the amount recorded for asset retirement obligations. Based on the current
provision, a one percent increase in the risk adjusted rate would decrease the
asset retirement obligation by $2,263,000. While a one percent decrease in the
risk adjusted rate would increase the asset retirement obligation by
$2,989,000.
The above calculation requires an estimation of the amount of the Trust's
petroleum reserves by field. This figure is calculated annually by an
independent engineering firm and is used to calculate depletion. This
calculation is to a large extent subjective. Reserve adjustments are affected
by economic assumptions as well as estimates of petroleum products in place
and methods of recovering those reserves. To the extent reserves are increased
or decreased, depletion costs will vary.
For the fiscal year ending December 31, 2006, the Trust expensed
$15,393,000 (2005 - $10,358,000) for the above-described items including
$2,919,000 (2005 - $628,000) for dry hole costs. The increase of $2,744,000
(excluding dry hole costs) over the 2005 balance is due primarily to increased
2006 production levels. The Trust has experienced increased finding and
development costs over the past two years (see Finding and Development Costs
below). This has resulted in a higher depletion per barrel as production from
the 2005/2006 wells make up a larger component of overall production. Based on
year end reserves, the Trusts average cost of proved reserves is $5.95 (2005 -
$5.08) per BOE.
The dry hole cost of $2,919,000 relates to seven shallow gas wells that
were drilled in the winter and summer of 2006. Five of these wells were
drilled pursuant to a farm-in agreement where Bonterra was committed to
drilling and completing a certain number of wells in order to earn in on the
entire land area. In total 12 wells (nine by the end of August) were drilled
and completed on the farm in lands in 2006. A further two were drilled in
January 2007 to complete the required wells per the farm-in agreements. The
wells were designed to test the productivity of the Edmonton Sands shallow gas
potential in two separate townships.
The Trust currently has an estimated reserve life for its proved
developed producing reserves of 11.0 (2005 - 12.1) years calculated using the
Trust's gross reserves (prior to allowance for royalties) based on the third
party engineering report dated December 31, 2006 and using fourth quarter 2006
average production rates of 4,119 BOE's (2005 - 3,780 BOE's). Based on total
proved reserves the Trust has a 13.6 (2005 - 13.8) year reserve life and if
proved and probable are used the reserve life increases to 17.6 (2005 - 17.3)
years. These figures are some of the longest (excluding oil sands) reserve
life indexes in the Trust sector.
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. Please see
discussion under Taxation of Trusts for discussion relating to the newly
announced taxation of trusts. However, the Trust operates its oil and gas
interests through its 100 percent owned subsidiaries Bonterra Energy Corp.
(Bonterra Corp.), Comstate Resources Ltd. (Comstate Ltd.) and Novitas.
Effective January 1, 2007 the Trust amalgamated Comstate Ltd. and Bonterra
Corp. All operating companies pay the majority of their income to the Trust
through interest and royalty payments which are deductible for income tax
purposes. For the taxation periods ending prior to 2004 Bonterra Corp. and
Comstate Ltd. both paid to the Trust sufficient royalty and interest payments
to eliminate all their taxable income. During 2004, due to timing of capital
expenditures and other funds flow factors, Comstate Ltd. was unable to pay
sufficient payments to the Trust to eliminate all of its taxable income and
paid taxes of approximately $560,000. Comstate Ltd. was able to obtain a full
refund of the 2004 taxes in 2005.
The Province of Saskatchewan levies a resource surcharge on all oil and
gas produced in the province. This surcharge applies if an individual company
exceeds a minimum capital threshold or where there are related companies a
combined asset threshold also applies. Both Bonterra Corp. and Comstate Ltd.
both exceeded the individual company threshold in 2006 and are now subject to
the surcharge. The Trust recorded a tax expense of $367,000 in relation to the
surcharge. Novitas may be subject to the surcharge by 2007 due to the
continued combined growth of the Trust's subsidiaries. Based on the Trust's
2006 revenues, from oil and gas production in the Province of Saskatchewan,
and if all operating companies had exceeded the combined asset threshold a
total tax expense of $617,000 would have been recorded.
Future tax provision relates to the future taxes that exist within
Bonterra Corp., Comstate Ltd. and Novitas. The liability on the balance sheet
and the corresponding income recovery relates to temporary differences
existing between Bonterra Corp's., Comstate Ltd.'s and Novitas' book value of
its assets and its remaining tax pools. Provision for future tax fluctuates
quarter over quarter depending on the timing of capital expenditures and funds
flow levels in each respective operating company.
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
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Undepreciated capital costs 20-100 $15,037,000
Canadian oil and gas property expenditures 10 1,244,000
Canadian development expenditures 30 30,581,000
Canadian exploration expenditures 100 93,000
Income tax losses carried forward(1) 100 9,035,000
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$55,990,000
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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 $15,685,000
Finance costs 20 626,000
Eligible capital expenditures 7 168,000
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$16,479,000
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The Canadian tax breakdown of distributions for the 2006 taxation year is
as follows:
Percentage
----------
Taxable Income (Other Income) 78.80
Return of Capital 21.20
----------
100.00
----------With respect to cash distributions paid during the year to U.S.
individual unitholders, 18.1 percent should be reported as a return of capital
(to the extent of the Unitholder's U.S. tax basis in their respective units)
and 81.9 percent should be reported as qualified dividends.
Net Earnings
The Trust's net earnings of $37,250,000 for the year ended December 31,
2006 represents an increase of $3,782,000 over the Trusts 2005 net earnings of
$33,468,000. The Trust recorded net earnings per unit on a fully diluted bases
in 2006 of $2.21 verses $2.01 in the 2005 year. This represents a return on
Unitholders' equity of approximately 69.8 (2005 - 58.4) percent based on year
end Unitholders' equity.
Strong commodity prices along with a 10.5 percent increase in production
volumes were the main drivers of the increased earnings. The Trust continues
to return in excess of 40 percent of its gross revenues in net earnings. The
Trust's low capital costs combined with a low debt to funds flow ratio all
contribute to the high return. Bonterra's high per unit operating costs are
more than offset with its low royalty rates resulting in one of the highest
cash net backs in the industry (see cash netback).
Funds Flow from Operations
Funds flow from operations for the year ending December 31, 2006 was
$52,797,000 compared to $44,579,000 for the year ended December 31, 2005.
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 was primarily due to higher commodity prices and higher
production volumes. As with all oil and gas producers the Trust's funds flow
is highly dependent on commodity prices.
The following reconciliation compares funds flow to the Trust's cash flow
from operations as calculated according to Canadian generally accepted
accounting principles:For the periods Three Months Twelve Months
ended December 31 2006 2005 2006 2005
-------------------------------------------------------------------------
Cash flow from
operations for the
period $11,925,000 $12,342,000 $51,944,000 $38,985,000
Items not affecting
funds flow:
Gain on sale of
property - - 532,000 263,000
Changes in accounts
receivable 1,102,000 50,000 147,000 2,814,000
Changes in crude
oil inventory (179,000) 66,000 7,000 134,000
Changes in parts
inventory 5,000 (3,000) (107,000) (170,000)
Changes in prepaid
expenses (299,000) (380,000) 305,000 (306,000)
Changes in accounts
payable and accrued
liabilities (688,000) 369,000 (793,000) 2,584,000
Asset retirement
obligations settled 369,000 45,000 762,000 275,000
-------------------------------------------------------------------------
Funds flow from
operations for
the period $12,235,000 $12,489,000 $52,797,000 $44,579,000
-------------------------------------------------------------------------
Cash Netback
The following table illustrates the Trust's cash netback:
$ per Barrel of Oil Equivalent (BOE) 2006 2005
-------------------------------------------------------------------------
Production volumes (BOE) 1,475,639 1,334,075
Gross production revenue $ 60.13 $ 56.85
Royalties (7.12) (6.74)
Field operating (15.07) (15.14)
-------------------------------------------------------------------------
Field netback 37.94 34.97
General and administrative (1.56) (1.81)
Interest and taxes (1.34) (0.30)
-------------------------------------------------------------------------
Cash netback $ 35.04 $ 32.86
-------------------------------------------------------------------------
The following table illustrates the Trust's cash netback for the three
months ended:
December 31 September 30
$ per Barrel of Oil Equivalent (BOE) 2006 2006
-------------------------------------------------------------------------
Production volumes (BOE) 378,916 369,104
Gross production revenue $ 57.32 $ 64.12
Royalties (6.37) (6.77)
Field operating (15.83) (15.41)
-------------------------------------------------------------------------
Field netback 35.12 41.94
General and administrative (1.27) (1.55)
Interest and taxes (1.64) (1.38)
-------------------------------------------------------------------------
Cash netback $ 32.21 $ 39.01
-------------------------------------------------------------------------
Finding and Development Costs (F&D Costs)
Bonterra has been active in its capital development program over the past
two years. Over this time period the Trust has incurred the following finding
and development costs:
-------------------------------------------------------------------------
2006 F&D 2005 F&D 2004 F&D 2006 Three 2005 Three
Costs per Costs per Costs per Year Year
BOE(1,2) BOE(1,2) BOE(1,2) Average Average
-------------------------------------------------------------------------
Proved Reserve
Additions $25.51 $14.86 $7.33 $15.90 $10.47
-------------------------------------------------------------------------
Proved plus
Probable Reserve
Additions $18.21 $12.33 $4.97 $11.84 $6.90
-------------------------------------------------------------------------
The above figures have been calculated in accordance with National
Instrument 51-101 (NI 51-101) where the finding and development costs equate
to the total exploration and development costs incurred by the Trust during
the year plus the yearly change in estimated future development costs as
calculated by Sproule Associates Limited. The following precautionary notes
have been provided as required by NI 51-101.
(1) BOE's may be misleading, particularly if used in isolation. A BOE
conversion ratio of 6MCF:1bbl is based on an energy equivalency
conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.
(2) The aggregate of the exploration and development costs incurred in
the most recent financial year and the change during that year in
estimated future development costs generally will not reflect total
finding and development costs related to reserve additions for that
year.Escalating development costs combined with moderate results in the Trusts
shallow gas drilling program in 2006 has resulted in a substantial increase in
2006 F&D costs. With the recent reduction in commodity prices, the Trust is
being able to negotiate lower drilling rig costs in respect of its 2007 winter
drill program.
Related Party Transactions
The Trust holds 689,682 (2005 - 689,682) common shares in Comaplex which
have a fair market value as of December 31, 2006 of $2,297,000 (2005 -
$2,448,000). Comaplex is a publically traded mineral company on the Toronto
Stock Exchange. The Trust's ownership in Comaplex represents approximately
1.7 percent of the issued and outstanding common shares of Comaplex. Bonterra
has common directors and management with Comaplex.
Comaplex paid a management fee to Comstate Ltd. of $300,000 (2005 -
$240,000). Comaplex also cost shares office rental costs and reimburses
Comstate Ltd. for costs related to employee benefits and office materials. In
addition Comaplex owns 204,633 (December 31, 2005 - 204,633) units in the
Trust. Services provided by Comstate Ltd. include executive services
(president and vice president, finance duties), accounting services, oil and
gas administration and office administration. All services performed are
charged at estimated fair value. At December 31, 2006, Comaplex owed the Trust
$38,000 (December 31, 2005 - $29,000).
The Trust also has a management agreement with Pine Cliff. Pine Cliff has
common directors and management with the Trust. Pine Cliff trades on the TSX
Venture Exchange. Pine Cliff paid a management fee to Comstate Ltd. of
$216,000 (2005 - $132,000). Services provided by Comstate Ltd. include
executive services (president and vice president, finance duties), accounting
services, oil and gas administration and office administration. All services
performed are charged at estimated fair value. The Trust has no share
ownership in Pine Cliff. There were no intercompany balances owing as of
December 31, 2006.
Commitments
The Trust has no contractual obligations that last more than a year other
than its office lease agreement which is as follows:Contract Obligations Less than 1 - 3 4 - 5 After
Total 1 year years years 5 years
-------------------------------------------------------------------------
Office lease $1,963,000 $283,000 $910,000 $656,000 $114,000
-------------------------------------------------------------------------Liquidity and Capital Resources
During 2006 the Trust participated in drilling 61 gross (45.6 net) wells
at a total cost of $38,348,000. Of these wells, 43 gross (30.3 net) were oil
wells and 18 gross (15.3 net) were natural gas wells. The Trust's operated
2006 drill program consisted of 34 gross (29 net) Cardium oil wells and 17
gross (14.7 net) natural gas wells.
As at December 31, 2006 Bonterra had 21 gross (11.4 net) Cardium oil
wells (including 9 gross, 1.3 net on non operated lands), 12 gross (9.3 net)
natural gas wells and 7 gross (5.5 net) coal-bed wells drilled but not on
production. Subsequent to December 31, 2006 and up to the date of this report,
Bonterra has put on production 6 gross (5.8 net) Cardium oil wells and 2 gross
(1 net) shallow gas wells. The Trust is currently completing several of its
Edmonton sand gas wells drilled in 2006 and anticipates that the majority of
the gas wells will be on production by the end of the second quarter of 2007.
Bonterra is waiting on final regulatory decisions and recovery in natural gas
pricing prior to commencing further completion work on the coal-bed methane
wells.
The Trust currently has plans to drill 20 gross (15 net) infill Cardium
wells and 2 gross (1.8 net) natural gas wells in 2007. Total capital costs are
anticipated to be approximately $20,000,000 for the planned development
programs and tying in of the remaining 2006 drilled wells. The Trust
anticipates funding the 2007 capital program out of current funds flow
($10-$15 million), exercising of employee unit options ($2-$3 million) and
existing lines of credit. This combination should allow for the Trust to
maintain an approximate one year debt to funds flow ratio.
The Trust is continuing with its efforts to acquire producing and non
producing properties through either property or entity acquisitions. Funding
for any acquisition would depend on items such as the type of acquisition
(entity vs. property), quality of the assets, size of the purchase and the
Trust unit trading price at the time of the acquisition.
At December 31, 2006 the Trust had bank debt of $45,379,000 (2005 -
$20,177,000). The Trust through its operating subsidiaries has bank revolving
credit facilities totalling $49,900,000 at December 31, 2006 (December 31,
2005 - $36,900,000). Effective January 1, 2007 this amount has been increased
to $59,900,000. The facilities carry an interest rate of Canadian chartered
bank prime.
Taxation of Trusts
On October 31, 2006 the Minster of Finance for Canada announced new
proposals for the taxation of existing income trusts. In summary under the new
proposals:- An income trust will be subject to a special rate of tax on its
distributions of income that is attributable to income from business
carried on in Canada, income from non-portfolio investments in
Canadian resource properties, and capital gains from the above.
- Distributions from income trusts will be taxed in the same manner as
a dividend from a taxable Canadian corporation.
- For existing trusts the new rules apply to taxation years that end
after 2010.
- The tax rate that would apply to taxation years after 2010 would be
31.5 percent.In addition the Minister announced the governments attempt to limit the
growth of existing income trusts. Under the proposals, the government will not
recommend any change to the 2011 date in respect of any income trust whose
equity capital grows as a result of issuances of new equity, in any of the
years from now to 2011 by an amount that does not exceed the greater of $50
million and an objective "safe harbour" amount. The safe harbour amount will
be measured by reference to the trusts market capitalization as of the end of
trading on October 31, 2006. Market capitalization is to be measured in terms
of the value of an income trusts issued and outstanding publicly-traded units.
For the period November 1, 2006 to December 31, 2007 an income trusts safe
harbour will be 40 percent of that October benchmark and 20 percent for each
calendar year 2008, 2009 and 2010.
The Minister also announced the government's intent to allow for
conversions of income trusts back to corporate form as well as to allow the
mergers of income trusts without effecting the above safe harbour amounts.
The above proposals have not been made law as of the date of this report.
In addition, the rules surrounding the safe harbour rules and conversion to a
corporate form have not yet been drafted into legislation.
The impact to individual unitholders of the above proposals differs by
the category of the investor. For Canadian individual or Canadian taxable
corporation investors the distributions will be subject to the dividend tax
credit which should offset to a large degree the tax paid by the Trust. For
those investors that hold their trust units in a tax deferred fund (RRSP's,
RRIF's or in a pension fund) there will be double taxation of distributions.
This will result in an effective rate of tax in most cases in excess of 55
percent made up of 31.5 percent at the trust level and a further tax on
withdrawal from the fund based on the individual's tax rate. Also for
non-resident investors there will be a significant double taxation as well.
The trust again pays its 31.5 percent, then a further 15 percent withholding
is required and the non-residents must also pay their own federal and state
taxes. This could result in excess of 60 percent being paid in taxes.
Bonterra's market value has been significantly impacted by the above
announcement. The Trust traded at $37.50 on October 31, 2006, and ended the
year at $25.57. The actual impact on operations to date has been minimal.
However, the uncertainty of how the legislation will be drafted and eventually
put into law has caused the Trust to be more conservative when examining its
current operations.
As of January 2, 2007, the Trust is believed to be owned approximately 25
percent by non-residents (based on ADP Canada and ADP USA beneficial reports).
As for the ownership by tax deferred funds, it is managements estimate that no
more than 15 percent is held by such entities. Therefore the majority of the
beneficial owners of Bonterra are estimated to be taxable Canadian investors.Management has been examining its options. These include:
(1) Continuing as a trust.
(2) Continuing as a trust to 2011 and converting to a corporation at
that time.
(3) Immediate conversion to a corporation.All of these options have differing impacts to the Trust's various
unitholders. With the fact the current government is in a minority position in
the house of commons, there is a large degree of uncertainty as to whether the
draft legislation will be passed, what amendments if any would be made, what
further legislation will be enacted to cover the safe harbour rules and
conversion features as well as a possible delay in the implementation of the
tax. All of these considerations may very will impact management's decision
regarding the best course of action for Bonterra.
Until more concrete information can be obtained it is management's
position that the Trust should continue with its current operations. The
proposed safe harbour rules will allow the Trust to raise in excess of
$650,000,000 over the next four years without losing its tax free status to
2011. This will allow the Trust to continue with its Cardium infill drilling
program, its shallow natural gas and natural gas from coals development as
well as potentially developing a CO(2) flood program and making some
acquisitions. Emphasis will be placed on increasing the Trusts available tax
pools to assist in mitigating any future tax consequences should the
legislation be passed.
Management will ensure that as information about the taxation of trusts
is provided all such relevant information will be made available to
Unitholders through press releases or as part of the Trust's continuous
disclosure requirements.
Forward-Looking Information
Certain information set forth in this document, including management's
assessment of Bonterra Energy Income Trust's ("the Trust" or "Bonterra")
future plans and operations, contains forward-looking statements. By their
nature, forward-looking statements are subject to numerous risks and
uncertainties, some of which are beyond Bonterra's control, including the
impact of general economic conditions, industry conditions, volatility of
commodity prices, currency fluctuations, imprecision of reserve estimates,
environmental risks, competition from other industry participants, the lack of
availability of qualified personnel or management, stock market volatility and
ability to access sufficient capital from internal and external sources.
Readers are cautioned that the assumptions used in the preparation of such
information, although considered reasonable at the time of preparation, may
prove to be imprecise and, as such, undue reliance should not be placed on
forward-looking statements. Bonterra's actual results, performance or
achievement could differ materially from those expressed in, or implied by
these forward-looking statements, and, accordingly, no assurance can be given
that any of the events anticipated by the forward-looking statements will
transpire or occur, or if any of them do so, what benefits that Bonterra will
derive therefrom. Bonterra disclaims any intention or obligation to update or
revise any forward-looking statements, whether as a result of new information,
future events or otherwise. Readers are cautioned that net present value of
reserves does not represent fair market value of reserves.Bonterra Energy Income Trust
----------------------------
Consolidated Balance Sheets
---------------------------
As at December 31 2006 2005
Assets
Current
Accounts receivable (Note 8) $ 10,486,000 $ 11,020,000
Crude oil inventory 843,000 836,000
Parts inventory 114,000 221,000
Prepaid expenses 1,086,000 781,000
Investment in related party (Note 2) 461,000 461,000
-------------------------------------------------------------------------
12,990,000 13,319,000
-------------------------------------------------------------------------
Property and Equipment (Note 3)
Petroleum and natural gas properties and
related equipment 176,602,000 139,798,000
Accumulated depletion and depreciation (54,650,000) (42,968,000)
-------------------------------------------------------------------------
121,952,000 96,830,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
$134,942,000 $110,149,000
-------------------------------------------------------------------------
Liabilities
Current
Distribution payable $ 4,050,000 $ 3,638,000
Accounts payable and accrued liabilities 13,748,000 11,476,000
Debt (Note 4) 45,379,000 20,177,000
-------------------------------------------------------------------------
63,177,000 35,291,000
Future income tax liability (Note 5) 3,587,000 4,341,000
Asset retirement obligations (Note 6) 14,819,000 13,195,000
-------------------------------------------------------------------------
81,583,000 52,827,000
-------------------------------------------------------------------------
Commitments, Contingencies and Guarantees
(Note 10)
Unitholders' Equity (Note 7)
Unit capital 89,488,000 83,900,000
Contributed surplus 1,116,000 636,000
Deficit (37,245,000) (27,214,000)
-------------------------------------------------------------------------
53,359,000 57,322,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
$134,942,000 $110,149,000
-------------------------------------------------------------------------
Bonterra Energy Income Trust
----------------------------
Consolidated Statements of Unitholders' Equity
----------------------------------------------
For the Years Ended December 31 2006 2005
Unitholders' equity, beginning of year $ 57,322,000 $ 54,060,000
Net earnings for the year 37,250,000 33,468,000
Net capital contributions (Note 7) 5,161,000 2,823,000
Units issued on acquisition of Novitas
Energy Ltd. (Note 7) - 5,681,000
Unit issue costs on acquisition of Novitas
Energy Ltd. (Note 7) - (259,000)
Unit based compensation adjustment 907,000 498,000
Dstributions declared (47,281,000) (38,949,000)
-------------------------------------------------------------------------
Unitholders' Equity, End of Year $ 53,359,000 $ 57,322,000
-------------------------------------------------------------------------
Bonterra Energy Income Trust
----------------------------
Consolidated Statements of Operations and Deficit
-------------------------------------------------
For the Years Ended December 31 2006 2005
Revenue
Oil and gas sales $ 88,734,000 $ 75,837,000
Royalties (10,512,000) (8,995,000)
Alberta royalty tax credit 487,000 464,000
Gain on sale of property (Note 3) 532,000 263,000
Interest and other 66,000 33,000
-------------------------------------------------------------------------
79,307,000 67,602,000
-------------------------------------------------------------------------
Expenses
Production costs 22,238,000 20,203,000
General and administrative 2,295,000 2,420,000
Interest on debt 1,610,000 575,000
Unit based compensation 907,000 498,000
Dry hole costs 2,919,000 628,000
Depletion, depreciation and accretion 12,474,000 9,730,000
-------------------------------------------------------------------------
42,443,000 34,054,000
-------------------------------------------------------------------------
Earnings Before Income Taxes 36,864,000 33,548,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Income taxes (recovery) (Note 5)
Current 367,000 (175,000)
Future (753,000) 255,000
-------------------------------------------------------------------------
(386,000) 80,000
-------------------------------------------------------------------------
Net Earnings for the Year 37,250,000 33,468,000
Deficit, beginning of year (27,214,000) (21,733,000)
Distributions declared (47,281,000) (38,949,000)
-------------------------------------------------------------------------
Deficit, end of year ($ 37,245,000) ($ 27,214,000)
-------------------------------------------------------------------------
Net Earnings Per Unit - Basic (Note 7) $ 2.23 $ 2.04
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Earnings Per Unit - Diluted (Note 7) $ 2.21 $ 2.01
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Bonterra Energy Income Trust
----------------------------
Consolidated Statements of Cash Flow
------------------------------------
For the Years Ended December 31 2006 2005
Operating Activities
Net earnings for the year $ 37,250,000 $ 33,468,000
Items not affecting cash
Gain on sale of property (532,000) (263,000)
Unit based compensation 907,000 498,000
Dry hole costs 2,919,000 628,000
Depletion, depreciation and accretion 12,474,000 9,730,000
Future income taxes (recovery) (753,000) 255,000
-------------------------------------------------------------------------
52,265,000 44,316,000
-------------------------------------------------------------------------
Change in non-cash working capital
Accounts receivable (147,000) (2,814,000)
Crude oil inventory (7,000) (134,000)
Parts inventory 107,000 170,000
Prepaid expenses (305,000) 306,000
Accounts payable and accrued liabilities 793,000 (2,584,000)
Asset retirement obligations settled (762,000) (275,000)
-------------------------------------------------------------------------
(321,000) (5,331,000)
-------------------------------------------------------------------------
51,944,000 38,985,000
-------------------------------------------------------------------------
Financing Activities
Increase in debt 25,202,000 11,717,000
Unit option proceeds 5,161,000 2,823,000
Unit issue costs on acquisition of
Novitas Energy Ltd. - (259,000)
Unit distributions (46,869,000) (38,001,000)
-------------------------------------------------------------------------
(16,506,000) (23,720,000)
-------------------------------------------------------------------------
Investing Activities
Property and equipment expenditures (38,348,000) (16,669,000)
Proceeds on sale of property 750,000 1,097,000
Abandonment deposit - 1,522,000
Cash portion of Novitas Energy Ltd.
acquisition - (769,000)
-------------------------------------------------------------------------
(37,598,000) (14,819,000)
-------------------------------------------------------------------------
Change in non-cash working capital
Accounts receivable 681,000 (534,000)
Accounts payable and accrued liabilities 1,479,000 88,000
-------------------------------------------------------------------------
2,160,000 (446,000)
-------------------------------------------------------------------------
(35,438,000) (15,265,000)
-------------------------------------------------------------------------
Net cash inflow - -
Cash, beginning of year - -
-------------------------------------------------------------------------
Cash, End of Year $ - $ -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash Interest Paid $ 1,610,000 $ 575,000
Cash Taxes Paid $ 393,000 $ 894,000
Bonterra Energy Income Trust
----------------------------
Notes to the Consolidated Financial Statements
----------------------------------------------
For the Years Ended December 31, 2006 and 2005
1. SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The consolidated financial statements have been prepared by management in
accordance with Canadian generally accepted accounting principles
("GAAP") as described below.
Consolidation
These consolidated financial statements include the accounts of Bonterra
Energy Income Trust (the "Trust") and its wholly owned subsidiaries
Bonterra Energy Corp. (Bonterra), Comstate Resources Ltd. (Comstate) and
effective January 7, 2005, Novitas Energy Ltd. (Novitas). Effective
January 1, 2007, Bonterra and Comstate amalgamated. Inter-company
transactions and balances are eliminated upon consolidation.
Measurement Uncertainty
The preparation of financial statements requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the
date of the financial statements and revenues and expenses during the
reporting period. Actual results can differ from those estimates.
In particular, amounts recorded for depreciation and depletion and
amounts used in ceiling test calculations are based on estimates of
petroleum and natural gas reserves and future costs required to develop
those reserves. The Trust's reserve estimates are evaluated annually by
an independent engineering firm. By their nature, these estimates of
reserves and the related future cash flows are subject to measurement
uncertainty, and the impact on the consolidated financial statements of
future periods could be material.
The amounts recorded for asset retirement obligations were estimated
based on the Trust's net ownership interest in all wells and facilities,
estimated costs to abandon and reclaim the wells and facilities and the
estimated period during which these costs will be incurred in the future.
Any changes to these estimates could change the amount recorded for asset
retirement obligations and may materially impact the financial statements
of future periods.
Inventories
Inventories consist of crude oil as well as materials and supplies which
include tubing, rods, motors, pump jacks, bases and miscellaneous parts
used in the maintenance of the Trust's tangible equipment. Both crude oil
and materials and supplies are valued at the lower of cost or net
realizable value. Inventory cost for crude oil is determined based on
combined average per barrel operating costs, royalties and depletion and
depreciation for the year and net realizable value is determined based on
sales price in the month preceding year end.
Investments
Investments are carried at the lower of cost and market value.
Property and Equipment
Petroleum and Natural Gas Properties and Related Equipment
The Trust follows the successful efforts method of accounting for
petroleum and natural gas properties and related equipment. Costs of
exploratory wells are initially capitalized pending determination of
proved reserves. Costs of wells which are assigned proved reserves remain
capitalized, while costs of unsuccessful wells are charged to earnings.
All other exploration costs including geological and geophysical costs
are charged to earnings as incurred. Development costs, including the
cost of all wells, are capitalized.
Producing properties and significant unproved properties are assessed
annually or more frequently as economic events dictate, for potential
impairment. Impairment is assessed by comparing the estimated net
undiscounted future cash flows to the carrying value of the asset. If
required, the impairment recorded is the amount by which the carrying
value of the asset exceeds its fair value.
Depreciation and depletion of capitalized costs of oil and gas producing
properties are calculated using the unit of production method.
Development and exploration drilling and equipment costs are depleted
over the remaining proved developed reserves. Depreciation of other plant
and equipment is provided on the straight line method. Straight line
depreciation is based on the estimated service lives of the related
assets which is estimated to be ten years.
Furniture, Fixtures and Office Equipment
These assets are recorded at cost and depreciated over a three to ten
year period representing their estimated useful lives.
Income Taxes
Income taxes are calculated using the liability method of accounting for
income taxes. Under this method, income tax liabilities and assets are
recognized for the estimated tax consequences attributable to differences
between the amounts reported for assets and liabilities by the Trust's
subsidiary companies in the consolidated financial statements of the
Trust and their respective tax bases, using enacted or substantively
enacted income tax rates. The effect of a change in income tax rates on
future tax liabilities and assets is recognized in income in the period
in which the change occurs.
The Trust is a taxable entity under the Income Tax Act (Canada) and is
taxable only on income that is not distributed or distributable to the
Unitholders. As the Trust allocates all of its taxable income to the
Unitholders in accordance with the Trust Indenture, and meets the
requirements of the Income Tax Act (Canada) applicable to the Trust, no
provision for income tax expense has been made in the Trust. However, the
Trust's subsidiaries are subject to taxation on income which is not
transferred to the Trust.
In the Trust structure, payments are made between the Trust's operating
subsidiaries and the Trust which result in the transferring of taxable
income from the operating subsidiaries to individual Unitholders. These
payments may reduce future income tax liabilities previously recorded by
the operating companies which would be recognized as a recovery of income
tax in the period incurred.
Asset Retirement Obligations
The fair value of obligations associated with the retirement of long-life
assets are recorded in the period the asset is put into use, with a
corresponding increase to the carrying amount of the related asset. The
obligations recognized are statutory, contractual or legal obligations.
The liability is adjusted over time for changes in the value of the
liability through accretion charges which are included in depletion,
depreciation and accretion expense. The costs capitalized to the related
assets are amortized to earnings in a manner consistent with the
depletion and depreciation of the underlying asset.
Trust Unit-Based Compensation
The Trust has a unit-based compensation plan, which is described in
Note 7. The Trust records a compensation expense over the vesting period
based on the fair value of options granted to employees, directors and
consultants. These amounts are recorded as contributed surplus. Any
consideration paid by employees, directors or consultants on the exercise
of these options is recorded as unit capital together with the related
contributed surplus associated with the exercised options.
Revenue Recognition
Revenues associated with sales of petroleum and natural gas are recorded
when title passes to the customer.
Hedging
Derivative financial instruments are utilized to reduce commodity price
risk on the Trust's product sales. The Trust does not enter into
financial instruments for trading or speculative purposes.
The Trust's policy is to formally designate each derivative financial
instrument as a hedge of a specifically identified product sale. The
Trust assesses the derivative financial instruments for effectiveness as
hedges, both at inception and over the term of the instrument. The
production volume in the derivative financial instruments all match the
production being hedged.
Commodity price swap agreements are used as part of the Trust's program
to manage its product pricing. The commodity price swap agreements
involve the periodic exchange of payments and are recorded as adjustments
of net revenue. For the twelve months ended December 31, 2006 the Trust
recorded a reduction to net revenue of $62,000 (2005 - $4,054,000) with
respect to these agreements.
Joint Interest Operations
Significant portions of the Trust's oil and gas operations are conducted
with other parties and accordingly the financial statements reflect only
the Trust's proportionate interest in such activities.
Net Earnings Per Unit
Basic earnings per unit are computed by dividing earnings by the weighted
average number of units outstanding during the year. Diluted per unit
amounts reflect the potential dilution that could occur if options to
purchase trust units were exercised. The treasury stock method is used to
determine the dilutive effect of trust unit options, whereby proceeds
from the exercise of trust unit options or other dilutive instruments are
assumed to be used to purchase trust units at the average market price
during the period.
2. INVESTMENT IN RELATED PARTY AND ACQUISITION OF NOVITAS ENERGY LTD.
The investment consists of 689,682 (December 31, 2005 - 689,682) common
shares in Comaplex Minerals Corp (Comaplex), a company with common
directors and management with the Trust and its subsidiaries. The
investment is recorded at cost. The fair market value as determined by
using the trading price of the stock at December 31, 2006 was $2,297,000
(December 31, 2005 - $2,448,000). 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.
On January 7, 2005 the Trust acquired Novitas. The acquisition was
accounted for at Novitas' carrying value due to the related status of
Novitas to the Trust. The carried values were as follows:
Accounts receivable $ 568,000
Crude oil inventory 122,000
Prepaid expenses 47,000
Property and equipment 23,130,000
Accumulated depletion and depreciation (6,522,000)
Accounts payable and accrued liabilities (2,010,000)
Debt (4,598,000)
Future income tax liability (3,089,000)
Asset retirement obligations (1,198,000)
--------------
$ 6,450,000
--------------
--------------
The acquisition cost was $769,000 cash and the issuance of 1,335,753
trust units.
3. PROPERTY AND EQUIPMENT
2006 2005
Accumulated Accumulated
Depletion Depletion
and and
Cost Depreciation Cost Depreciation
-------------------------------------------------------------------------
Undeveloped land $ 334,000 $ - $ 334,000 $ -
Petroleum and
natural gas
properties and
related
equipment 175,353,000 54,008,000 138,713,000 42,622,000
Furniture,
equipment and
other 915,000 642,000 751,000 346,000
-------------------------------------------------------------------------
$176,602,000 $ 54,650,000 $139,798,000 $ 42,968,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
In January 2006 the Trust completed the sale of a non-operated oil and
gas property for gross proceeds of $750,000 to an unrelated third party.
The disposition resulted in the Trust reporting a gain on sale of
$532,000.
On April 8, 2005, a former subsidiary of Novitas, Pine Cliff Energy Ltd.
(Pine Cliff) (with common directors and management with the Trust and its
subsidiaries) closed a rights offering with over 97 percent of former
Novitas shareholders exercising their rights to acquire common shares in
Pine Cliff for $0.15 per common share. As part of the rights offering,
the Trust agreed to sell to Pine Cliff effective January 1, 2005 (closing
April 8, 2005) approximately 18 barrels per day of oil equivalent of
production and some exploration lands formerly held by Novitas for
proceeds of approximately $1,000,000. As a result of this sale the Trust
reported a gain on sale of property of $225,000. The Trust also disposed
of minor non-core area properties for proceeds of approximately $97,000
for a gain of $38,000.
4. DEBT
The Trust has a bank revolving credit facility of $49,900,000 at
December 31, 2006 (2005 - $36,900,000). Effective January 2, 2007 the
revolving credit facility was increased to $59,900,000. 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
outstanding letters of credit. Letters of credit totalling $340,000
(December 31, 2005 - $340,000) were issued at December 31, 2006. 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 GAAP. It has been management's experience that these types of
demand 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
year ended December 31, 2006 for this loan was $1,610,000 (2005 -
$575,000).
5. INCOME TAXES
The Trust has recorded a future income tax liability related to assets
and liabilities and related tax amounts held through its 100 percent
owned operating subsidiaries. The following figures do not reflect the
potential consequences of the Canadian Federal Governments October 31,
2006 announcement on the future taxation of Income Trusts. The liability
relates to the following temporary differences in those subsidiaries:
2006 2005
-------------------------------------------------------------------------
Future income tax liability to assets and
liabilities of the subsidiary companies $ 6,233,000 $ 5,919,000
Future tax asset related to finance costs
in corporate subsidiaries - (12,000)
Future tax asset related to corporate tax
losses carried forward in the subsidiary
companies (2,646,000) (1,566,000)
-------------------------------------------------------------------------
$ 3,587,000 $ 4,341,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Income tax expense varies from the amounts that would be computed by
applying Canadian federal and provincial income tax rates as follows:
2006 2005
-------------------------------------------------------------------------
Earnings before income taxes $ 36,864,000 $ 33,548,000
Combined federal and provincial income
tax rates 34.97% 38.08%
-------------------------------------------------------------------------
Income tax provision calculated using
statutory tax rates 12,891,000 12,775,000
Increase (decrease) in taxes resulting
from:
Saskatchewan resource surcharge 389,000 347,000
Unit-based compensation 317,000 190,000
Non-deductible crown royalties 1,072,000 1,793,000
Resource allowance (1,901,000) (3,283,000)
Trust income allocated to Unitholders (13,031,000) (12,763,000)
Adjustment on acquisition of Novitas - 1,055,000
Others (123,000) (34,000)
-------------------------------------------------------------------------
Income tax expense (recovery) $ (386,000) $ 80,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 $ 15,037,000
Canadian oil and gas property expenditures 10 1,244,000
Canadian development expenditures 30 30,581,000
Canadian exploration expenditures 100 93,000
Income tax losses carried forward(1) 100 9,035,000
-------------------------------------------------------------------------
$ 55,990,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Income tax losses carried forward expire in 2014 ($635,000), 2015
($3,574,000) and 2016 ($4,826,000).
The Trust has the following tax pools, which may be used in reducing
future taxable income allocated to its Unitholders:
Rate of
Utilization
% Amount
-------------------------------------------------------------------------
Canadian oil and gas property expenditures 10 $ 15,685,000
Finance costs 20 626,000
Eligible capital expenditures 7 168,000
-------------------------------------------------------------------------
$ 16,479,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
On October 31, 2006, the Canadian Federal Government announced a proposed
Trust taxation pertaining to taxation of distributions paid by publicly
traded income trusts. Currently, distributions paid to unitholders, other
than returns of capital, are claimed as a deduction by the Trust in
arriving at taxable income whereby tax is eliminated at the Trust level
and is paid by the unitholders. The proposals would result in a two-
tiered tax structure whereby distributions would first be subject to a
31.5 percent at the Trust level commencing in 2011 and then investors
would be subject to tax on the distribution as if it were a taxable
dividend paid by a taxable Canadian corporation. If enacted, the
proposals would apply to the Trust effective January 1, 2011. The Trust
is currently assessing various alternatives with respect to the potential
implications of the tax proposals; however, until the legislation is
enacted in final form, the Trust will not arrive at a final conclusion
with respect to future Trust structure and implications to the Trust. As
the tax proposals had not been substantively enacted as of December 31,
2006, the consolidated financial statements do not reflect the impact of
the proposed taxation.
6. ASSET RETIREMENT OBLIGATIONS
At December 31, 2006, the estimated total undiscounted amount required to
settle the asset retirement obligations was $46,434,000 (2005 -
$39,921,000). Costs for asset retirement have been calculated assuming a
5 percent inflation rate for 2007, 4 percent for 2008, 3 percent for 2009
and 2 percent thereafter. These obligations will be settled based on the
useful lives of the underlying assets, which extend up to 40 years into
the future. This amount has been discounted using a credit-adjusted risk-
free interest rate of 5 (2005 - 5) percent.
Changes to asset retirement obligations were as follows:
2006 2005
-------------------------------------------------------------------------
Asset retirement obligations, January 1 $ 13,195,000 $ 11,419,000
Adjustment to asset retirement obligations 1,726,000 233,000
Acquisition of Novitas - 1,198,000
Liabilities settled during the year (762,000) (275,000)
Accretion 660,000 620,000
-------------------------------------------------------------------------
Asset retirement obligations, December 31 $ 14,819,000 $ 13,195,000
-------------------------------------------------------------------------
7. UNIT CAPITAL
Authorized
The Trust is authorized to issue an unlimited number of trust units
without nominal or par value.
2006 2005
Issued Number Amount Number Amount
-------------------------------------------------------------------------
Trust Units
Balance,
beginning
of year 16,535,158 $ 83,900,000 14,943,405 $ 75,486,000
Transfer of
contributed
surplus to Unit
capital - 427,000 - 169,000
Units issued on
acquisition of
Novitas - - 1,335,753 5,681,000
Unit issue costs
on acquisition
of Novitas - - - (259,000)
Issued pursuant
to Trust unit
option plan 339,500 5,161,000 256,000 2,823,000
-------------------------------------------------------------------------
Balance, end
of year 16,874,658 $ 89,488,000 16,535,158 $ 83,900,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The number of trust units used to calculate diluted net earnings per unit
for the year ended December 31, 2006 of 16,880,422 (2005 - 16,594,260)
included the basic weighted average number of units outstanding of
16,737,651 (2005 - 16,388,621) plus 142,771 (2005 - 205,639) units
related to the dilutive effect of unit options.
The deficit balance is composed of the following items:
2006 2005
-------------------------------------------------------------------------
Accumulated earnings $122,406,000 $ 85,156,000
Accumulated cash distributions (159,651,000) (112,370,000)
-------------------------------------------------------------------------
Deficit $(37,245,000) $(27,214,000)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The Trust provides an option plan for its directors, officers, employees
and consultants. Under the plan, the Trust may grant options for up to
1,670,000 (2005 - 1,635,000) 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
December 31, 2006 and 2005, and changes during the years is presented
below:
2006 2005
-------------------------------------------------------------------------
Weighted- Weighted-
Average Average
Exercise Exercise
Options Price Options Price
-------------------------------------------------------------------------
Outstanding at beginning
of year 646,000 $18.67 565,000 $11.56
Options granted 447,000 29.18 407,000 23.32
Options exercised (339,500) 15.20 (256,000) 11.03
Options cancelled (32,000) 24.70 (70,000) 16.35
-------------------------------------------------------------------------
Outstanding at
end of year 721,500 $26.55 646,000 $18.67
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Options exercisable
at end of year 212,500 $22.62 214,000 $10.89
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The following table summarizes information about unit options outstanding
at December 31, 2006:
Options Outstanding Options Exercisable
---------------------------------- -------------------------
Number Weighted-
Out- Average Weighted- Number Weighted-
standing Remaining Average Exercisable Average
At Contractual Exercise At Exercise
12/31/06 Life Price 12/31/06 Price
-------------------------------------------------------------------------
$15.20 31,000 0.5 years $15.20 19,000 $15.20
$22.45-
$23.35 251,500 2.3 years 23.32 193,500 23.35
$28.70-
$28.75 399,000 2.2 years 28.75 - -
$32.00-
$33.75 40,000 3.0 years 33.55 - -
-------------------------------------------------------------------------
$15.20-
$33.75 721,500 2.1 years $26.55 212,500 $22.62
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 447,000 unit options with an estimated
fair value of $1,193,000 ($2.67 per option) using the Black-Scholes
option pricing model with the following key assumptions:
Weighted-average risk free interest rate (%) - 4.1
Expected life (years) - 2.5
Weighted-average volatility (%) - 27.0
Dividend yield - based on the percentage
of distributions paid to
the Unitholders during
the year
8. RELATED PARTY TRANSACTIONS
The Trust received a management fee from Comaplex of $300,000 (2005 -
$240,000) for management services and office administration. This fee has
been included as a recovery in general and administrative expenses and
represents the fair value of the services rendered.
As at December 31, 2006, the Trust had an account receivable from
Comaplex of $38,000 (December 31, 2005 - $29,000).
The Trust received a management fee from Pine Cliff of $216,000 (2005 -
$132,000) for management services and office administration. This fee has
been included as a recovery in general and administrative expenses and
represents the fair value of the services rendered.
As at December 31, 2006 the Trust had an account receivable from Pine
Cliff of Nil (December 31, 2005 - $165). As at December 31, 2006, the
Trust had an account payable of Nil (December 31, 2005 - $16,000) to Pine
Cliff. The 2005 amount owing was related to outstanding post closing
adjustment items for the sale of properties to Pine Cliff (see note 3).
9. FINANCIAL INSTRUMENTS
Fair Values
The Trust's financial instruments included in the balance sheet are
comprised of accounts receivable, distribution payable, accounts payable
and accrued liabilities and the revolving demand loan. The fair value of
these financial instruments approximate their carrying value due to the
short-term maturity of those instruments. Borrowings under bank credit
facilities are for short periods with variable interest rates, thus,
carrying values that approximate fair value.
Credit Risk
Substantially all of the Trust's accounts receivable are due from
customers in the oil and gas industry and are subject to normal industry
credit risks. The carrying value of accounts receivable reflects
management's assessment of associated credit risks.
Interest Rate Risk
The Trust's bank debt is comprised of revolving loans at variable rates
of interest, and as such, the Trust is exposed to interest rate risk.
Commodity Price Risk
The nature of the Trust's operations results in exposure to fluctuations
in commodity prices and exchange rates. The Trust monitors and when
appropriate uses derivative financial instruments to manage its exposure
to these risks.
10. COMMITMENTS, CONTINGENCIES AND GUARANTEES
The Trust entered into the following commodity hedging transactions in
2006 for a portion of its 2007 and 2008 production:
Volume
Period of Agreement Commodity per day Index Price (Cdn.)
------------------- --------- ------- ----- ------------
January 1, 2007 Crude Oil 500 barrels WTI Floor of $74.55
to June 30, 2007 and ceiling of
$85.00 per
barrel
January 1, 2007 Crude Oil 500 barrels WTI Floor of $75.00
to 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
November 1, 2006 Natural Gas 2,000 GJ's AECO Floor of $6.65
to March 31, 2007 and ceiling of
$12.50 per GJ
December 1, 2006 Natural Gas 1,500 GJ's AECO Floor of $6.00
to March 31, 2007 and ceiling of
$9.65 per GJ
April 1, 2007 Natural Gas 2,000 GJ's AECO $6.52 per GJ
to 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 Natural Gas 2,000 GJ's AECO Floor of $6.50
to March 31, 2008 and Ceiling of
$10.37 per GJ
As at December 31, 2006 the fair value of the outstanding commodity
hedging contracts was a net asset of $1,189,000 (December 31, 2005 -
($1,349,000)).
The Trust has no contractual obligations that last more than a year other
than its office lease agreement which is as follows:
Contract Less than 1 - 3 4 - 5 After
Obligations Total 1 year years years 5 years
-------------------------------------------------------------------------
Office lease $1,963,000 $283,000 $910,000 $656,000 $114,000%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 web site 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