Bonterra Energy Corp. Announces Fourth Quarter and Annual 2009 Results
Annual Highlights
2009 2008 2007
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Financial ($000, except $ per share/unit)
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Revenue - realized oil and gas 85,712 121,730 96,431
Cash flow from operations 38,893 69,570 51,433
Per Share/Unit Basic 2.16 4.07 3.04
Per Share/Unit Diluted 2.15 4.06 3.04
Payout Ratio(1) 79% 77% 87%
Funds Flow(2) 66,504 70,448 53,815
Per Share/Unit Basic 3.69 4.13 3.18
Per Share/Unit Diluted 3.67 4.12 3.18
Payout Ratio(1) 46% 76% 83%
Cash payments per share/unit(1) 1.70 3.12 2.64
Net Earnings 68,563 55,426 30,350
Per Share/Unit Basic 3.81 3.25 1.79
Per Share/Unit Diluted 3.78 3.23 1.79
Capital Expenditures and Acquisitions
(net of disposals) 5,640 45,407 19,300
Total assets 293,987 265,301 142,326
Working Capital Deficiency 10,162 23,878 58,766
Long-term Debt 59,823 79,910 -
Shareholders'/Unitholders' Equity 118,874 56,777 44,376
Shares/Units Outstanding 18,620 17,258 16,928
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Operations
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Oil and Liquids (barrels per day) 3,141 3,073 3,113
Average Price ($ per barrel) 59.82 87.54 70.31
Natural Gas (MCF per day) 11,120 7,637 6,627
Average Price ($ per MCF) 4.15 8.21 6.75
Total BOE per day(3) 4,994 4,346 4,218
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Reserves
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Oil and Liquids (barrels in 000s)
Proved Developed Prducing (Gross)(4) 15,519 15,534 14,468
Proved (Gross) 19,220 17,991 17,472
Proved plus Probable (Gross) 27,568 22,867 21,910
Natural Gas (MCF in 000s)
Proved Developed Prducing (Gross) 32,103 32,108 19,863
Proved (Gross) 36,642 36,571 24,125
Proved plus Probable (Gross) 49,539 50,245 32,465
Reserve Life Index(5) (oil, liquids
and natural gas at 6:1) (years)
Proved Developed Prducing (Gross) 11.7 12.5 11.3
Proved (Gross) 14.2 14.4 13.7
Proved plus Probable (Gross) 20.1 18.7 17.4
Reserves per Weighted Average Outstanding
Share/Unit (BOE)
Proved Developed Prducing (Gross) 1.16 1.22 1.05
Proved (Gross) 1.41 1.41 1.27
Proved plus Probable (Gross) 1.99 1.83 1.62
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Quarterly Highlights
2009 4th 3rd 2nd 1st
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Financial ($ 000s, except $ per share)
Revenue - realized oil and gas sales 24,946 20,965 20,501 19,300
Cash flow from operations 13,673 9,350 9,238 6,632
Per Share Basic 0.76 0.50 0.52 0.38
Per Share Diluted 0.75 0.50 0.52 0.38
Payout Ratio(1) 66% 87% 77% 94%
Funds Flow(2) 37,595 10,753 9,780 8,376
Per Share Basic 2.07 0.58 0.55 0.49
Per Share Diluted 2.06 0.57 0.55 0.49
Payout Ratio(1) 24% 76% 73% 74%
Cash payments per share(1) 0.50 0.44 0.40 0.36
Net Earnings 52,136 5,790 4,544 6,093
Per Share Basic 2.88 0.32 0.26 0.35
Per Share Fully Diluted 2.85 0.32 0.26 0.35
Capital Expenditures and
Acquisitions (16,976) 17,660 2,255 2,701
Total Assets 293,987 273,543 258,393 260,732
Working Capital Deficiency 10,162 14,455 13,989 14,909
Long-term debt 59,823 81,136 71,573 89,383
Shareholders' Equity 118,874 74,025 72,332 56,377
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Operations
Oil and Liquids (barrels per day) 3,182 3,084 3,029 3,268
Natural Gas (MCF per day) 10,193 10,881 11,551 11,877
Total BOE per day 4,881 4,898 4,954 5,245
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(1) Cash dividend/disbursement payments per share/unit are based on
payments made in respect of production months as opposed to the month
paid.
(2) Funds flow is not a recognized measure under GAAP. For these
purposes, the Company defines funds flow as funds provided by
operations before changes in non-cash operating working capital items
but including gain on sale of property and investment tax credit
receivable adjustments and excluding restricted cash and asset
retirement obligations settled.
(3) Barrels of oil equivalent (BOE) are calculated using a conversion
ratio of 6 MCF to 1 barrel of oil. The conversion is based on an
energy equivalency convervsion 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.
(4) Gross reserves relate to the Company's ownership of reserves
deducting any royalties.
(5) The reserve life index is calculated by dividing the reserves (BOE)
by the annualized fourth quarter average production rate
(2009 - 4,881; 2008 - 4,587 BOE per day; 2007 - 4,295 BOE per day).
Financial Highlights
- Revenue and funds flow from operations in 2009 decreased 30 percent
and 6 percent, respectively when compared to the prior year primarily
due to a 32 percent decrease in the Company's crude oil average
realized price and a 50 percent decrease in the Company's natural gas
average realized price partially offset by production increases and a
gain on asset sale of $24.2 million in Q4 2009. Commodity prices
showed improvement during the latter half of the year, mainly in
crude oil, and the fourth quarter numbers reflected a positive impact
with a 250 percent increase in funds flow from operations in the
fourth quarter of 2009 compared with the third quarter of 2009;
- In 2009, Bonterra paid cash dividends to shareholders of $1.70 per
share, a substantial decrease from the 2008 level of $3.12 per share.
Bonterra had reduced its dividend in early 2009 to maintain its
balance sheet strength and the financial flexibility necessary to
continue developing the Pembina Cardium horizontal play. As pricing
improved, Bonterra was able to increase the dividend twice during the
year. Subsequent to year-end, Bonterra was able to once again
increase the dividend to its current level of $0.18 per share which
began with the dividend paid out in January, 2010;
- The payout ratio was 46 percent of funds flow (72 percent without the
gain on asset sale of $24.2 million and within the Company's annual
target of 70 to 80 percent);
- During the year, Bonterra took several steps towards improving its
financial position. The Company entered into a new syndicated banking
facility effective April 29, 2009 consisting of a $100 million
syndicated revolving credit facility and a $20 million non-syndicated
revolving credit facility. In addition, Bonterra completed an equity
offering in May, 2009. The Company issued 1,068,000 common shares at
a price of $16.85 per share for net proceeds of approximately $17
million. Funds were used for the Company's capital program and for
general working capital purposes.
Operational Highlights
- In 2009, Bonterra spent approximately $35.2 million on its capital
development program of which $22.9 million was spent on its drilling
and completions program with the remainder spend on land and
corporate acquisitions in the Pembina area.
- Production increased to an all time high of 4,994 barrels of oil
equivalent (BOE) per day as a result of its internal development
program and acquisitions during the year. Fourth quarter production
totaled 4,881 BOE per day, an increase of eight percent over the same
period last year;
- Reserves increased to 25.3 million BOE and 35.8 million BOE on a
proved and a proved plus probable basis, respectively. This
represents an increase of 5.2 percent to the Company's proved
reserves and a 14.7 percent increase to proved plus probable
reserves;
- Reserves per share on a P+P basis increased 8.7 percent to 1.99 BOE
per share compared to 1.83 BOE per share in 2008 ;
- Bonterra's finding, development and acquisition (FD&A) costs in 2009
continue to be among the lowest in the Canadian oil and gas industry
at $13.25 per BOE on a total proved basis and $8.93 per BOE on a
proved plus probable basis.
- With an average cash netback of $23.42 per BOE, Bonterra's 2009
proved plus probable recycle ratio is 2.6 times.
- Bonterra completed asset sales in 2009 and in the first quarter of
2010, obtaining $35.8 million in dispositions from non-core assets in
Saskatchewan. This included the divestment of approximately 270 BOE
per day of producing oil and gas properties and an associated 1.4
million BOE of proved plus probable reserves. The proceeds from these
sales will assist in accelerating the development of the Cardium
assets.
A Discussion of Financial and Operational Results
This press release is a review of the operations, current financial position, and outlook for Bonterra Energy Corp. ("Bonterra" or the "Company") and should be read in conjunction with the audited financial statements for the year ended
Forward-looking Information
Certain statements contained in this press release include statements which contain words such as "anticipate", "could", "should", "expect", "seek", "may", "intend", "likely", "will", "believe" and similar expressions, statements relating to matters that are not historical facts, and such statements of our beliefs, intentions and expectations about development, results and events which will or may occur in the future, constitute "forward-looking information" within the meaning of applicable Canadian securities legislation and are based on certain assumptions and analysis made by us derived from our experience and perceptions. Forward-looking information in this press release includes, but is not limited to: expected cash provided by continuing operations; dividends; future capital expenditures, including the amount and nature thereof; oil and natural gas prices and demand; expansion and other development trends of the oil and gas industry; business strategy and outlook; expansion and growth of our business and operations; and maintenance of existing customer, supplier and partner relationships; supply channels; accounting policies; credit risks; and other such matters.
All such forward-looking information is based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate in the circumstances. The risks, uncertainties, and assumptions are difficult to predict and may affect operations, and may include, without limitation: foreign exchange fluctuations; equipment and labour shortages and inflationary costs; general economic conditions; industry conditions; changes in applicable environmental, taxation and other laws and regulations as well as how such laws and regulations are interpreted and enforced; the ability of oil and natural gas companies to raise capital; the effect of weather conditions on operations and facilities; the existence of operating risks; volatility of oil and natural gas prices; oil and gas product supply and demand; risks inherent in the ability to generate sufficient cash flow from operations to meet current and future obligations; increased competition; stock market volatility; opportunities available to or pursued by us; and other factors, many of which are beyond our control. The foregoing factors are not exhaustive and are further discussed herein under the heading Business Prospects, Risks and Outlooks as well as in the Company's Annual Information Form filed on SEDAR at www.sedar.com.
Actual results, performance or achievements could differ materially from those expressed in, or implied by, this forward-looking information and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking information will transpire or occur, or if any of them do so, what benefits will be derived therefrom. Except as required by law, the Company disclaims any intention or obligation to update or revise any forward-looking information, whether as a result of new information, future events or otherwise.
The forward-looking information contained herein is expressly qualified by this cautionary statement.
Production
Three months ended Twelve months ended
DecemberSeptember December December December
31, 2009 30, 2009 31, 2008 31, 2009 31, 2008
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Crude oil and NGLs
(barrels per day) 3,182 3,084 3,055 3,141 3,073
Natural gas
(MCF per day) 10,193 10,881 8,817 11,120 7,637
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Average BOE per day 4,881 4,898 4,525 4,994 4,346
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Barrels of oil equivalent (BOE) 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.
Bonterra's 2009 average production increased 14.9 percent on a per BOE basis over 2008 despite the sale of the Shaunavon property of 210 BOE per day. Crude oil production increased by 2.2 percent while gas production increased by 45.6 percent. The natural gas increase was due primarily to the acquisition of Silverwing Energy Inc. (Silverwing) on
On
In 2009, Bonterra drilled seven Pembina Cardium horizontal wells (5.5 net), eight vertical Pembina Cardium wells (6.9 net) and participated in drilling two natural gas wells (0.4 net). Bonterra recorded a 100 percent success rate with its 2009 drilling program. The Company's first horizontal well was drilled in 2008 and was placed on production in Q1 2009. Bonterra has completed and tied in three (2.1 net) horizontal Cardium oil wells and six (4.9 net) vertical oil wells in 2009. The additional four (3.4 net) horizontal Cardium oil wells and two (2.0 net) vertical wells were placed on production in the first week in Q1 2010.
In November, the Company engaged the services of a second drilling rig and in March a third drilling rig was added and will continue its Pembina Cardium horizontal well drilling program with all rigs until road bans are imposed in
Even with the above mentioned disposition, the company was able to increase its Q4 crude oil production through its 2009 Pembina Cardium horizontal and vertical drill programs. The Company's fourth quarter production in 2009 saw increases in crude oil of 98 barrels per day and a decline in natural gas of 688 MCF per day production over Q309. Exit production for the four (2.73 net) producing Pembina Cardium horizontal wells was approximately 456 (311 net) BOE per day. The Q4 natural gas decline is mainly due to shut in and restricting production of some of the Company's gas wells as well as natural production declines.
Bonterra expects 2010 production to average between 5,700 and 6,000 BOE per day.
Revenue
Three months ended Twelve months ended
DecemberSeptember December December December
(Cdn $) 31, 2009 30, 2009 31, 2008 31, 2009 31, 2008
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Revenue - oil and gas
sales (000s) 24,946 20,965 22,613 85,712 121,730
Average Realized
Prices:
Crude oil and NGLs
(per barrel) 68.40 65.38 58.91 59.82 87.54
Natural gas (per MCF) 4.76 3.13 7.00 4.15 8.21
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Revenue from petroleum and natural gas sales decreased 29.6 percent in 2009 compared to 2008 primarily due to a 31.7 percent drop in crude oil prices and a 49.5 percent drop in natural gas prices. The drop in commodity prices was partially offset with the above mentioned production increases. During 2009 the Company did not enter into any risk management contracts.
Quarter over quarter the Company saw an increase in revenues of
Royalties
Three months ended Twelve months ended
($ 000s) except DecemberSeptember December December December
$ per BOE 31, 2009 30, 2009 31, 2008 31, 2009 31, 2008
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Crown royalties 1,451 1,248 2,337 4,737 13,736
Freehold royalties,
gross overriding
royalties and net
carried interests 892 697 558 2,677 3,479
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Total royalty expense 2,343 1,945 2,895 7,414 17,215
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Percentage of Revenue 9.4 9.3 12.8 8.6 14.1
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$ per BOE 5.22 4.32 6.86 4.07 10.82
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Royalties paid by the Company consist primarily of Crown royalties paid to the Provinces of Alberta, Saskatchewan and British Columbia. The majority of the Company's wells are low productivity wells and therefore have lower Crown royalty rates. The Company's average Crown royalty rate was approximately 5.5 percent (2008 - 10.6 percent) and approximately 3.1 percent (2008 - 2.7 percent) for other royalties. The increase in other royalty rates is due to the new horizontal oil wells being drilled on freehold mineral rights land.
The recently announced new
The fourth quarter royalties have increased
Investment Tax Credit Recovery
As part of the Company's conversion from a trust to a corporation in 2008, Bonterra assumed approximately
Gain on Sale of Property
On
Eagle Rock has since changed its name to Wild Stream Exploration Inc. (Wild Stream) (TSXV: WSX) and consolidated its common shares on a 30:1 basis resulting in Bonterra holding 1,025,640 common shares of Wild Stream.
Production Costs
Three months ended Twelve months ended
($ 000s) except DecemberSeptember December December December
$ per BOE 31, 2009 30, 2009 31, 2008 31, 2009 31, 2008
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Production costs 6,870 6,585 6,859 27,848 25,413
$ per BOE 15.30 15.79 16.25 15.28 15.98
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Total production costs in 2009 have increased by
Total operating costs increased slightly in the fourth quarter of 2009 compared to the prior quarter due primarily to the billing of prior year gas processing charge adjustments in 2009 of approximately
As discussed above, Bonterra'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 Company is continually examining ways to reduce operating costs.
General and Administrative Expense
Three months ended Twelve months ended
($ 000s) except DecemberSeptember December December December
$ per BOE 31, 2009 30, 2009 31, 2008 31, 2009 31, 2008
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G&A Expense 1,623 788 824 4,458 3,401
$ per BOE 3.61 1.75 1.95 2.45 2.14
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General and administrative (G&A) expenses increased 31 percent in 2009 compared to 2008. The Company provides administrative services to Comaplex Minerals Corp. (Comaplex) (TSX: CMF) and Pine Cliff Energy Ltd. (Pine Cliff) (TSXV: PNE), companies that share common directors and management. Please refer to discussion under Related Party Transactions for details.
The Company's significant general and administrative costs are employee compensation; professional services such as legal, engineering and accounting; computer services and bank charges. Employee compensation expense decreased by approximately 7 percent (
Computer services increased by
The quarter over quarter increase of
During the year the Company capitalized
Interest Expense
Three months ended Twelve months ended
($ 000s) except DecemberSeptember December December December
$ per BOE 31, 2009 30, 2009 31, 2008 31, 2009 31, 2008
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Interest Expense 738 815 746 3,294 2,740
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$ per BOE 1.64 1.81 1.77 1.81 1.72
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Bank debt at
The Company has also borrowed
Interest charges increased in 2009 as the average outstanding debt balance (including related party balances) increased by approximately
Quarter over quarter saw a decrease in interest charges due to reduced debt balances resulting from proceeds of the Shaunavon sale being applied to the bank debt.
Effective
The interest rate on the credit facility is calculated as follows:
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Level I Level II Level III Level IV Level V
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Consolidated
Total Funded
Debt(1) to Over Over Over
Consolidated Under 1.0:1 to 1.5:1 to 2.0:1 to Over
Cash flow Ratio 1.0:1 1:5:1 2.0:1 2.5:1 2.5:1
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Canadian Prime
Rate Plus(2) 125 150 175 200 250
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Bankers'
Acceptances Rate
Plus(2) 275 300 325 350 400
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(1) Consolidated total funded debt excludes related party amounts but
includes working capital.
(2) Numbers in table represent basis points.
Consolidated total funded debt to consolidated cash flow ratio shall be adjusted effective as of the first day of the next fiscal quarter following the end of each fiscal quarter, with each such adjustment to be effective until the next such adjustment.
As of
Stock-Based Compensation
Stock-based compensation is a statistically calculated value representing the estimated expense of issuing employee stock options. The Company records a compensation expense over the vesting period based on the fair value of options granted to employees, directors and consultants. The Company issued only 33,000 stock options during 2009 resulting in a reduction of stock-based compensation by
The 33,000 common share options were issued with an exercise price of
Depletion, Depreciation, Accretion and Dry Hole Costs
The Company 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 Company 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 Company's long production life of its wells, the wells generally require replacement of tangible assets more than once during their life time. Most of the Company'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
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
The above calculation requires an estimation of the amount of the Company'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
The Company continues to have relatively low finding and development costs (see discussion under Finding and Development Costs). Based on year end reserves, the Company's average cost of proved reserves is
The Company currently has an estimated reserve life for its proved developed producing reserves of 11.7 (2008 - 12.5) years calculated using the Company's gross reserves (prior to allowance for royalties) based on the third party engineering report dated
Income Taxes
On
The current tax provision of
The Company and its 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
($ 000s) % Amount
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Undepreciated capital costs 20-100 $ 21,671
Eligible capital expenditures 7 7,363
Share issue costs 20 2,973
Canadian oil and gas property expenditures 10 26,282
Canadian development expenditures 30 59,141
Canadian exploration expenditures 100 11,174
SR&ED expenditures 100 80,357
Income tax losses carried forward(1) 100 223,629
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$ 432,590
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(1) Federal income tax losses carried forward expire in the following
years; 2013 - $1,069,000, 2024 - $3,347,000, 2025 - $7,532,000, 2026
- $46,670,000, 2027 - $117,189,000, 2028 - $34,726,000, 2029 -
$13,096,000.
The Company has
The Company also has
Net Earnings
Three months ended Twelve months ended
($ 000s) except DecemberSeptember December December December
$ per share 31, 2009 30, 2009 31, 2008 31, 2009 31, 2008
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Net Earnings 52,136 5,790 10,585 68,563 55,426
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$ per share - Basic 2.88 0.32 0.62 3.81 3.25
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$ per share - Fully
Diluted 2.85 0.32 0.62 3.78 3.23
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Bonterra's net earnings for the year ended
Two significant factors contributing to net earnings were the Company's recordings of the investment tax credit recovery of
Comprehensive Income
Other comprehensive income for 2009 consists of an unrealized gain on investments (including investments in a related party) of
Cash Flow from Operations
Three months ended Twelve months ended
($ 000s) except DecemberSeptember December December December
$ per share 31, 2009 30, 2009 31, 2008 31, 2009 31, 2008
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Cash flow from
operations 13,673 9,350 10,336 38,893 69,570
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$ per share - basic 0.76 0.50 0.59 2.16 4.07
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$ per share - fully
diluted 0.75 0.50 0.59 2.15 4.06
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Cash flow from operations decreased 44 percent year over year, mainly due to decreased commodity prices received in 2009. Fourth quarter cash flow increased by
Cash Netbacks
The following table illustrates the Company's cash netback:
$ per Barrel of Oil Equivalent (BOE) 2009 2008
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Production volumes (BOE) 1,822,628 1,590,666
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Gross production revenue $ 47.04 $ 81.15
Realized gain (loss) on risk management
contracts - (4.62)
Royalties (4.07) (10.82)
Production costs (15.28) (15.98)
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Field netback 27.69 49.73
General and administrative(1) (2.16) (2.14)
Interest and taxes (2.11) (2.00)
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Cash netback $ 23.42 $ 45.59
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The following table illustrates the Company's cash netback for the three
months ended:
December September
$ per Barrel of Oil Equivalent (BOE) 31, 2009 30, 2009
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Production volumes (BOE) 448,892 450,616
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Gross production revenue $ 55.50 $ 47.81
Royalties (5.22) (4.32)
Production costs (15.30) (15.79)
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Field netback 34.98 27.70
General and administrative(1) (2.43) (1.75)
Interest and taxes (1.80) (1.99)
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Cash netback $ 30.75 $ 23.96
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(1) General and administrative costs have been reduced by $532,000
relating to the bonus payment on the gain on sale of property as the
benefit has not been included in the above cash net back calculation.
Finding and Development Costs (F&D Costs)
The Company has been active in its capital development program over the past three years. Over this time period Bonterra has incurred the following F&D and FD&A(3) Costs:
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2009 F&D 2008 F&D 2007 F&D 2009 Three 2008 Three
Costs per Costs per Costs per Year Year
BOE(1)(2) BOE(1)(2) BOE(1)(2) Average Average
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Proved Reserve
Additions $16.23 $7.00 $2.15 $8.46 $11.55
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Proved plus
Probable Reserve
Additions $11.01 $6.82 $2.02 $6.62 $9.02
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2009 2008 2007
FD&A FD&A FD&A 2009 Three 2008 Three
Costs per Costs per Costs per Year Year
BOE BOE BOE Average Average
(1)(2)(3) (1)(2)(3) (1)(2)(3)
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Proved Reserve
Net Additions $13.25 $8.67 $2.74 $8.22 $12.30
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Proved plus
Probable Reserve
Net Additions $8.93 $7.47 $2.68 $6.36 $9.45
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The above figures have been calculated in accordance with National Instrument 51-101 (NI 51-101) where the 2009 F&D Costs equate to the total exploration and development costs incurred by the Company of
(1) Barrels of Oil Equivalent 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.
(3) FD&A costs are net of proceeds of disposal and the FD&A costs per BOE
are based on reserves acquired net of reserves disposed of.
Results from the Company's Cardium oil drilling program continue to be better than anticipated resulting in an increase in the third party engineering reports estimated recoverable reserves from existing wells but also from future development. Continued low decline rates have also resulted in increased reserves due to technical revisions. Both these factors contributed to an overall F&D cost in 2009 of
Related Party Transactions
The Company holds 689,682 (2008 - 689,682) common shares in Comaplex which have a fair market value as of
Comaplex paid a management fee to the Company of
As of
In 2008, in order to facilitate the acquisition of Silverwing, the Company borrowed on a short-term basis
Interest paid on these loans during 2009 and 2008 was
The Company also has a management agreement with Pine Cliff. Pine Cliff has common directors and management with the Company. Pine Cliff trades on the TSX Venture Exchange. Pine Cliff paid a management fee to the Company of
As of
Commitments
The Company has no contractual obligations that last more than a year other than its office lease agreements which are as follows:
($ 000s)
-------------------------
Lease Obligations
-------------------------
Year 1 $ 944
Year 2 932
Year 3 829
Year 4 496
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Total $3,201
-------------------------
Liquidity and Capital Resources
During 2009, Bonterra participated in drilling 17 gross wells (12.8 net) at a total cost of
On
As previously discussed, the Company closed a purchase and sale agreement to divest of a portion of its Shaunavon oil production to Eagle Rock. The proceeds of disposition included cash of
Subsequent to
The government of Alberta announced drilling incentives and royalty reductions in respect of wells drilled after
Bonterra anticipates funding the 2010 capital program from cash flow, the Company's existing line of credit, sale of investments, proceeds from the above mentioned Pinto sale as well as proceeds received on the exercise of employee stock options.
Effective
The following consolidated financial statements and notes to the consolidated financial statements have been provided for further details.
Bonterra Oil & Gas Ltd.
Consolidated Balance Sheets
As at December 31
($ 000s) 2009 2008
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Assets
Current
Restricted term deposit - 20
Accounts receivable (Notes 4 & 15) 14,713 11,753
Crude oil inventory 431 845
Prepaid expenses (Note 4) 3,247 4,222
Future income tax asset (Note 11) 11,889 2,669
Investments (Note 8) 4,462 -
Investment in related party (Note 6) 4,827 2,131
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39,569 21,640
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Restricted cash (Note 7) 812 1,252
Investment tax credit receivable (Note 11) 27,670 -
Future income tax asset (Note 11) 58,265 85,416
Property and Equipment (Note 8)
Petroleum and natural gas properties
and related equipment 255,840 232,685
Accumulated depletion and depreciation (88,169) (75,692)
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Net Property and Equipment $ 167,671 $ 156,993
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$ 293,987 $ 265,301
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Liabilities
Current
Accounts payable and accrued
liabilities (