Bonterra Energy Income Trust Announces Fourth Quarter and Annual Results
Wed Mar 19, 8:02 AMCALGARY, March 19 /CNW/ - Bonterra Energy Income Trust (www.bonterraenergy.com) (TSX: BNE-UN.TO) is pleased to announce its financial and operational results for the three months and fiscal year ended December 31, 2007.
HIGHLIGHTS
Capital Spending and Production
-------------------------------
In 2007 Bonterra's capital expenditure was $19,000,000, down from $38,000,000 in 2006. This reduction was caused mainly by uncertainty regarding what the impact of the Alberta royalty structure change will be and by the out of control drilling costs encountered in 2006. In 2007 the Trust drilled 22 gross (15.3 net) Cardium oil wells and 2 gross (0.7 net) Edmonton Sand natural gas wells with a 100 percent success rate.
The capital program was successful in replacing the 2007 annual production and in increasing overall reserves as well as increasing the daily production rate to 4,218 BOE from 4,042 in 2006. It is expected that average production will increase in 2008. The exit production rate for December 2007 was approximately 4,400 BOE per day.
Internal calculations of the estimated inventory of economic undrilled locations, net to the Trust, using a crude oil price of $80 and capital expenditures of $900,000 per Cardium well ($375,000 for a natural gas well) (subject to the terms of the new Alberta royalty structure) is:
- Cardium oil and solution gas wells: 330
- Natural gas wells 10
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340
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-----
At the current rate of drilling, the Trust will have a drilling inventory of approximately 17 years. It is not anticipated that these drill locations will have any significant impact on production from existing wells.
Reserves
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Gross proved plus probable crude oil and NGL reserves increased by 2 percent and gross proved plus probable natural gas reserves increased by 9 percent. These percentages were somewhat affected by the property swap of Dodsland area, Saskatchewan, properties for Pembina area, Alberta, properties, whereby the Dodsland property ratio of oil to solution gas was higher than the ratio of oil to solution gas for the Pembina property. The reserve life index for 2007 (using Q4, 2007 production) is 17.4 years compared to 17.6 years in 2006. The slight reduction is due to Q4, 2007 production increasing to 4,295 BOE compared to 4,118 BOE in Q4, 2006. On a per unit basis the reserves in BOE per weighted average outstanding unit increased to 1.62 in 2007 from 1.57 in 2006.
The Trust is extremely pleased with its 2007 finding and development costs of $2.68 per BOE for proved plus probable reserve additions. The recycle ratio in 2007 was 13.0 (2006 - 1.9). The exceptional costs and ratio in 2007 are attributable to lower capital costs per well and also due to a carry over from 2006 activities. At December 31, 2006, drilled wells that were not on production were assigned low reserves or no reserves and when these wells were put on production in 2007, the independent engineers, giving consideration to the 2007 production history, assigned or increased previously assigned reserves to all of these wells.
Bank Debt
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Bank debt at December 31, 2007, was $57,422,000 compared to $45,379,000 in 2006. This represents a debt to funds flow ratio (by annualizing the Q4, 2007, adjusted distribution base) of 10.9 months compared to the 2006 ratio of 11 months. It is anticipated that this ratio will be reduced in 2008.
Cash Netback and Recycle Ratio
------------------------------
Bonterra's cash netback in 2007 was $34.93 compared to $35.04 in 2006. It should be noted that due to an increase in production and commodity prices and the property swap, the Q4, 2007, netback increased to $40.09 compared to $34.96 for Q4, 2006. The Trust's recycle ratio in 2007 was 13.0 compared to 1.9 in 2006.
FINANCIAL AND OPERATIONAL SUMMARY
Three Months Ended Years Ended
December 31 December 31
2007 2006 2007 2006
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Realized Oil, Gas
& NGL Sales $26,573,000 $21,719,000 $96,431,000 $88,734,000
Adjusted Distribution
Base(1) $15,842,000 $12,235,000 $53,815,000 $52,797,000
Per Unit - basic $ 0.94 $ 0.72 $ 3.18 $ 3.15
Per Unit - diluted $ 0.94 $ 0.72 $ 3.18 $ 3.12
Net Earnings $ 7,920,000 $ 6,471,000 $30,350,000 $37,250,000
Per Unit - basic $ 0.47 $ 0.39 $ 1.79 $ 2.23
Per Unit - diluted $ 0.47 $ 0.38 $ 1.79 $ 2.21
Distributions
per Unit $ 0.66 $ 0.72 $ 2.64 $ 2.82
Payout Ratio 83% 90%
Units outstanding 16,928,158 16,874,658
Daily Oil and NGL
Production (Bbls) 3,098 3,138 3,113 3,040
Daily Gas
Production (MCF) 7,176 5,885 6,627 6,014
Daily BOE (6:1) 4,295 4,119 4,218 4,042
Average Liquid Price
($/Bbl) $ 77.60 $ 60.79 $ 70.31 $ 64.69
Average Gas Price
($/MCF) $ 6.70 $ 7.57 $ 6.75 $ 7.55
Average BOE Price
($/BOE) $ 67.25 $ 57.32 $ 62.64 $ 60.13
Net Back per BOE(2) $ 40.09 $ 32.21 $ 34.96 $ 35.04
Reserves
Oil and Liquids
(barrels in 000's)
Proved Developed
Producing (Gross)(3) 14,468 13,688
Proved (Gross) 17,472 16,758
Proved plus
Probable (Gross) 21,910 21,526
Natural Gas (MCF
in 000's)
Proved Developed
Producing (Gross) 19,863 17,011
Proved (Gross) 24,125 22,562
Proved plus
Probable (Gross) 32,465 29,700
Reserve Life Index
(Oil, liquids and
natural gas at 6:1)(4)
Proved Developed
Producing 11.3 11.0
Proved 13.7 13.6
Proved plus Probable 17.4 17.6
Reserves in BOE's per
Weighted Average
Outstanding Unit
Proved Developed
Producing 1.05 0.98
Proved 1.27 1.22
Proved plus Probable 1.62 1.57
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(1) Adjusted distribution base (formally funds flow from operations) is
not a recognized measure under GAAP. Management believes that in
addition to net earnings, adjusted distribution base 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 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") recently
published recommendations regarding disclosure of a measure called
Standardized Distributable Cash. Please refer to pages 23 and 24 of
this report for the reconciliation between adjusted distribution base
and standardized distributable cash.
(2) 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.
(3) Gross reserves relate to the Trust's ownership of reserves before
royalty interests.
(4) The reserve life index is calculated by dividing the reserves (in
BOE's) by the annualized fourth quarter average production rate in
BOE/d 4,295 (2006 - 4,119)
RESERVES
The Trust engaged the services of Sproule Associates Limited to prepare a
reserve evaluation with an effective date of December 31, 2007. 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 Shaunavon area
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, 2007
(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 13,624 12,909 19,863 15,281 844 627
Developed
Non-Producing 9 9 907 731 1 1
Undeveloped 2,808 2,425 3,355 2,215 186 123
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TOTAL PROVED 16,442 15,343 24,125 18,228 1,030 750
PROBABLE 4,160 3,890 8,340 6,213 278 194
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TOTAL PROVED PLUS
PROBABLE 20,602 19,233 32,465 24,441 1,308 944
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RECONCILIATION OF TRUST GROSS RESERVES
BY PRINCIPAL PRODUCT TYPE (FORECAST PRICES AND COSTS)
Light and Medium
Oil and NGL's Natural Gas
Gross Gross
Gross Gross Proved Gross Gross Proved
Proved Probable Plus Proved Probable Plus
(Mbbl) (Mbbl) Probable (MMcf) (MMcf) Probable
(Mbbl) (MMcf)
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December 31, 2006 16,758 4,768 21,526 22,562 7,138 29,700
Extension 719 180 899 1,350 (375) 975
Improved recovery 147 57 204 295 168 463
Technical
revisions 1,473 (411) 1,062 1,066 1,363 2,429
Discoveries - - - - - -
Acquisitions 771 260 1,031 1,372 418 1,790
Dispositions (1,288) (357) (1,645) (448) (185) (633)
Economic factors (27) (59) (86) 103 (187) (84)
Production (1,081) - (1,081) (2,175) - (2,175)
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December 31, 2007 17,472 4,438 21,910 24,125 8,340 32,465
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SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE
AS OF DECEMBER 31, 2007 (FORECAST PRICES AND COSTS)
NET PRESENT VALUE OF FUTURE NET REVENUE
Before Income Taxes
Discounted at (%/year)
0 5 10 15 20
(M$)
RESERVE CATEGORY
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PROVED
Developed Producing 834,718 489,936 351,815 279,759 235,358
Developed Non-Producing 4,009 3,167 2,570 2,131 1,799
Undeveloped 111,055 88,159 70,872 57,584 47,202
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TOTAL PROVED 949,782 581,262 425,257 339,474 284,358
PROBABLE 323,791 131,693 74,507 49,747 36,262
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TOTAL PROVED PLUS PROBABLE 1,273,573 712,955 499,764 389,222 320,620
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SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE
AS OF DECEMBER 31, 2007 (FORECAST PRICES AND COSTS)
NET PRESENT VALUE OF FUTURE NET REVENUE
After Income Taxes
Discounted at (%/year)
0 5 10 15 20
(M$)
RESERVE CATEGORY
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PROVED
Developed Producing 687,026 422,853 313,885 255,463 260,016
Developed Non-Producing 3,375 2,690 2,204 1,846 1,573
Undeveloped 94,416 74,799 60,043 48,718 39,870
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TOTAL PROVED 784,817 500,341 376,132 306,026 260,016
PROBABLE 244,341 100,548 57,632 38,976 28,768
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TOTAL PROVED PLUS PROBABLE 1,029,159 600,889 433,763 345,003 288,784
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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)
-------------------------------------------------------------------------
2008 88.17 6.19 52.29 65.72 90.30
2009 84.54 6.94 50.14 63.01 86.58
2010 83.16 7.46 49.32 61.98 85.17
2011 81.26 7.50 48.20 60.57 83.23
2012 80.73 7.41 47.88 60.17 82.68
2013 81.25 7.58 48.19 60.56 83.21
2014 82.88 7.76 49.16 61.78 84.88
2015 84.55 7.94 50.14 63.02 86.59
2016 86.25 8.12 51.15 64.28 88.33
2017 87.98 8.31 52.18 65.58 90.10
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 cost
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 2007 average production of oil and natural gas liquids was 3,113 (2006 - 3,040) barrels per day and natural gas production in 2007 averaged 6,627 (2006 - 6,014) MCF per day. Oil production increased by approximately 2.5 percent while gas production increased by approximately 10 percent. The increased crude oil production was predominantly due to the Trust's 2006 and 2007 development programs. Natural gas increase was a combination of the 2006 development program and the asset swap concluded on October 30, 2007.
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 2007. Bonterra tied-in 3 gross and net Cardium oil wells and 2 gross and net natural gas wells in December. The Trust also completed an asset exchange resulting in the disposition of its interest in the Dodsland area of Saskatchewan for further property interests in the Pembina area of Alberta. The net result was a slight reduction in volumes on a BOE basis with Dodsland representing approximately 265 BOE's per day and the acquired properties producing approximately 250 BOE's. However the newly acquired properties had an average operating cost per BOE of $12.60 compared to $36.50 for the Dodsland assets offset slightly by larger royalties.
The Trust's overall annual decline rate for 2007 was approximately nine percent which the Trust was able to more than offset with its 2007 drill program. The Trust, along with its partners, drilled 22 gross (15.3 net) Cardium oil wells. This includes 15 gross and 14.3 net Cardium wells drilled directly by the Trust. Also the Trust drilled 2 gross (.7 net) shallow gas wells in 2007. The Trust experienced a 100 percent success rate with its 2007 drilling program.
As at December 31, 2007 Bonterra had 7 gross (6.3 net) Cardium oil wells, 2 gross (2 net) natural gas wells and 3 gross (2.5 net) coal-bed (CBM) wells with assigned reserves drilled but not on production. Subsequent to December 31, 2007 and up to the date of this report, Bonterra has put on production all of its Cardium oil wells and one shallow gas well. The timing for the tie-in of the remaining natural gas and CBM wells has not yet been determined.
Revenue
Gross revenue from petroleum and natural gas sales prior to royalties was $96,431,000 (2006 - $88,734,000). The increase of $7,697,000 was due to increased production volumes and an increase in the average price received for crude oil offset partially by a 10.6 percent decline in the average price of natural gas. The price received for crude oil increased to $70.31 per barrel in 2007 from $64.69 per barrel in 2006 while natural gas prices decreased to $6.75 per MCF in 2007 from $7.55 per MCF in 2006.
The fourth quarter saw a substantial increase in gross revenues of $2,779,000 over quarter three due to increased production and increased commodity prices. Production in the fourth quarter averaged 4,295 BOE's per day compared to 4,088 in the third quarter. Also the average price received in the fourth quarter for crude oil and natural gas liquids was $77.60 ($73.68 third quarter) per barrel and $6.70 ($5.47 third quarter) per MCF for natural gas.
Although the Trust received higher net commodity prices in 2007 than in 2006, increases in the price of U.S. WTI oil prices and U.S. Nymex natural gas prices were partially offset by the rising Canadian dollar. The negative impact of the rising Canadian dollar on 2007's cash flow from operations was approximately 26 cents per unit and approximately 24 cents per unit on net earnings.
Included in gross revenue is a realized gain on risk management contracts of $621,000 (2006 - ($62,000)) due to higher prices received as a result of price hedging. The Trust also reported an unrealized loss on risk management contracts of $3,085,000 due to the elimination of hedge accounting effective October 1, 2007. With the property swap of the Dodsland property the Trust has reduced its hedging percentage to approximately 25 percent of its anticipated forward production.
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, 2008 Crude Oil 1,000 barrels WTI Floor of $73.00
to June 30, 2008 and ceiling of
$83.00 per
barrel
July 1, 2008 to
December 31, 2008 Crude Oil 500 barrels WTI Floor of $73.00
and ceiling of
$80.68 per
barrel
November 1, 2007
to March 31, 2008 Natural Gas 2,000 GJ's AECO Floor of $6.50
and ceiling of
$10.37 per GJ
Subsequent to December 31, 2007 and up to the date of this report the
Trust has entered into the following commodity hedging transactions:
Volume
Period of Agreement Commodity per day Index Price (Cdn.)
------------------- --------- ------- ----- ------------
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 at December 31, 2007 the fair value of the outstanding commodity hedging contracts was a net liability of $3,085,000 (December 31, 2006 - net asset $1,189,000).
Royalties
Royalties paid by the Trust consist primarily of Crown royalties paid to the Provinces of Alberta and Saskatchewan. During 2007 the Trust paid $9,209,000 (2006 - $8,156,000) in Crown royalties and $3,235,000 (2006 - $1,996,000) in freehold royalties, gross overriding royalties and net carried interests. The majority of the Trust's wells are low productivity wells and therefore have low Crown royalty rates. The Trust's average Crown royalty rate is approximately ten percent (2006 - ten percent) and approximately three percent (2006 - two percent) for other royalties before hedging adjustments.
During 2007, the Trust was advised by the owner of a gross overriding royalty that the production limit, resulting in an additional gross overriding royalty in respect of certain of its Cardium oil wells, had been reached. The production limit was triggered by a calculation on a multitude of Cardium wells including many that were not owned by the Trust. In addition the exact wells that the production limit was applicable to was not readily known by the Trust nor easily determined. In discussions with the payee it was determined that the production limit was reached in late 2005. The royalty has been calculated based on this agreed date and the affected wells for Bonterra and other operators in the area were identified. The approximate amount of the adjustment, net to the Trust is $570,000 for periods prior to January 1, 2007, and this amount has been included in the 2007 royalties figure. The monthly amount of the royalty on a go forward basis is approximately $55,000 per month based on current pricing and production levels.
Also in 2007 the Trust was informed by the operator of its Dodsland property that it had not been charged a net profit royalty for the years 2004, 2005 and 2006. In review of the agreements it was confirmed no payment was made and an amount of approximately $150,000 was paid by the Trust for the net profit royalty. This amount has been included in the 2007 royalty figure.
Royalty rates in the fourth quarter averaged approximately 13 percent; slightly higher than preceding quarters. The asset swap of the Dodsland properties for the Pembina properties resulted in an increase of approximately one percent in the average royalty rate for the Trust.
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; however this program was discontinued by the Alberta Government effective January 1, 2007 which resulted in a reduction of revenue of $500,000 in 2007.
Production Costs
Production costs totalled $24,073,000 in 2007 compared to $22,238,000 in 2006. On a barrel of oil equivalent (BOE) basis 2007 operating costs were $15.64 compared to $15.07 for 2006. 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 acquired Pembina properties from the swap as well as on the newly drilled wells are significantly lower on a BOE basis than on its Dodsland property and this may result in lower operating costs per BOE in the future.
Operating costs were $5,535,000 in the fourth quarter of 2007 compared to $6,401,000 in the third quarter. The decrease was due primarily to the above mentioned asset swap which resulted in approximately $375,000 less operating costs as well as an approximate $300,000 operating cost adjustment related to previously expensed surface lease payments that pertained to periods subsequent to the closing date of the asset swap.
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.
With the asset exchange, the Trust anticipates operating costs in the $13.50 to $14.50 per BOE range for 2008. The higher operating costs for the Trust are substantially offset by low royalty rates of approximately 13 percent, which is much lower than industry average for conventional production and on a combined basis results in high cash net backs despite higher than average operating costs.
General and Administrative Expense
General and administrative expenses were $2,603,000 in 2007 compared to $2,295,000 in 2006. On a BOE basis, general and administrative expenses in 2007 averaged $1.69 compared to $1.56 per BOE in 2006. The Trust is managed internally. In addition, the Trust provides administrative services to Comaplex Minerals Corp. (Comaplex) and Pine Cliff Energy Ltd. (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 costs are employee compensation and professional services such as legal, engineering and audit. Employee compensation expense increased by approximately 8.5 percent ($252,000). This increase has been partially offset by increased overhead recoveries charged to operations and capital programs. Costs associated with professional services increased by approximately $450,000. Of this increase approximately $340,000 related to the evaluation of several organizational options. This review was part of the Trust's continuing examination of means to address the changes resulting from the federal government's taxation of Trust's announcement on October 31, 2006 and enacted into law in 2007. The balance of the increase pertained to increased costs associated with producing the Trust's engineering report as well as fees related to the audit and continuous disclosure requirements.
The fourth quarter general and administrative expenses were $34,000 lower than the third quarter. The decrease was primarily due to the Trust incurring costs of $275,000 for professional fees in the third quarter for services discussed above offset partially by an increase in the fourth quarter bonus amount and increased cost adjustments related to engineering and audit services.
Interest Expense
Interest expense for the 2007 fiscal year of the Trust was $3,028,000 (2006 - $1,610,000). The increase was due to increased loan balances resulting from the Trust's 2006 and 2007 capital programs. Interest rates during the year on the outstanding debt averaged approximately 5.9 (2006 - 5.3) percent. The Trust maintained an average outstanding debt balance of approximately $51,600,000 (2006 - $31,000,000). Total debt (including negative working capital) as of December 31, 2007 represents approximately 13.1 months of 2007 annual adjusted distribution base or 11.1 months based on annualized 2007 fourth quarter adjusted distribution base. The ratio of bank debt only as of December 31, 2007 based on the annualized 2007 Q4 base was 10.9 months.
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 allow it to take advantage in the future of either acquisition opportunities or to provide flexibility to develop its infill oil, shallow gas and CBM potential without requiring the issuance of trust units. The Trust's December 31, 2007 debt level including working capital is slightly below this level.
The Trust's current bank agreements for the Trust's wholly owned operating subsidiaries (each of Bonterra Energy Corp (Bonterra Corp.), and Novitas Energy Ltd. (Novitas) have their own) provide for a combined $69,900,000 (December 31, 2006 - $49,900,000) of available credit facility. Bank debt at December 31, 2007 was $57,422,000 (December 31, 2006 - $45,379,000). 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 Option Based Compensation
Unit option 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.
In 2007, the Trust issued 553,000 unit options of which 517,000 were issued at the end of June 2007 at an average price of $28.31 and a fair value of $2.75 per unit. The fair value of the options granted has been estimated using the Black-Scholes option pricing model, assuming a weighted risk free interest rate of 4.7 (2006 - 4.1) percent, expected weighted average volatility of 27 percent (2006 - 27), expected weighted average life of 2.3 years (2006 - 2.5) and an annual dividend rate based on the distributions paid to the Unitholders during the year. The future unit based compensation impact of these options is approximately $250,000 per quarter over the next four quarters.
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.
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, 2007, the estimated total undiscounted amount required to settle the asset retirement obligations was $54,622,000 (2006 - $46,434,000). Of the $8,188,000 increase, approximately $2.7 million is due to the asset swap (the Dodsland property had no asset retirement obligation associated with it as the Trust had the option of transferring back the title to the wells to a third party who would then inherit this obligation).
These obligations will be settled based on the useful lives of the underlying assets, which extend up to 50 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 $2,504,000, while a one percent decrease in the risk adjusted rate would increase the asset retirement obligation by $3,430,000.
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, 2007, the Trust expensed $16,675,000 (2006 - $15,393,000) for the above-described items including $3,078,000 (2006 - $2,919,000) for dry hole costs. During 2007 the Trust wrote off all costs related to 8 wells drilled during the period 2004-2006 since the independent third party engineers did not attribute any reserves to them as well as some 2007 carryover costs related to wells written off in 2006. As of December 31, 2007 all capitalized costs have been assigned reserves and in the future any facilities that do not have reserves attributed to them will be written off.
The Trust has experienced a significant reduction in finding and development costs during the current year (see discussion under Finding and Development Costs) resulting in a marginal decrease in costs per barrel of reserves. Based on year end reserves, the Trust's average cost of proved reserves is $5.84 (2006 - $5.95) per BOE.
The Trust currently has an estimated reserve life for its proved developed producing reserves of 11.3 (2006 - 11) years calculated using the Trust's gross reserves (prior to allowance for royalties) based on the third party engineering report dated December 31, 2007 and using fourth quarter 2007 average production rates of 4,295 BOE's (2006 - 4,119 BOE's). Based on total proved reserves the Trust has a 13.7 (2006 - 13.6) year reserve life and if proved and probable are used the reserve life increases to 17.4 (2006 - 17.6) years. These figures are some of the longest (excluding oil sands) reserve life indexes in the Trust sector.
Taxes
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, are claimed as a deduction by the Trust in arriving at taxable income whereby tax is eliminated at the Trust level and the 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 28 (previously 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.
Future income tax expense for 2007 increased by a one time adjustment of $4,076,000, with a corresponding increase to the future tax liability as a result of the June 2007 enactment. 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.
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 effect even though it is anticipated that many trusts will change their organizational structure to attempt to reduce this impact.
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 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 current resource surcharge rate of 3.3 percent to 3.1 percent on July 1, 2007 and to 3.0 percent on July 1, 2008.
The Trust's subsidiaries have the following tax pools, which may be used to reduce taxable income in future years, limited to the applicable rates of utilization:
Rate of
Utilization
% Amount
-------------------------------------------------------------------------
Undepreciated capital costs 20-100 $16,921,000
Canadian oil and gas property expenditures (COGPE) 10 1,771,000
Canadian development expenditures (CDE) 30 30,431,000
Canadian exploration expenditures (CEE) 100 93,000
Income tax losses carried forward(1) 100 15,056,000
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$64,272,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Income tax losses carried forward expire in 2014 ($635,000), 2015
($3,574,000), 2026 ($4,826,000) and 2027 ($6,021,000).
The Trust itself has the following tax pools, which may be used in
reducing future taxable income allocated to its Unitholders:
Rate of
Utilization
% Amount
-------------------------------------------------------------------------
COGPE 10 $14,409,000
Finance costs 20 339,000
Eligible capital expenditures 7 348,000
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$15,096,000
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The Canadian tax breakdown of distributions for the 2007 taxation year is
as follows:
Percentage
-----------
Taxable Income (Other Income) 91.45
Return of Capital 8.55
-----------
100.00
-----------
With respect to cash distributions paid during the year to U.S. individual unitholders, 7.9 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 92.1 percent should be reported as qualified dividends.
During the fourth quarter the Trust reported a future tax recovery of $133,000 compared to a future tax recovery of $1,110,000 in the third quarter. The difference of $977,000 relates to the significant increase in the adjusted distribution base to $15,842,000 (Q3 - $13,149,000) as well as increased capital spending of $7,213,000 (Q3 - $2,763,000) while only increasing the Trust's debt level by $828,000. The impact of the above was that the corporate subsidiaries had to claim maximum CDE and tangible tax pools deductions as well as reducing their loss carryforwards during the fourth quarter to cover the additional income left in the subsidiaries.
Net Earnings
The Trust's net earnings of $30,350,000 for the year ended December 31, 2007 represents a decrease of $6,990,000 over the Trust's 2006 net earnings of $37,250,000. The Trust recorded net earnings per unit on a fully diluted basis in 2007 of $1.79 versus $2.21 in the 2006 year. This represents a return on Unitholders' equity of approximately 68.6 (2006 - 69.8) percent based on year end Unitholders' equity.
The enacting of the trust taxation legislation resulted in a one time adjustment of $4,076,000 for future income tax expense which is the predominant reason for the decline in net earnings. Strong crude oil prices along with a 4.4 percent increase in production volumes were offset with a 10.6 percent decrease in the price of natural gas, increased operating costs and depletion claims due to higher production volumes and increased interest costs. The Trust returned in excess of 33 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 net backs in the industry (see cash netback).
Comprehensive Income
On January 1, 2007 the Trust became obliged to adopt the new accounting standards regarding the accounting for financial instruments. On adoption the Trust increased its investment in related party by $1,836,000 for the fair value of this investment. On January 1, 2007 the Trust further recognized a current asset of $1,189,000 for the fair value of its commodity derivative contracts. These adjustments resulted in a further increase in the future income tax liability and accumulated other comprehensive income of $645,000 and $2,380,000 respectively.
Other comprehensive income for 2007 included an increase in the unrealized gain on investment in a related party of $1,465,000 ($295,000 in the fourth quarter), a reduction of $814,000 relating to the recognition and transfer of previously reported hedging gains in accumulated other comprehensive income. Effective October 1, 2007, the Trust discontinued the use of hedge accounting due to the difficulty in determining the effective portion of the commodity hedges. All of the above adjustments are net of applicable income tax effects.
Standardized Distributable Cash
Compliance with Guidance
The following 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
(July 1,
Year Ended Year Ended 2001 to
December 31, December 31, December 31,
2007 2006 2007)
-------------------------------------------------------------------------
Cash Flow from Operating
Activities $ 51,433,000 $ 51,944,000 $218,275,000
-------------------------------------------------------------------------
Less adjustment for:
-------------------------------------------------------------------------
Capital expenditures (19,300,000) (37,598,000) (94,498,000)
-------------------------------------------------------------------------
Financing restrictions
caused by debt - - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Standardized
Distributable Cash $ 32,133,000 $ 14,346,000 $123,777,000
-------------------------------------------------------------------------
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Definition and Disclosure of Adjusted Distribution Base (Formerly Funds
Flow from Operations)
-------------------------------------------------------------------------
Cumulative
Amounts From
Inception
of Trust
(July 1,
Year Ended Year Ended 2001 to
December 31, December 31, December 31,
2007 2006 2007)
-------------------------------------------------------------------------
Standardized Distributable
Cash - per above $ 32,133,000 $ 14,346,000 $123,777,000
-------------------------------------------------------------------------
Adjusted for:
-------------------------------------------------------------------------
Capital expenditures 19,300,000 37,598,000 94,498,000
-------------------------------------------------------------------------
Gain on sale of property - 532,000 1,089,000
-------------------------------------------------------------------------
Changes in accounts
receivable 1,082,000 147,000 5,576,000
-------------------------------------------------------------------------
Changes in crude oil
inventory (51,000) 7,000 253,000
-------------------------------------------------------------------------
Changes in parts inventory 18,000 (107,000) (190,000)
-------------------------------------------------------------------------
Changes in prepaid expenses 244,000 305,000 498,000
-------------------------------------------------------------------------
Changes in accounts payable
and accrued Liabilities 269,000 (793,000) 1,863,000
-------------------------------------------------------------------------
Asset retirement
obligations settled 820,000 762,000 2,529,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Adjusted Distribution Base
(formerly Funds Flow from
Operations)(1) $ 53,815,000 $ 52,797,000 $229,893,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Adjusted distribution base (formerly funds flow from operations) is
not a recognized measure under GAAP. The Trust believes that in
addition to net earnings, adjusted distribution base 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 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 the 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 material
seasonality impact in working capital.
Analysis of Relationship between Standardized Distributable Cash,
Distributions, and Investing and Financing Activities
-------------------------------------------------------------------------
Year ended Year ended Year ended
December 31, December 31, December 31,
2007 2006 2005
-------------------------------------------------------------------------
Standardized
Distributable Cash $ 32,133,000 $ 14,346,000 $ 23,413,000
-------------------------------------------------------------------------
Distributions ($44,648,000) ($47,281,000) ($38,949,000)
-------------------------------------------------------------------------
Increase in bank debt $ 12,043,000 $ 25,202,000 $ 11,717,000
-------------------------------------------------------------------------
Proceeds on exercise of
employee unit options $ 993,000 $ 5,161,000 $ 2,823,000
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Issuance of units
(net of costs of issue) - - ($259,000)
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Non cash financing and
investing working capital
adjustments ($521,000) $ 2,572,000 $ 1,255,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The only unfunded operating transaction of the Trust is its asset
retirement obligations. The Trust has the following estimated timing of
expenditures for asset retirement obligations:
Expected
Year Expenditure
----------------------------------------------------------
2008 $ 296,000
2009 517,000
2010 529,000
2011 563,000
2012 856,000
----------------------------------------------------------
----------------------------------------------------------
$ 2,761,000
----------------------------------------------------------
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Definition and History of Productive Capacity and Strategy
Bonterra's primary objective is to grow its reserves from which it expects
to generate cash flow so it will be able to continue with distributions for
its unitholders. 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.
-------------------------------------------------------------------------
Year Ended Year ended Year ended
December 31, December 31, December 31,
2007 2006 2005
-------------------------------------------------------------------------
Proven and probable
reserves at beginning of
period (BOE's) 26,476,000 23,870,000 19,711,000
-------------------------------------------------------------------------
Reserves added due to
acquisitions (net of
disposals) (BOE's) (421,000) 16,000 2,393,000
-------------------------------------------------------------------------
Reserves added due to capital
expenditures (BOE's) 2,806,000 4,082,000 3,100,000
-------------------------------------------------------------------------
Production during period
(BOE's) 1,540,000 1,476,000 1,334,000
-------------------------------------------------------------------------
Increase in productive
capacity (BOE's) 845,000 2,622,000 4,159,000
-------------------------------------------------------------------------
Reserves per unit (fully
diluted) 1.62 1.57 1.46
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Productive capacity
maintenance requirements $ 17,043,000 $ 17,472,000 $ 9,205,000
-------------------------------------------------------------------------
Capital expenditures for
the period $ 19,300,000 $ 38,348,000 $ 56,703,000
-------------------------------------------------------------------------
Capital expenditures in
excess of maintenance
requirements $ 2,257,000 $ 20,876,000 $ 47,498,000
-------------------------------------------------------------------------
Cost of increased productive
capacity (per BOE) $ 2.67 $ 8.01 $ 11.42
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 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 exceed the level of funds withheld. However, the Trust with its long life reserves and relatively low debt levels compared to other income trusts has the flexibility to increase or decrease its capital commitments depending on commodity prices and costs of development.
It is management's strategy to finance the costs of reclamation as well as potential income taxes (commencing in 2011) resulting from the recently enacted income trust tax law from 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
(July 1,
Year Ended Year Ended 2001 to
December 31, December 31, December 31,
2007 2006 2007)
-------------------------------------------------------------------------
Standardized
Distributable Cash $ 32,133,000 $ 14,346,000 $123,777,000
-------------------------------------------------------------------------
Per weighted average unit $ 1.90 $ 0.86 $ 8.01
-------------------------------------------------------------------------
Per fully diluted unit $ 1.90 $ 0.85 $ 7.96
-------------------------------------------------------------------------
Cash distributions $ 44,648,000 $ 47,281,000 $204,299,000
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Payout ratio 1.39 3.30 1.65
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Adjusted Distribution Base $ 53,815,000 $ 52,797,000 $229,893,000
-------------------------------------------------------------------------
Per weighted average unit $ 3.18 $ 3.15 $ 14.93
-------------------------------------------------------------------------
Per fully diluted unit $ 3.18 $ 3.12 $ 14.82
-------------------------------------------------------------------------
Cash distributions $ 44,648,000 $ 47,281,000 $204,299,000
-------------------------------------------------------------------------
Payout ratio 0.83 0.90 0.89
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-------------------------------------------------------------------------
On a go forward basis the Trust plans to reduce the payout ratio in
respect of Standardized Distributable Cash to a level between 110 to
120 percent to facilitate a debt to adjusted distribution base level of
approximately one year and to incur no current income tax (excluding
Saskatchewan Resource Surcharge). This will be attained through continued
control of capital replacement costs, 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 Income Taxes.
Cash Netback
The following table illustrates the Trust's cash netback:
$ per Barrel of Oil Equivalent (BOE) 2007 2006
-------------------------------------------------------------------------
Production volumes (BOE) 1,539,461 1,475,639
-------------------------------------------------------------------------
Gross production revenue $ 62.64 $ 60.13
Royalties (8.08) (7.12)
Field operating (15.64) (15.07)
-------------------------------------------------------------------------
Field netback 38.92 37.94
General and administrative (1.69) (1.56)
Interest and taxes (2.30) (1.34)
-------------------------------------------------------------------------
Cash netback $ 34.93 $ 35.04
-------------------------------------------------------------------------
The following table illustrates the Trust's cash netback for the three
months ended:
December 31 September 30
$ per Barrel of Oil Equivalent (BOE) 2007 2007
-------------------------------------------------------------------------
Production volumes (BOE) 395,154 375,962
-------------------------------------------------------------------------
Gross production revenue $ 67.25 $ 63.29
Royalties (8.39) (7.13)
Field operating (14.01) (17.02)
-------------------------------------------------------------------------
Field netback 44.85 39.14
General and administrative (1.87) (2.06)
Interest and taxes (2.89) (2.12)
-------------------------------------------------------------------------
Cash netback $ 40.09 $ 34.96
-------------------------------------------------------------------------
Finding and Development Costs (F&D Costs)
Bonterra has been active in its capital development program over the past
three years. Over this time period the Trust has incurred the following
finding and development costs:
-------------------------------------------------------------------------
2007 F&D 2006 F&D 2005 F&D 2007 Three 2006 Three
Costs per Costs per Costs per Year Year
BOE(1)(2) BOE(1)(2) BOE(1)(2) Average Average
-------------------------------------------------------------------------
Proved Reserve
Additions $2.74 $25.51 $14.86 $14.37 $15.90
-------------------------------------------------------------------------
Proved plus
Probable Reserve
Additions $2.68 $18.21 $12.33 $11.07 $11.84
-------------------------------------------------------------------------
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.
During 2007, Bonterra experienced an approximate 30 percent reduction in
drilling and completion costs. In addition, results from the Trust's Cardium
oil drilling program have been better than anticipated resulting in an
increase in the third party engineering reports estimated recoverable reserves
from existing wells but also from future development. Both these factors
contributed to an overall F&D cost in 2007 of $2.68 per proven and probable
reserve.
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
Total 1 year years years
-------------------------------------------------------------------------
Office lease $1,658,000 $289,000 $932,000 $437,000
-------------------------------------------------------------------------
Liquidity and Capital Resources
During 2007 the Trust participated in drilling 24 gross (16 net) wells at a total cost of $18,595,000. Included in the above figure is approximately $7,000,000 of costs associated with the completion and tie-in of wells the Trust drilled in 2006 and prior years. An additional $1,200,000 was spent in 2008 to complete and tie-in the remaining 2007 drilled wells for an average cost of $760,000 per well. This compares to over $1.1 million per Cardium well in 2006.
As at December 31, 2007 Bonterra had 7 gross (6.3 net) Cardium oil wells, 2 gross (2 net) natural gas wells and 3 gross (2.5 net) CBM wells drilled but not on production. Subsequent to December 31, 2007 and up to the date of this report, Bonterra has put on production all the Cardium oil wells and 1 gross (1 net) shallow gas well. The timing for the eventual tie-in of the remaining natural gas and CBM wells has not yet been determined.
The Trust currently has plans to drill 25 gross (20 net) infill Cardium wells at an estimated budget figure of $800,000 per well. The Trust also plans on refracing 10 to 15 Cardium wells in 2008 to enhance current production. In addition, the Trust is currently examining an infill Edmonton Sand natural gas program. Total capital costs are anticipated to be approximately $20,000,000 for the planned development programs and tying in of the remaining 2007 drilled wells. The Trust anticipates funding the 2008 capital program out of current cash flow and exercising of employee unit options. This combination should allow for the Trust to maintain its debt to adjusted distribution base ratio at less than one.
Taxation of Trusts
In June, 2007 the October 31, 2006 proposals by the Minster of Finance for Canada for the taxation of existing income trusts were proclaimed into law. In summary the law provides that:
- 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 October of 2007 the Minister of Finance announced a
reduction in this rate to 29.5 percent for 2011 and 28 percent
thereafter.
In addition the Minister announced in October 2006 the government's attempt to limit the growth of existing income trusts. According to the announcement, 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 October 31, 2006 to December 31, 2010 by an amount that does not exceed the greater of $50 million and an objective "safe harbour" amount. The safe harbour amount is measured by reference to the trust's 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 trust's issued and outstanding publicly-traded units and its bank debt. For the period November 1, 2006 to December 31, 2007 an income trust's 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 in October 2006 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. None of the rules surrounding the safe harbour and conversion to a corporate form have been legislated.
The impact to individual unitholders of the above legislative changes 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 50 percent, twenty nine and a half percent (Twenty eight percent in 2012 and thereafter) 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 taxes, then generally a further 15 percent withholding is required and the non-residents must also pay their own taxes in their country of residence. This could result in excess of 55 percent being paid in taxes.
The Trust's management along with its professional advisors have been examining various options available to it to in respect of its long term strategic planning. The process continues to be complicated by the fact that significant proposals of the Minister's October 2006 announcement have not yet been legislative. In addition, the Trust has a diverse ownership base with approximately 24.8 percent of outstanding units held by non-residents as of January 2, 2008 (based on ADP Canada and ADP USA beneficial reports) and an estimated 15 percent held by deferred income plans with the rest held by taxable Canadian investors.
In the mean time the proposed safe harbour rules will allow Bonterra to raise in excess of $650,000,000 over the next three years without losing its tax free status before 2011. This will allow the trust to continue with its Cardium infill drilling program, its shallow natural gas and CBM development as well as potentially developing a CO(2) flood program or to make corporate or property acquisitions. The current emphasis will be placed on increasing the Trust's available tax pools to assist in dealing with the future tax consequences resulting from the taxation of trust legislation.
Sensitivity Analysis
Sensitivity analysis, as estimated for 2008:
Cash Flow
Cash Flow Per Unit
--------- --------
U.S. $1.00 per barrel $958,000 $0.056
Canadian $0.10 per MCF $213,000 $0.013
Change of Canadian $0.01/U.S. $ exchange rate $692,000 $0.041
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 2007 2006
Assets
Current
Accounts receivable (Note 9) $ 10,575,000 $ 10,486,000
Crude oil inventory 792,000 843,000
Parts inventory 132,000 114,000
Prepaid expenses 1,330,000 1,086,000
Future income tax asset (Note 5) 913,000 -
Investment in related party (Note 2) 4,014,000 461,000
-------------------------------------------------------------------------
17,756,000 12,990,000
-------------------------------------------------------------------------
Property and Equipment (Note 3)
Petroleum and natural gas properties
and related equipment 187,288,000 176,602,000
Accumulated depletion and depreciation (61,805,000) (54,650,000)
-------------------------------------------------------------------------
125,483,000 121,952,000
-------------------------------------------------------------------------
$143,239,000 $134,942,000
-------------------------------------------------------------------------
Liabilities
Current
Distribution payable $ 3,724,000 $ 4,050,000
Accounts payable and accrued liabilities 12,291,000 13,748,000
Derivative liability (Note 11) 3,085,000 -
Debt (Note 4) 57,422,000 45,379,000
-------------------------------------------------------------------------
76,522,000 63,177,000
Future income tax liability (Note 5) 7,595,000 3,587,000
Asset retirement obligations (Note 6) 14,904,000 14,819,000
-------------------------------------------------------------------------
99,021,000 81,583,000
-------------------------------------------------------------------------
Commitments, Contingencies and Guarantees
(Note 11)
Unitholders' Equity (Note 7)
Unit capital 90,590,000 89,488,000
Contributed surplus 2,140,000 1,116,000
-------------------------------------------------------------------------
92,730,000 90,604,000
-------------------------------------------------------------------------
Deficit (51,543,000) (37,245,000)
Accumulated other comprehensive
income (Note 8) 3,031,000 -
-------------------------------------------------------------------------
(48,512,000) (37,245,000)
-------------------------------------------------------------------------
Total Unitholders' Equity 44,218,000 53,359,000
-------------------------------------------------------------------------
$143,239,000 $134,942,000
-------------------------------------------------------------------------
Bonterra Energy Income Trust
Consolidated Statements of Unitholders' Equity
For the Years Ended December 31 2007 2006
Unitholders' equity, beginning of year $ 53,359,000 $ 57,322,000
Comprehensive income for the year 31,001,000 37,250,000
Adjustment of opening accumulated other
comprehensive income (Note 1) 2,380,000 -
Net capital contributions (Note 7) 993,000 5,161,000
Unit option based compensation adjustment 1,133,000 907,000
Distributions declared (44,648,000) (47,281,000)
-------------------------------------------------------------------------
Unitholders' Equity, End of Year $ 44,218,000 $ 53,359,000
-------------------------------------------------------------------------
Bonterra Energy Income Trust
Consolidated Statements of Operations
and Deficit
For the Years Ended December 31 2007 2006
Revenue
Oil and gas sales $ 95,810,000 $ 88,796,000
Realized gain (loss) on risk
management contracts 621,000 (62,000)
Unrealized loss on risk management
contracts (Notes 8 and 11) (3,085,000) -
Royalties (12,444,000) (10,512,000)
Alberta royalty tax credit - 487,000
Gain on sale of property (Note 3) - 532,000
Interest and other 44,000 66,000
-------------------------------------------------------------------------
80,946,000 79,307,000
-------------------------------------------------------------------------
Expenses
Production costs 24,073,000 22,238,000
General and administrative 2,603,000 2,295,000
Interest on debt 3,028,000 1,610,000
Unit option based compensation 1,133,000 907,000
Dry hole costs 3,078,000 2,919,000
Depletion, depreciation and accretion 13,597,000 12,474,000
-------------------------------------------------------------------------
47,512,000 42,443,000
-------------------------------------------------------------------------
Earnings Before Income Taxes 33,434,000 36,864,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Income taxes (recovery) (Note 5)
Current 512,000 367,000
Future 2,572,000 (753,000)
-------------------------------------------------------------------------
3,084,000 (386,000)
-------------------------------------------------------------------------
Net Earnings for the Year 30,350,000 37,250,000
Deficit, beginning of year (37,245,000) (27,214,000)
Distributions declared (44,648,000) (47,281,000)
-------------------------------------------------------------------------
Deficit, end of year ($51,543,000) ($37,245,000)
-------------------------------------------------------------------------
Net Earnings Per Trust Unit
- Basic (Note 7) $ 1.79 $ 2.23
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Earnings Per Trust Unit
- Diluted (Note 7) $ 1.79 $ 2.21
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Bonterra Energy Income Trust
Consolidated Statement of Comprehensive Income (Note 1)
For the Year Ended December 31 2007
Net Earnings for the Period $ 30,350,000
-------------------------------------------------------------------------
Other comprehensive income, net of income tax
Unrealized gains on investments
(net of income taxes of $252,000) 1,465,000
Gains and losses on derivatives designated as
cash flow hedges transferred to net earnings
(net of income taxes of ($334,000)) (814,000)
-------------------------------------------------------------------------
Other Comprehensive Income 651,000
-------------------------------------------------------------------------
Comprehensive Income $ 31,001,000
-------------------------------------------------------------------------
Comprehensive Income Per Trust Unit - Basic (Note 7) $ 1.83
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Comprehensive Income Per Trust Unit - Diluted (Note 7) $ 1.83
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Bonterra Energy Income Trust
Consolidated Statements of Cash Flow
For the Years Ended December 31 2007 2006
Operating Activities
Net earnings for the year $ 30,350,000 $ 37,250,000
Items not affecting cash
Gain on sale of property - (532,000)
Unrealized loss on risk management
contracts 3,085,000 -
Unit option based compensation 1,133,000 907,000
Dry hole costs 3,078,000 2,919,000
Depletion, depreciation and accretion 13,597,000 12,474,000
Future income taxes (recovery) 2,572,000 (753,000)
-------------------------------------------------------------------------
53,815,000 52,265,000
-------------------------------------------------------------------------
Change in non-cash working capital
Accounts receivable (1,082,000) (147,000)
Crude oil inventory 51,000 (7,000)
Parts inventory (18,000) 107,000
Prepaid expenses (244,000) (305,000)
Accounts payable and accrued liabilities (269,000) 793,000
Asset retirement obligations settled (820,000) (762,000)
-------------------------------------------------------------------------
(2,382,000) (321,000)
-------------------------------------------------------------------------
51,433,000 51,944,000
-------------------------------------------------------------------------
Financing Activities
Increase in debt 12,043,000 25,202,000
Unit option proceeds 993,000 5,161,000
Unit distributions (44,974,000) (46,869,000)
-------------------------------------------------------------------------
(31,938,000) (16,506,000)
-------------------------------------------------------------------------
Investing Activities
Property and equipment expenditures (19,300,000) (38,348,000)
Proceeds on sale of property - 750,000
Change in non-cash working capital
Accounts receivable 993,000 681,000
Accounts payable and accrued liabilities (1,188,000) 1,479,000
-------------------------------------------------------------------------
(19,495,000) (35,438,000)
-------------------------------------------------------------------------
Net cash inflow - -
Cash, beginning of year - -
-------------------------------------------------------------------------
Cash, End of Year $ - $ -
-------------------------------------------------------------------------
Cash Interest Paid $ 3,028,000 $ 1,610,000
Cash Taxes Paid $ 292,000 $ 393,000
Bonterra Energy Income Trust
Notes to the Consolidated Financial Statements
For the Years Ended December 31, 2007 and 2006
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) and Novitas Energy Ltd. (Novitas).
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.
Financial instruments - recognition and measurement
On January 1, 2007, the Trust adopted Section 3855 of the Canadian
Institute of Chartered Accountants ("CICA") Handbook, "Financial
Instruments - Recognition and Measurement" and Section 3861 "Financial
Instruments - Disclosure and Presentation". These set out the standards
for recognizing and measuring financial instruments in the balance sheet
and the standards for reporting gains and losses in the financial
statements. Financial assets available for sale, assets and liabilities
held for trading and derivative financial instruments, whether part of a
hedging relationship or not, have to be measured at fair value.
The Trust has made the following classifications:
- Investment in related party is classified as available for sale and
recorded at fair value which is marked-to-market through
comprehensive income.
- Accounts receivable are classified as loans and receivables and are
recorded at amortized cost using the effective interest method. Gains
and losses are recognized in net earnings when the asset is no longer
recognized.
- Accounts payable and accrued liabilities and bank debt are classified
as other liabilities and are recorded at amortized cost using the
effective interest method. Gains and losses are recognized in net
earnings when the liability is no longer recognized.
The adoption of the Sections is done retrospectively without restatement
of the consolidated financial statements of prior periods. As at
January 1, 2007, the impact on the consolidated balance sheet of
measuring the investment in related party at fair value was an increase
of $1,836,000 to investment in a related party, an increase in future
income tax liability of $270,000 and an increase in accumulated other
comprehensive income of $1,566,000.
The impact on the consolidated balance sheet of measuring hedging
derivatives at fair value at January 1, 2007 was an increase in other
assets of $1,189,000, an increase in future tax liability of $375,000 and
an increase in accumulated other comprehensive income of $814,000. As of
October 1, 2007, the Trust discontinued the used of hedge accounting (see
Note 8).
The Trust selected January 1, 2003 as its transition date for embedded
derivatives. An embedded derivative is a component of a financial
instrument or another contract the characteristics of which are similar
to a derivative. This had no impact on the consolidated financial
statements.
Comprehensive income
On January 1, 2007, the Trust adopted Section 1530 of the CICA Handbook,
"Comprehensive Income". This section describes reporting and disclosure
recommendations with respect to comprehensive income and its components.
Comprehensive income is the change in unitholders' equity, which results
from transactions and events from sources other than the Trust's
unitholders and consists of net income and other comprehensive income
("OCI"). OCI comprises revenues, expenses, gains and losses that are
recognized in comprehensive income but excluded from net income. Such
items include unrealized gains and losses from changes in fair value of
certain financial instruments.
The adoption of this section results in the Trust presenting a
consolidated statement of comprehensive income as a part of the
consolidated financial statements.
Equity
On January 1, 2007, the Trust adopted Section 3251 of the CICA Handbook
"Equity" replacing Section 3250 "Surplus". This section describes
standards for the presentation of equity and changes in equity for
reporting periods as a result of the application of Section 1530
"Comprehensive Income".
Hedges
On January 1, 2007, the Trust adopted Section 3865 of the CICA Handbook
"Hedges". The recommendations of this Section expand the guidelines
required by Accounting Guideline 13 (AcG-13), Hedging Relationships. This
section describes when and how hedge accounting can be applied as well as
the disclosure requirements. Hedge accounting enables the recording of
gains, losses, revenues and expenses from the derivative financial
instrument in the same period as those related to the hedged item.
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.
Accounting changes
The Trust also adopted Section 1506, "Accounting Changes," whereby the
only impact is to provide disclosure of when an entity has not applied a
new source of GAAP that has been issued but is not yet effective. This is
the case with Section 1535, "Capital Disclosures", Section 3862,
"Financial Instruments Disclosures" and Section 3863, "Financial
Instruments - Presentation" which are required to be adopted for fiscal
years beginning on or after October 1, 2007. The Trust will adopt these
standards on January 1, 2008 and it is expected that the only effect on
the Trust will be incremental 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.
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 is
currently evaluating the impact of the adoption of this new Section on
its consolidated financial statements. The Trust does not expect that the
adoption of this new Section will have a material impact on its
consolidated financial statements.
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 fair value. In 2006 the investments were
recorded at 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 and
its 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 income tax liabilities and assets is recognized in income in the
period in which the change occurs.
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 Option Based Compensation
The Trust has a unit option 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.
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
The investment consists of 689,682 (December 31, 2006 - 689,682) common
shares in Comaplex Minerals Corp (Comaplex), a company with common
directors and management with the Trust and its subsidiaries. The
investment is recorded at fair market value (December 31, 2006 -
$2,297,000). The common shares trade on the Toronto Stock Exchange under
the symbol CMF. The investment represents less than a one and a half
percent ownership in the outstanding shares of Comaplex.
3. PROPERTY AND EQUIPMENT
2007 2006
-------------------------------------------------------------------------
Accumulated Accumulated
Depletion and Depletion and
Cost Depreciation Cost Depreciation
-------------------------------------------------------------------------
Undeveloped land $ 316,000 $ - $ 334,000 $ -
Petroleum and
natural gas
properties and
related
equipment 185,947,000 61,105,000 175,353,000 54,008,000
Furniture,
equipment and
other 1,025,000 700,000 915,000 642,000
-------------------------------------------------------------------------
$187,288,000 $ 61,805,000 $176,602,000 $ 54,650,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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.
4. DEBT
The Trust has a bank revolving credit facility of $69,900,000 at
December 31, 2007 (2006 - $49,900,000). The terms of the credit facility
provide that the loan is due on demand and is subject to annual review.
The credit facility has no fixed payment requirements. The amount
available for borrowing under the credit facility is reduced by
outstanding letters of credit. Letters of credit totalling $340,000
(December 31, 2006 - $340,000) were issued at December 31, 2007. 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, 2007 for this loan was $3,021,000 (2006 -
$1,610,000).
5. TAXES
The Trust has recorded a future income tax liability and a current future
income tax asset related to assets and liabilities and related tax
amounts. The following 2007 figures reflect the consequences of the
Canadian Federal Government's October 31, 2006 announcement on the future
taxation of Income Trusts and the enactment of those proposals in 2007:
2007 2006
-------------------------------------------------------------------------
Future income tax liability related to
assets and liabilities: $ 11,517,000 $ 6,233,000
Future tax asset related to finance costs: (79,000) -
Future tax asset related to corporate tax
losses carried forward in the
subsidiary companies (3,843,000) (2,646,000)
-------------------------------------------------------------------------
Future income tax liability $ 7,595,000 $ 3,587,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Future income tax asset related to current
portion of derivative liability $ 913,000 $ -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Income tax expense varies from the amounts that would be computed by
applying Canadian federal and provincial income tax rates as follows and
the federal government's rate reduction enacted in December 2007:
2007 2006
-------------------------------------------------------------------------
Earnings before taxes $ 33,434,000 $ 36,864,000
Combined federal and provincial
income tax rates 32.27% 34.97%
-------------------------------------------------------------------------
Income tax provision calculated using
statutory tax rates 10,789,000 12,891,000
Increase (decrease) in taxes resulting from:
Saskatchewan resource surcharge 512,000 367,000
Unit-based compensation 366,000 317,000
Non-deductible crown royalties - 1,072,000
Resource allowance - (1,901,000)
Change in effective tax rate of the Trust 4,076,000 -
Trust income allocated to Unitholders (13,176,000) (13,031,000)
Others 517,000 (123,000)
-------------------------------------------------------------------------
Income tax expense (recovery) $ 3,084,000 $ (386,000)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 $16,921,000
Canadian oil and gas property expenditures 10 1,771,000
Canadian development expenditures 30 30,431,000
Canadian exploration expenditures 100 93,000
Income tax losses carried forward(1) 100 15,056,000
-------------------------------------------------------------------------
$64,272,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Income tax losses carried forward expire in 2014 ($635,000), 2015
($3,574,000), 2026 ($4,826,000) and 2027 ($6,021,000).
The Trust has the following tax pools, which may be used in reducing
future taxable income allocated to its Unitholders:
Rate of
Utilization
% Amount
-------------------------------------------------------------------------
Canadian oil and gas property expenditures 10 $14,409,000
Finance costs 20 339,000
Eligible capital expenditures 7 348,000
-------------------------------------------------------------------------
$15,096,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
On October 31, 2006, the Canadian Federal Government announced a proposed
Trust taxation pertaining to taxation of distributions paid by publicly
traded income trusts and this was enacted by legislation in June, 2007.
Previously, distributions paid to unitholders, other than returns of
capital, were claimed as a deduction by the Trust in arriving at taxable
income whereby tax is eliminated at the Trust level and 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.
Prior to June 2007, the Trust estimated the future income tax on certain
temporary differences between amounts recorded on its balance sheet for
book and tax purposes at a nil effective tax rate. The entire balance of
the future income tax liability reported related to assets and
liabilities and related tax amounts held through the Trust's 100 percent
held subsidiaries. Under the legislation, the Trust now estimates the
effective tax rate on post-2010 reversal of these temporary differences
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 December 31, 2007, the Trust
has estimated the amount of its temporary differences which were
previously not subject to tax and estimated the periods in which these
differences will reverse. The Trust estimates that $14,496,000 net
taxable temporary differences will reverse after January 1, 2011,
resulting in an additional $4,076,000 future income tax liability. The
taxable temporary differences relate principally to the excess of net
book value of oil and gas properties over the remaining tax pools
attributable thereto.
As the legislation gives rise to a change in the Trust's estimated future
income tax liability in the period, the recognition of the additional
liability is accounted for prospectively in the period and an additional
$4,076,000 of future income tax expense has been recorded for the period.
While the Trust believes it will be subject to additional tax under the
new legislation, the estimated effective tax rate on temporary difference
reversals after 2011 may change in future periods. As the legislation is
new, future technical interpretations of the legislation could occur and
could materially affect management's estimate of the future income tax
liability.
The amount and timing of reversals of temporary differences will also
depend on the Trust's future operating results, acquisitions and
dispositions of assets and liabilities, and distribution policy. A
significant change in any of the preceding assumptions could materially
affect the Trust's estimate of the future income tax liability.
6. ASSET RETIREMENT OBLIGATIONS
At December 31, 2007, the estimated total undiscounted amount required to